Oil and Natural Gas Sector: New Source Performance Standards and National Emission 

Standards for Hazardous Air Pollutants Reviews

40 CFR Parts 60 and 63

Response to Public Comments on

Proposed Rule August 23, 2011 (76 FR 52738)

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Sector Policies and Programs Division

Research Triangle Park, NC 27711
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FOREWORD

This document provides the EPA’s responses to public comments on the EPA’s Proposed Oil 

and Natural Gas Sector: New Source Performance Standards and National Emission Standards 

for Hazardous Air Pollutants Reviews. The EPA published a Notice of Proposed Rulemaking in 

the Federal Register on August 23, 2011, at 76 FR 52738. The EPA received comments on this 

proposed rule via mail, e-mail, facsimile, and at three public hearings held in Pittsburgh, 

Pennsylvania, Dallas, Texas and Denver, Colorado in September 2011. Copies of all comments 

submitted and transcripts for the public hearings are available at the EPA Docket Center Public 

Reading Room. Comments, letters, and transcripts of the public hearings are also available 

electronically through http://www.regulations.gov by searching Docket IDs EPA-HQ-OAR-2010-

0505.

This document contains responses to comments on the proposed NSPS (40 CFR part 60, subpart 

OOOO) and changes proposed to the NESHAPs (40 CFR part 63, subparts HH and HHH). Due 

to the size and scope of this rulemaking, the EPA summarized a limited amount of major 

comments in the preamble of the final rule. This document contains a summary of all substantive 

comments provided by commenters extracted from the original letters and public hearing 

transcripts.

For each comment, the Document Control Number (DCN) is provided along with the comment 

summary. 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. In some 

cases the same comment was submitted by two or more commenters through submittal of a form 

letter prepared by an organization, by the commenter incorporating by reference the comments in 

another comment letter, or by the commenter providing identical or similar language 

independently. Rather than repeat these comment excerpts for each commenter, the comment 

excerpt is provided only once. 

Several of the EPA’s responses to comments are provided immediately following each comment 

summary. However, in instances where several commenters raised similar or related issues, the 

EPA has grouped these comments together and provided a single response after the last comment 

summary in the group. In some cases, the EPA provided responses to specific comments or 

groups of similar comments in the preamble to the final rulemaking. Rather than repeating those 

responses in this document, the EPA has referenced the preamble or the appropriate technical 

support document for a description of the analysis included in the final rule. Additionally, the 

EPA does not individually identify each and every commenter who made a certain point in all 

instances, particularly in cases where multiple commenters express essentially identical 

arguments. Although portions of the preamble to the final rule are paraphrased in this document, 

to the extent any ambiguity is introduced by this paraphrasing, the preamble itself remains the 

definitive statement of the rationale for the final rule.

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Table of Contents

1.0 Summary.................................................................................................................................. 1

1.1 Background.......................................................................................................................... 1

1.2 Summary of Significant Changes Since Proposal ............................................................... 2

1.2.1 NSPS (Subpart OOOO) ................................................................................................ 3

1.2.2 NESHAP (Subpart HH and Subpart HHH) .................................................................. 8

1.3 Summary of Impacts of Promulgated Action .................................................................... 18

1.3.1 What are the air impacts?............................................................................................ 18

1.3.2 What are the energy impacts? ..................................................................................... 20

1.3.3 What are the cost impacts? ......................................................................................... 20

1.3.4 What are the economic impacts? ................................................................................ 22

1.3.5 What are the benefits of this final rule? ...................................................................... 22

2.0 Response to Comments Regarding Subpart OOOO .............................................................. 27

2.1 Emission Sources Regulated Under the Proposed Rule .................................................... 27

2.1.1 Gas Well Completions................................................................................................ 27

2.1.2 Pneumatic Controllers................................................................................................. 35

2.1.3 Compressors................................................................................................................ 40

2.1.4 SO2 Emissions from Natural Gas Processing Plants................................................... 44

2.1.5 Other Potential Emission Sources to be Regulated – Produced Water Ponds............ 47

2.2 Well Completions and Recompletions............................................................................... 51

2.2.1 Estimated Number of Wells......................................................................................... 51

2.2.2 Description of Well Completion Process and REC Process....................................... 52

2.2.3 Subcategory 1 Wells (non-exploratory and non-delineation)..................................... 55

2.2.4 Subcategory 2 Wells (exploratory and delineation).................................................... 69

2.2.5 Thresholds for Parameters to Define which Well Completions are Subject to REC 

Requirements ........................................................................................................................ 71

2.2.6 Other Comments......................................................................................................... 75

2.3 Pneumatic Controllers........................................................................................................ 80

2.3.1 Compliance Options and Compliance Schedule......................................................... 80

2.3.2 Proposed Emission Limit for Processing Plants......................................................... 81

2.3.3. Proposed Emission Limit for Production, Transmission and Storage ........................ 81
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2.3.4 Low Bleed Devices..................................................................................................... 82

2.3.5 Other Comments......................................................................................................... 83

2.4 Compressors....................................................................................................................... 85

2.4.1 Applicability ............................................................................................................... 87

2.4.2 Number of Compressor Affected Facilities................................................................ 90

2.4.3 Centrifugal Compressor Wet Seals............................................................................. 92

2.4.4 Reciprocating Compressors – Rod Packing Replacement.......................................... 95

2.5 Storage Vessels................................................................................................................ 104

2.5.1 Number of Storage Vessels....................................................................................... 104

2.5.2 Equipment Costs....................................................................................................... 104

2.5.3 Affected Facilities..................................................................................................... 110

2.5.4 Control Techniques................................................................................................... 127

2.5.5. Other Comments...................................................................................................... 137

2.6 Equipment Leaks ............................................................................................................. 143

2.6.1 Leak Definition ......................................................................................................... 144

2.6.2 Leaker Emission Factors and Emission Estimation Methodology ........................... 148

2.6.3 Control Techniques................................................................................................... 151

2.6.4 Other Comments....................................................................................................... 159

2.7 Innovative Compliance Approaches................................................................................ 169

2.7.1 Registration of Wells and Advance Notice of Completions..................................... 169

2.7.2 Third Party Verification............................................................................................ 170

2.7.3 Provisions for Encouraging Innovative Technology ................................................ 171

2.7.4 Applicability of Title V Permitting Requirements to Non-major Sources............... 173

2.7.5 Other Comments....................................................................................................... 180

2.8 Startup, Shutdown and Malfunction Provisions .............................................................. 181

2.8.1 Affirmative Defense Provisions for Malfunctions.................................................... 195

2.8.2 Other Comments....................................................................................................... 209

2.9 Notification, Recordkeeping and Reporting Requirements for the Proposed NSPS....... 216

2.10 Other Comments............................................................................................................ 221

2.10.1 Use of Data from the Natural Gas STAR Program................................................. 221

2.10.2 VOC Content of Natural Gas.................................................................................. 224
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2.10.3 Assessing Co-benefits from Greenhouse Gas Emission Reductions...................... 225

2.10.4 Harmonization with Other Rules............................................................................ 226

2.10.5 Relationship to 40 CFR 98, Subpart W .................................................................. 229

2.10.6 Proposed Standards Would Apply to Affected Facilities that Commence 

Construction, Reconstruction, or Modification After August 23, 2011 ............................. 231

3.0 Comments Regarding Subpart HH and Subpart HHH ........................................................ 233

3.1 Representativeness and Comprehensiveness of NEI Data Used in Analyses.................. 233

3.2. Previously Unregulated Sources..................................................................................... 234

3.2.1 Legal Authority......................................................................................................... 236

3.2.2 Glycol Dehydrators – 40 CFR subpart HH............................................................... 241

3.2.3 Glycol Dehydrators – 40 CFR subpart HHH............................................................ 245

3.2.4 Other Comments on Glycol Dehydration Units........................................................ 256

3.2.6 Storage Vessels: Previously Unregulated and Regulated Sources ........................... 259

3.2.7 Definition of Associated Equipment......................................................................... 263

3.2.8 Other Comments....................................................................................................... 265

3.3 Risk Assessment .............................................................................................................. 267

3.3.1 General Comments on the Methods Used to Assess Risk ........................................ 267

3.3.2 Uncertainties in the Risk Assessment....................................................................... 280

3.3.3 Actions Taken Based on Risk Results...................................................................... 282

3.3.4 Other Comments....................................................................................................... 286

3.4 Technology Review ......................................................................................................... 288

3.4.1 General Comments on the Technology Review Methodology................................. 288

3.4.2 Actions Taken Based on the Technology Review .................................................... 295

3.5 Other Proposed Actions................................................................................................... 302

3.5.1 Alternative to Use Manufacturer’s Testing Results for Certain Enclosed Combustion 

Control Devices .................................................................................................................. 302

3.5.2 Addition of Definition for Flare................................................................................ 310

3.5.3 Monitoring, Recordkeeping and Reporting .............................................................. 310

3.5.4 Startup, Shutdown and Malfunction ......................................................................... 332

3.5.5 Applicability and Compliance .................................................................................. 361

3.5.6 Other Comments....................................................................................................... 367
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3.6 Miscellaneous Comments on NESHAP Amendments.................................................... 369

4.0 Cost, Environmental, Energy and Economic Impacts......................................................... 372

4.1 Economic Impacts............................................................................................................ 372

4.2 Estimated Benefits........................................................................................................... 386

4.2.1 Estimated Health Benefits......................................................................................... 386

4.2.2 Estimated Climate Co-benefits................................................................................. 392

4.3 Other Comments.............................................................................................................. 403

5.0 Miscellaneous Comments.................................................................................................... 409

5.1 Request for Extension of the Compliance Date............................................................... 416

5.2 Rules are an Attempt to Regulate Methane and Other Greenhouse Gases...................... 417

5.3 Regulation of NOx and other Pollutants........................................................................... 420

List of Appendices

Appendix A. List of Commenters Cited in this RTC Document Submitting Comments To EPA 

Air and Radiation Docket Number EPA-HQ-OAR-2010-0505 Regarding the Oil and Natural 

Gas NSPS and NESHAP Reviews Proposed August 23, 2011 .................................................. A-1

Appendix B. Complete List of Commenters that Submitted Comments to EPA Air and 

Radiation Docket Number EPA-HQ-OAR-2010-0505 Regarding the Oil and Natural Gas NSPS 

and NESHAP Reviews Proposed August 23, 2011 .................................................................... B-1
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Acronyms and Abbreviations

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

AQRVs Air Quality Related Values

BACT Best Available Control Technology

BID Background Information Document

BPD Barrels Per Day

BSER Best System of Emission Reduction

BTEX Benzene, Toluene, Ethylbenzene, 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

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
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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

MOU Memorandum of Understanding

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

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

NEPA National Environmental Policy Act

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

OGI Optical Gas Imaging

OMB Office of Management and Budget

PB–HAP Hazardous air pollutants known to be persistent and bio-accumulative in the 

environment

PFE Potential for Flash Emissions

PM Particulate Matter

PM2.5 Particulate Matter (2.5 microns and less)
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POM Polycyclic Organic Matter

PPM Parts Per Million

PPMV Parts Per Million by Volume

PSD Prevention of Significant Deterioration

PSIA Pounds Per Square Inch Absolute

PSIG Pounds Per Square Inch Gauge

PTE Potential to Emit

QA Quality Assurance

RACT Reasonably Available Control Technology

RBLC RACT/BACT/LAER Clearinghouse

REC Reduced Emissions Completion

REL CalEPA Reference Exposure Level

RFA Regulatory Flexibility Act

RfC Reference Concentration

RfD Reference Dose

RIA Regulatory Impact Analysis

RICE Reciprocating Internal Combustion Engines

RTC Response to Comments

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

SISNOSE Significant Economic Impact on a Substantial Number of Small Entities

S/L/T State, 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 describing the movement 

and transformation of pollutants over time, through a user-defined, bounded 

system that includes both biotic and abiotic compartments
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TSD Technical Support Document

TWA Time Weighted Average

UF Uncertainty Factor

UMRA Unfunded Mandates Reform Act

URE Unit Risk Estimate

VCS Voluntary Consensus Standards

VOC Volatile Organic Compounds

VRU Vapor Recovery Unit
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1.0 Summary

1.1 Background

On January 14, 2009, pursuant to section 304(a)(2) of the Clean Air Act (CAA), WildEarth 

Guardians and the San Juan Citizens Alliance filed a complaint in the Unite States District Court 

for the District of Columbia and alleged that the U.S. Environmental Protection Agency (EPA) 

failed to meet its obligations under CAA section 111(b)(1)(B) for the Crude Oil and Natural Gas 

Production source category and CAA sections 112(d)(6) and 112(f)(2) for the Oil and Natural 

Gas Production and Natural Gas Transmission and Storage major source categories. On February 

5, 2010, the Court entered a consent decree that, as subsequently modified, required 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 17, 2012.

On August 23, 2011, the EPA announced (76 FR 52738) how the Agency proposed to address 

the reviews of the NSPS for volatile organic compounds (VOC) and sulfur dioxide (SO2)

emissions from natural gas processing plants. The EPA proposed to add to the source category 

list any oil and gas operation not covered by the current listing. This action also included 

proposed amendments to the existing NSPS for VOC and SO2 emissions from natural gas 

processing plants and proposed VOC standards for operations not covered by the existing NSPS. 

In addition, this action proposed how the EPA would address the residual risk and technology 

review (RTR) conducted for the oil and natural gas production and natural gas transmission and 

storage national emission standards for hazardous air pollutants (NESHAP). The EPA further 

proposed standards for emission sources within these two source categories that were not then 

addressed, as well as amendments to improve aspects of these NESHAP related to applicability 

and implementation. Finally, the EPA addressed provisions in these NSPS and NESHAP related 

to emissions during periods of startup, shutdown and malfunction (SSM).

Specifically, the EPA proposed revising the NSPS for VOCs from leaking components at 

onshore natural gas processing plants (40 CFR part 60, subpart KKK) and NSPS for SO2

emissions from natural gas processing plants (40 CFR part 60, subpart LLL). The EPA also 

proposed establishing 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, the EPA proposed a new subpart OOOO to regulate VOC emissions 

from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers, and 

storage vessels. The EPA also addressed the residual RTR conducted under section 112 of the 

CAA 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). The EPA proposed revisions to the existing emission limit for glycol dehydration 

unit process vents and leak detection and repair requirements. In addition, pursuant to section 
2

112(d)(2) and (3), the EPA proposed emission limits reflecting maximum achievable control 

technology (MACT) for certain currently uncontrolled emission sources in these source 

categories. This action included proposed modification, and addition of testing and monitoring, 

and related notification, recordkeeping and reporting requirements, as well as other minor 

technical revisions to the NESHAP. This action also proposed revisions to the regulatory 

provisions related to emissions during periods of SSM.

A 90-day period, ending October 24, 2011, was initially provided for the public to submit 

comments regarding the proposed subpart OOOO (40 CFR part 60), and proposed revisions to 

subparts HH and HHH (40 CFR part 63). The comment period was later extended to November 

30, 2011. Approximately 4,400 comment letters were entered into EPA’s Air and Radiation 

docket assigned for this rulemaking (docket number EPA-HQ-OAR-2010-0505). The EPA 

reviewed all of the comment letters entered into the docket and grouped the commenters into two 

general categories. The first category consists of commenters stating only general support or 

opposition to the proposed rulemaking. Commenters supporting the rulemaking frequently 

included statements requesting that the EPA establish the most stringent air emissions standards 

possible and include all existing sources. Commenters opposing the rulemaking frequently stated 

that the proposed rules are overly stringent and burdensome and would negatively impact 

domestic oil and natural gas production. The second category of public commenters are those 

providing comments regarding specific issues and topics related to the rule development and 

proposed rule language for the new subpart OOOO, and revisions to NSPS subparts KKK and 

LLL, and NESHAP subparts HH and HHH.

This document presents a summary of the public comments entered into docket EPA-HQ-OAR2010-0505 regarding specific issues and topics related to the development of the proposed 

subpart OOOO and amendments to subparts KKK and LLL NSPS (40 CFR part 60) and 

amendments to subparts HH and HHH NESHAP (40 CFR part 63) (i.e., comments submitted by 

commenters in the second category) and EPA’s responses to those comments. The EPA assigned 

these comments to specific categories (see Table of Contents) based on an assessment of the 

principal subject of the comment; however, some comments inevitably overlap multiple subject 

areas. Appendix A lists commenters for which the EPA has provided a specific response, either 

in this document or in the final rule preamble. Appendix B identifies all of the commenters that 

submitted comments to the docket. Some of the comment sets were signed or submitted on 

behalf of multiple commenters.

1.2 Summary of Significant Changes Since Proposal

This section describes significant changes made to the proposal that the EPA is now finalizing in 

this rule. These changes result from the EPA’s review of the additional data and information 
3

provided to us and our consideration of the many substantive and thoughtful comments 

submitted on the proposal.

For clarity, we have divided this section into two parts. Section 1.2.1 describes the significant 

changes that have been made to the NSPS (40 CFR part 60, subpart OOOO) since proposal. 

Section 1.2.2 describes the significant changes made to the NESHAP (40 CFR part 63, subparts 

HH and HHH). 

1.2.1 NSPS (Subpart OOOO)

This section will discuss in greater detail the key changes the EPA has made since 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.

We believe 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.

1.2.1.1 Gas Well Affected Facilities

We have revised the requirements for gas well affected facilities since proposal in response to 

comment. The final rule applies to three subcategories of fractured and refractured gas wells for 

which well completion operations are conducted: (1) wildcat (exploratory) and delineation gas 

wells; (2) non-wildcat and non-delineation gas wells for which the reservoir pressure is 

insufficient for a reduced emissions completion (REC) to be performed, as determined by a 

simple calculation involving reservoir pressure, well depth and flow line pressure at the sales 

meter (we refer to these wells as “low pressure gas wells”); and (3) all other fractured and 

refractured gas wells. In the proposed 40 CFR part 60, subpart OOOO, upon promulgation of this 

rule, each well completion or recompletion at a non-exploratory or non-delineation well would 

have had to employ REC in combination with a completion combustion device to control gas not 

suitable for entering the flow line. Because of uncertainties in the supply of equipment and labor 

over the near-term, we are now requiring this work practice standard for completion operations 

begun at subcategory (3) gas wells (non-exploratory and non-delineation wells) on or after 

January 1, 2015. Until this date, flowback emissions must be controlled using a completion 

combustion device unless it is technically infeasible or unsafe to do so. Owners and operators are 

encouraged to use REC when available during this period. Completion operations at subcategory 

(1) gas wells (wildcat and delineation wells) and subcategory (2) gas wells (non-wildcat and nondelineation low pressure gas wells) begun on or after 60 days after the date of promulgation of 

the rule are required to control flowback emissions by using REC with combustion or by routing 
4

emissions to a completion combustion device alone unless it is technically infeasible or unsafe to 

do so. 

The final rule includes a specific modification provision for well completions in lieu of the 

General Provisions in 40 CFR 60.14. For a more detailed explanation, please see section IX.A of 

the final rule preamble. In addition, we have revised the definition of “flowback period” to more 

clearly define when the flowback period begins and ends.

In the proposed rule, all completions at existing wells (i.e., those originally constructed on or 

before August 23, 2011) that are subsequently fractured or refractured were considered to be 

modifications. In the final rule, completions of wells that are refractured on or after the rule’s 

effective date are not considered modified and, as a result, are not affected facilities under the 

NSPS if the completion operation is conducted with the use, immediately upon flowback, of 

emission control techniques required on or after January 1, 2015, for new wells and satisfies 

other requirements.

In the proposed rule, we prescribed specific equipment to accomplish an REC. In the final rule, 

we have removed the required equipment specifications for REC and added operational 

standards that will result in minimizing emissions and maximizing product recovery. In light of 

the comments received, we conclude that it is inappropriate and unnecessary to prohibit the use 

of other equipment that can be used to accomplish an REC, and that the operational standards 

can be achieved using a variety of equipment that can change from well to well.

Initial compliance requirements for gas well affected facilities have also been revised and 

streamlined. Owners and operators are now required to notify the Administrator of the actual 

date of each well completion operation by email no later than 2 days prior to the well completion 

operation, 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. The email must include information that had been part of the 30-day advance 

notification, as described in the proposed rule, including contact information for the owner and 

operator, well identification, geographic coordinates of the well and planned date of the 

beginning of flowback. However, if the owner or operator is subject to State regulations that 

require advance notification of well completions and has met those advance notification 

requirements, then the owner or operator is considered to have met the advance notification 

requirements for gas well completions under the NSPS.

In the final rule, the recordkeeping and reporting requirements for well completions also provide 

for a streamlining option that owners and operators may choose in lieu of the standard annual 

reporting requirements. The standard annual report must include copies of all well completion 

records for each gas well affected facility for which a completion operation was performed 

during the reporting period. The alternative, streamlined annual report for gas well affected 
5

facilities requires submission of a list, with identifying information of all affected gas wells 

completed, electronic or hard copy photographs documenting REC in progress for each well for 

which REC was required and the self-certification required in the standard annual report. The 

operator retains a digital image of each REC in progress. The image must include a digital date 

stamp and geographic coordinates stamp to help link the photograph with the specific well 

completion operation.

1.2.1.2 Centrifugal and Reciprocating Compressor Affected Facilities

In the final rule, we have made changes that impact both reciprocating and centrifugal 

compressor affected facilities in response to comments requesting clarification. Because we are 

not finalizing standards covering them, centrifugal and reciprocating compressors located in the 

transmission, storage and distribution segment are not affected facilities. 

In the proposed rule, all centrifugal compressors would be required to use dry seals. The final 

rule requires that centrifugal compressors with wet seals reduce emissions by 95.0 percent. 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 95.0 percent. Testing, monitoring, 

recordkeeping, reporting and notification requirements associated with the control devices have 

also been added. In the final rule, centrifugal compressors with dry seals are not affected 

facilities. More detailed discussion of this change is presented in section IX.D of the final rule

preamble. 

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 and changing rod packing after 26,000 hours of operation.

1.2.1.3 Pneumatic Controller Affected Facilities

For pneumatic controller affected facilities located in the oil and natural gas production 

segments, we have revised the definition of pneumatic controller affected facility from a single 

pneumatic controller to a single continuous bleed natural gas-driven pneumatic controller with a 

continuous bleed rate greater than 6 scfh for which construction, modification or reconstruction 

commenced after August 23, 2011. At natural gas processing plants, individual continuous bleed 

natural gas-operated pneumatic controllers for which construction, modification or 

reconstruction commenced after August 23, 2011, are affected facilities under this rule. As 

explained further in section IX.C of the final rule preamble, this change provides clarity by more 

specifically defining the pneumatic controllers we intended to regulatein the final rule. In 
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addition, only pneumatic controllers located prior to the point at which the gas enters the 

transmission and storage segment are subject to the NSPS. Because we are not finalizing 

standards covering them, controllers located in the transmission and storage segment are not 

affected facilities. The emission rates we proposed for pneumatic controllers have not changed in 

the final rule.

All new pneumatic controller affected facilities are required, in the final rule, to be tagged with 

the month and year of installation and identification that allows traceability to the records for that 

controller.

In the proposed rule, each pneumatic controller affected facility would have to comply upon 

promulgation. The final rule allows a 1-year phase-in period beginning on the date of 

promulgation before the bleed rate limit is effective for an affected facility. We believe this 

phase-in period is necessary for at least two reasons. First, owners and operators would

demonstrate compliance based on information in the manufacturers’ specification. We have 

concluded that such information is not always included in current manufacturers’ specifications 

and a period of time is required for manufacturers to test their products and modify specifications 

to include the information. Second, we are not aware of any add-on control device that is or can 

be used to reduce VOC emissions from gas-driven pneumatic devices. 

Finally, language in the proposed rule could have been interpreted to meanthat all pneumatic 

controllers installed in any year after the proposal date must be reported each year, rather than 

those installed only during the reporting period. In order to clarify and streamline the 

recordkeeping and reporting requirements associated with pneumatic controllers, we are 

requiring only information concerning those affected facilities constructed, modified or 

reconstructed during the reporting period to be included in the annual report. 

1.2.1.4 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 something that is mobile (such as trucks, railcars, barges or ships) to be subject to 40 

CFR part 60, subpart OOOO if it is intended to be located at a site for at least 180 consecutive 

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 emit 

6 tpy of VOC or more are subject to the NSPS, based on our analysis in the proposed rule 
7

showing that the proposed NSPS is cost effective for storage vessels with that level of VOC 

emissions. In the final rule, for storage vessels constructed, modified or reconstructed at well 

sites with no wells already in production at the time of construction, 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 storage 

vessels constructed, modified or reconstructed at well sites with one or more wells already in 

production at the time of construction, modification or reconstruction, VOC emissions can be 

determined prior to startup. Accordingly, these estimation and installation periods are not 

necessary and, therefore, 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 40 CFR part 60, subpart OOOO and modified 

those requirements, as appropriate for this rule. 

In the proposed rule, each storage vessel required to reduce emissions would have to comply 

upon promulgation. In the final rule, owners or operators are allowed a 1-year phase-in period

beginning on the date of promulgation before the 95.0-percent control requirement is effective. 

We believe this phase-in period is necessary because of initial problems securing control devices 

that are manufacturer-tested and have appropriate documentation for determining control 

efficiency. In addition, we believe that owners or operators will require a period of time to 

establish the need for controls and install them where called for. The 1-year phase-in period will 

also allow owners or operators the necessary time to establish the need for a control device and 

procure and install the equipment.

1.2.1.5 Equipment Leaks Affected Facilities and Sweetening Unit Affected Facilities at Onshore 

Natural Gas Processing Plants

We have revised the identification of affected facilities for equipment leaks at natural gas 

processing plants. We proposed that compressors and equipment (as defined in the rule) located 

at onshore natural gas processing plants were affected facilities. As discussed above, 

compressors (reciprocating and centrifugal) have requirements under 40 CFR part 60, subpart 

OOOO that extend beyond the natural gas processing plant. To remove the duplicative 

requirements for compressors at natural gas processing plants, we have revised the identification 

of affected facility to exclude compressors from the standards that apply to equipment leaks at 

onshore natural gas processing plants.
8

1.2.1.6 Changes to Notification, Recordkeeping and Reporting Requirements

In response to comment expressing concern with the burdens associated with demonstrating and 

monitoring compliance, we have reanalyzed 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 in 40 

CFR 60.7(a)(1), (3) and (4). These requirements relate to notification of construction and initial 

performance testing and are more suited to construction of more traditional facilities (e.g., gas 

processing plants, refineries and chemical plants) rather than the numerous individual pieces of 

apparatus (e.g., individual pneumatic controllers, compressor and storage vessels) that are 

“affected facilities” under the final rule. Specific notification and initial compliance 

demonstration requirements in the final rule make the General Provisions notification 

requirements unnecessary for gas well affected facilities.

As mentioned previously, we have also streamlined the notification, recordkeeping and reporting 

requirements for gas well affected facilities. In place of a written notification of each well 

completion operation 30 days prior to the completion, owners or operators must submit a 

notification no later than 2 days prior to the date of the completion. This notification may be 

submitted by email. To avoid duplicative and potentially conflicting advance notification 

requirements, the final rule provides that owners or operators who are subject to state regulations 

that require advance notification of well completions and have met those notification 

requirements, then the owner or operator is considered to have met the advance notification 

requirements of the NSPS. Additionally, in lieu of the standard annual reporting requirements, 

the final rule allows submission of an annual report for gas well affected facilities that consists

only of a list, with identifying information of all affected gas wells completed, electronic or hard 

copy photographs documenting REC in progress for each well for which REC was required and 

the self-certification required in the standard annual report.

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 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.

1.2.2 NESHAP (Subpart HH and Subpart HHH)

This section discusses the key changes the EPA is making to the NESHAP 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 substantive comments submitted on the proposal.
9

We have retained the same approach and methodology to establishing the standards as described 

at proposal. We have, however, made some changes in response to comments, which are 

described further below. One change resulted in revisions to the MACT emission limits for small 

glycol dehydration units. In addition, based on the comments received, we are not finalizing the 

MACT standard for the subcategory of storage vessels without the PFE, which was a 

subcategory that was left unregulated in the 1999 subpart HH rule. Specifically, based on our 

review of the comments, we believe that we need additional data and information to set an 

emission standard for storage vessels without the PFE, and we intend to collect the additional 

data and propose MACT emission standards under section 112(d)(2) and (3) of the CAA for such 

storage vessels. Finally, we are retaining the 0.9 Mg/yr compliance option for large dehydration 

units. 

1.2.2.1 What are the significant changes since proposal for the Oil and Natural Gas Production 

Facilities (subpart HH) source category?

Under the authority of sections 112(d)(2) and (d)(3) of the CAA, we proposed amendments to 

subpart HH by adding requirements for previously unregulated units; specifically we proposed 

standards for small glycol dehydration units and storage vessels without the PFE. 

In the final amendments for subpart HH, we have revised the proposed MACT standards for 

small glycol dehydration units in response to comments that we did not take into account 

variability in the development of the MACT floor. In our proposal, the MACT standards for 

existing affected sources was a unit-specific BTEX limit of 1.10x10-4g BTEX/scm-ppmv and for 

new affected sources was a BTEX limit of 4.66 x10-6g BTEX/scm-ppmv. In this final rule, we 

accounted for variability by using an upper prediction limit to develop a revised BTEX emission 

limit for existing small glycol dehydration units of 3.28x10-4grams 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 x10-6grams BTEX/scm-ppmv. 

Finally, we are not finalizing MACT standards for storage vessels without the PFE in this rule. 

We received numerous comments expressing concerns with how we established the proposed 

standards for this subcategory. In response to such comments, we have re-evaluated the proposed 

MACT standards and conclude that we need (and intend to gather) addition data on these sources 

in order to analyze and establish MACT emission standards for this subcategory of storage 

vessels under section 112(d)(2) & (3) of the CAA. 

Changes made to amendments proposed under the authority of CAA section 112(f)(2)

We proposed to eliminate the 0.9 Mg/yr benzene compliance option for large glycol dehydration 

units because, in the proposed rule, we estimated that the emissions allowed as the result of this 

compliance option resulted in estimated cancer risks up to 400-in-1-million. We received 
10

multiple comments concerning our proposed risk estimate. After reviewing these comments, we 

discovered that we had significantly overestimated the allowable emissions associated with this 

compliance option. First, for several sources, including the source that we predicted had the 400-

in-1 million MIR, we used an incorrect factor (or multiplier) to scale up actual emissions 

associated with sources that could utilize the compliance option level of 0.9 Mg/yr to allowables. 

We used an incorrect factor due to an inadvertent transcription error in our calculations. Second, 

we learned that the risk assessment supporting the proposed rule erroneously included several 

area sources, which are not subject to subpart HH and thus should not have been included in the 

112(f) risk assessment. After revising the risk assessment to remove area sources, and 

considering the MACT standard promulgated today for small glycol dehydrators pursuant to 

section 112(d)(2) and (d)(3), the MIR for the Oil and Natural Gas Production source category 

based on actual and allowable emissions is 10-in-1 million, compared to the 400-in-1 million1

based on allowable emissions and 40-in-1 million based on actual emissions that were estimated 

in the proposed rule. 

As the result of our revised risk analysis, we have determined that 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. Total estimated cancer incidence from the source category is 0.02 

excess cancer cases per year, or one case in every 50 years. This estimate is unchanged from the 

proposed rule because the incidence from a small number of sources typically does not affect 

total incidence reported to one significant figure. The estimate from the proposed rule of 

maximum chronic non-cancer TOSHI value (0.1) is unchanged, driven by naphthalene emissions 

from fugitive sources. The maximum acute non-cancer hazard quotient value (9, based on the 

benzene REL) is also unchanged from the proposed rule. Although driven by the same pollutant 

that drives the MIR, benzene, the maximum acute hazard quotient value did not change from the 

proposed rule because the source driving the acute value was not identified as an area source 

and, thus, remained in the revised analysis. It is common for the maximum acute hazard quotient 

and cancer MIR not to coincide because the acute value is strongly dependent on short-term 

meteorology and the distance to the facility property boundary, whereas the MIR is dependent on 

long-term meteorology and the distance to census block receptors. There are 13 cases in the 

source category (out of approximately 1000 facilities) where the REL is exceeded by more than a 

factor of two.

 

1 At proposal, we used an incorrect factor (or multiplier) in calculating allowable emissions for 

the source that, at proposal, had an estimated MIR of 400-in-1 million. Since proposal, we have

learned that this source is an area source and thus is not subject to the subpart HH MACT 

standards. As such, we removed this source from our section 112(f) risk analysis. In any event, 

we have determined that even if this area source were to have actual emissions at the 0.9 Mg/yr 

level, its risk would be 3-in-1 million. 
11

Based on the conservative nature of the acute exposure scenario used in the screening assessment 

for this source category, the EPA has judged that, considering all associated uncertainties, the 

potential for effects from acute exposures is low. Screening estimates of acute exposures were 

evaluated for each HAP at the point of highest off-site exposure for each facility (i.e., not just the 

census block centroids) assuming that a person is present at this location at a time when both the 

peak emission rate and worst-case dispersion conditions occur. Although the REL (which 

indicates the level below which adverse effects are not anticipated) is exceeded in this case, we 

believe the potential for acute effects is low for several reasons. The acute modeling scenario is 

worst-case because of the confluence of peak emission rates and worst-case dispersion 

conditions. Also, the generally sparse populations near the facilities with the highest estimated 1-

hour exposures make it less likely that a person would be near the plant to be exposed.

We also conducted a facility-wide risk assessment. The maximum facility-wide risk estimate of 

100-in-1 million is unchanged from the proposed rule. Also unchanged from proposal is the fact 

that the facility-wide risk is driven by emissions from reciprocating internal combustion engines 

(“RICE”) and these engines are not part of the Oil and Natural Gas Production source category. 

In fact, oil and natural gas production operations contribute only about one percent or less to the 

total facility-wide risks. In the last few years, the Agency has revised the MACT standards for 

certain RICE. 75 FR 9648 and 51570. Although it is difficult to discern from the available data 

which types of RICE are driving the facility-wide risk, it is important to note that the 2005 NEI 

data on which we modeled risk did not take into account the recent MACT revisions to the RICE 

rule. Finally, our assessment that the potential for significant human health risks due to 

multipathway exposures or adverse environmental effects is low has not changed since proposal 

(See 76 FR 52774).

Consistent 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 this 

case, because the MIR is well below 100-in-1-million, and because a number of other factors 

indicate relatively low risk concern, including low cancer incidence, low potential for adverse 

environmental effects or human health multi-pathway, and unlikely chronic and acute noncancer 

health impacts, we conclude that the level of risk associated with the Oil and Natural Gas 

Production source category MACT standards (including the small glycol dehydrator MACT 

standard issued today) is acceptable.2 

 

2 We reach the same conclusion even if we do not consider the new MACT for small glycol 

dehydrators in our acceptability determination. Indeed, focusing solely on the standards in the 
12

In making our proposed ample margin of safety determination under CAA section 112(f)(2), we 

subsequently evaluated the risk reductions and costs associated with various emissions control 

options to determine whether we should impose additional standards to reduce risks further. As 

stated above, we made certain revisions to the risk assessment in response to comments and the 

resulting MIR for subpart HH is 10-in-1 million. We have not identified any emission control 

options that would reduce emissions and risk associated with subpart HH sources for glycol 

dehydration units and storage vessels. Our proposed amendment to remove the 0.9 Mg/yr 

compliance option does not affect the risk driver, which is fugitive emissions. As a result, we are 

retaining the 0.9 Mg/yr compliance option in the final rule. We have determined that the risks 

associated with the level of emissions allowed by the MACT standards are driven by fugitive 

emissions (i.e., leaks). 

Since a LDAR program is the typical method for reducing emissions from fugitive sources, we 

considered requiring a LDAR program to reduce risk for this source category. The NEI dataset 

for this source category contains approximately 2,500 emission points that we characterized as 

fugitive. These emission points are located at 639 facilities. The fugitive emissions associated 

with those 639 facilities are 747 tons of HAP.

In evaluating the effectiveness of a LDAR program at these facilities we looked at two different 

LDAR programs – one is a program equivalent to NSPS subpart VV, and the second is a more 

stringent program equivalent to NSPS subpart VVa3. A LDAR program equivalent to subpart 

VV can achieve emission reductions of approximately 39 percent with capital and annual costs 

of $237,700 and $79,419 per facility, respectively. Therefore, such a program for the 639 

facilities would be expected to reduce emissions by 249 tons of HAP with total capital and 

annual costs of $152 million and $50.7 million, respectively. The cost effectiveness would be 

approximately $204,000 per ton of HAP.

A LDAR program equivalent to NSPS subpart VVa can achieve emission reductions of 

approximately 43 percent overall with capital and annual costs of $241,000 and $82,900 per 

facility, respectively. Therefore, an LDAR program for the 639 facilities would be expected to 

 

existing MACT, the level of risk associated with such standards would remain 10-in-1 million, 

and thus our acceptability determination does not change. There is one facility that is a small 

glycol dehydrator that has an MIR of 10-in-1 million. After imposition of the MACT for small 

glycol dehydrators, however, this unit would have an MIR of 7-in-1 million. Also, see memo 

titled Supplemental Facility Information Obtained from Various State/Local Agencies and 

Additional Analysis. March 20, 2012. See Docket.

3

See memorandum titled Costs and Emission Reductions for NSPS subpart VV and VVa LDAR 

programs, dated April 1, 2012.
13

reduce emissions by 275 tons of HAP, with total capital and annual costs of $154 million and 

$53 million, respectively. The cost effectiveness would be approximately $193,000 per ton of 

HAP reduced. These additional control requirements would reduce the MIR for the source 

category from 10 in a million to approximately 7-in-1-million. 

As explained in the proposal, in accordance with the approach established in the Benzene 

NESHAP, we weigh all health risk measures and information considered in the risk acceptability 

determination, along with the costs and economic impacts of emissions controls, technological 

feasibility, uncertainties, and other relevant factors, in making our ample margin of safety 

determination and deciding whether standards are necessary to reduce risks further. Considering 

all of this information, we conclude that the costs of the options analyzed are not reasonable 

considering the emissions reductions and risk reductions potentially achievable with the control 

measures evaluated. Thus, we conclude that the MACT standards in subpart HH (coupled with 

the new MACT standard for small glycol dehydrators) provide an ample margin of safety to 

protect public health and prevent adverse environmental effects. Accordingly, we are re-adopting 

those standards to satisfy the requirements of section 112(f).

Changes made to standards proposed under the authority of CAA section 112(d)(6)

As discussed in detail in the preamble for the proposed rule (76 FR 52784), we conducted a 

technology review for glycol dehydration units, storage vessels, and equipment leaks under the 

authority of 112(d)(6). We assessed developments in practices, processes, and control 

technologies sources for those regulated under the initial NESHAP and determined that it was 

cost effective to lower the leak definition for valves at natural gas processing plants. We did not 

identify developments in practices, processes, and control technologies for glycol dehydration 

units and storage vessels. As a result of this assessment, we proposed revisions to the equipment 

leak requirements in 40 CFR part 63, subpart HH to lower the leak definition for valves to an 

instrument reading of at least 500 ppm. No significant changes since proposal were made to the 

equipment leak standards proposed under the authority of section 112(d)(6) of the CAA4. 

Other Changes to the proposed rule 

We are revising the emission reduction demonstrated using the manufacturers performance test 

from 98.0 percent to 95.0 percent. Specifically, if an owner or operator chooses to install a 

combustion control device that is tested under, and passes, the prescribed manufacturers 

performance test the final rule states that the control device has demonstrated a destruction 

 

4 Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce, U.S. EPA, titled Technology 

Review for the Final Amendments to Standards for the Oil and Natural Gas Production and 

Natural Gas Transmission and Storage Source Categories. April 17, 2012. See Docket.
14

efficiency of 95.0 percent. This change is a result of comments and data provided on the actual 

performance of these devices in the field. 

In the proposed rule, we proposed that the standards apply at all times and removed provisions 

that provided an exemption from the emission standards during SSM. In response to comments 

that the monitoring and reporting provisions related to excursions occurring during SSM events 

that remain in the subpart suggest exemption and therefore should be removed, we are removing 

these provisions in the final rule.

1.2.2.2 What are the significant changes since proposal for the Natural Gas Transmission and 

Storage facilities (subpart HHH) source category?

Changes made to amendments proposed under the authority of CAA sections 112(d)(2) and 

(d)(3)

Under the authority of sections 112(d)(2) and (d)(3) of the CAA, we proposed amendments to 

subpart HHH by adding requirements for previously unregulated units; specifically we proposed 

standards for 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 that we did not take into account variability in 

the development of the MACT floor. We had proposed a unit-specific BTEX emission limit of 

6.42x10-5grams BTEX/scm-ppmv for existing sources and a BTEX limit of 1.10x10-5g 

BTEX/scm-ppmv for new sources. In the final rule, we accounted for variability by using an 

upper prediction limit to develop a revised emission limit of 3.10x10-4g BTEX/scm-ppmv and 

for new affected sources is a BTEX limit of 5.44x10-5grams BTEX/scm-ppmv. The process for 

developing these emissions limitations is documented in this Responses to Comments document 

and a technical memorandum which can be found in the docket.

Changes to amendments proposed under the authority of CAA section 112(f)(2)

We proposed to eliminate the 0.9 Mg/yr benzene compliance option for large glycol dehydration 

unit process vents because, in the proposed rule, we estimated that the emissions allowed as the 

result of this compliance option resulted in estimated cancer risks up to 90-in-1-million. In 

response to comments, we learned that the risk assessment supporting the proposed rule 

erroneously included some sources that have permanently shut down, and several area sources, 

which are not subject to Subpart HHH and thus should not have been included in the 112(f) risk 

assessment. After revising the risk assessment to remove these sources, and considering the 

MACT standards promulgated today pursuant to section 112(d)(2) and (d)(3), the MIR for the 

Natural Gas Transmission and Storage source category based on actual and allowable emissions 
15

is 20-in-1 million, compared to the 90-in-1 million based on allowable emissions and 20-in-1 

million based on actual emissions estimated in the proposed rule. 

As the result of our revised risk analysis, we have determined that approximately 1,100 people 

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

in the proposed rule. Total estimated cancer incidence from the source category is 0.001 excess 

cancer cases per year, or one case in every 1,000 years. This estimate is unchanged from the 

proposed rule because the incidence from a small number of sources typically does not affect 

total incidence reported to one significant figure. The estimate from the proposed rule of 

maximum chronic non-cancer TOSHI value (0.2) is unchanged, driven by benzene emissions 

from fugitive sources. The maximum acute non-cancer hazard quotient value (4, based on the 

benzene REL) changed from the proposed rule; the value in the proposed rule was 5, but was 

associated with an area source that was removed from the risk assessment. There are two cases in 

the source category (out of approximately 300 facilities) where the REL is exceeded by more 

than a factor of two.

Based on the conservative nature of the acute exposure scenario used in the screening assessment 

for this source category, the EPA has judged that, considering all associated uncertainties, the 

potential for effects from acute exposures is low. Screening estimates of acute exposures were 

evaluated for each HAP at the point of highest off-site exposure for each facility (i.e., not just the 

census block centroids) assuming that a person is present at this location at a time when both the 

peak emission rate and worst-case dispersion conditions occur. Although the REL (which 

indicates the level below which adverse effects are not anticipated) is exceeded in this case, we 

believe the potential for acute effects is low for several reasons. The acute modeling scenario is 

worst-case because of the confluence of peak emission rates and worst-case dispersion 

conditions. Also, the generally sparse populations near the facilities with the highest estimated 1-

hour exposures make it less likely that a person would be near the plant to be exposed.

We also conducted a facility-wide risk assessment. The maximum facility-wide risk estimate of 

200-in-1 million is unchanged from the proposed rule. Also unchanged from proposal is the fact 

that the facility-wide risk is driven by emissions from reciprocating internal combustion engines 

(“RICE”) and these engines are not part of the Natural Gas Transmission and Storage source 

category. In fact, natural gas transmission and storage operations contribute only about one 

percent or less to the total facility-wide risks. In the last few years, the Agency has revised the 

MACT standards for certain RICE. (See 75 FR 9648 and 51570). Although it is difficult to 

discern from the available data which types of RICE are driving the facility-wide risk, it is 

important to note that the 2005 NEI data on which we modeled risk did not take into account the 

recent MACT revisions to the RICE rule. Finally, our assessment that the potential for significant 

human health risks due to multipathway exposures or adverse environmental effects is low has 

not changed since proposal (See 76 FR 52774).
16

Consistent 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 Natural Gas Transmission and Storage is acceptable. 

In this case, because the MIR is well below 100-in-1-million, and because a number of other 

factors indicate relatively low risk concern, including low cancer incidence, low potential for 

adverse environmental effects or human health multi-pathway effects, and unlikely chronic and 

acute noncancer health impacts, we conclude that the level of risk associated with the Natural 

Gas Transmission and Storage source category MACT standards (including those MACT 

standards issued today) is acceptable.5

In making our proposed ample margin of safety determination under section 112(f)(2), we 

subsequently evaluated the risk reductions and costs associated with various emissions control 

options to determine whether we should impose additional standards to reduce risks further. As 

stated above, we made certain revisions to the risk assessment in response to comments and the 

resulting MIR for subpart HHH is 20-in-1 million. We have not identified any emission control 

options that would reduce emissions and risk associated with subpart HHH sources for glycol 

dehydration units. Our proposed amendment to remove the 0.9 Mg/yr compliance option does 

not affect the risk driver, which is fugitive emissions. As a result, we are retaining the 0.9 Mg/yr 

compliance option in the final rule. 

We have determined that the risks associated with the level of emissions allowed by the MACT 

standards are driven by fugitive emissions (i.e., leaks). Since a LDAR program is the typical 

method for reducing emissions from fugitive sources, we evaluated the costs and emissions 

reductions associated with requiring such a program to reduce risk for this source category. The 

NEI dataset for the natural gas transmission and storage source category contains approximately 

314 emission points that we characterized as being fugitive in nature. These emission points are 

located at 212 facilities. The fugitive emissions associated with those 212 facilities are 187 tons 

of HAP.

In evaluating the effectiveness of a LDAR program at these facilities we looked at two different 

LDAR programs – one is a program equivalent to NSPS subpart VV, and the second is a more 

 

5 We reach the same conclusion even if we do not consider the new MACT for small glycol 

dehydrators in our acceptability determination. Indeed, focusing solely on the standards in the 

existing MACT, the level of risk associated with such standards would remain 20-in-1 million, 

and thus our acceptability determination would not change. The glycol dehydrators analyzed all 

had risks well below 20-in-1 million.
17

stringent program equivalent to NSPS subpart VVa6. A LDAR program equivalent to subpart 

VV can achieve emission reductions of approximately 51 percent with capital and annual costs 

of $361,800 and $142,600 per facility, respectively. Therefore, such a program for 212 facilities 

would be expected to reduce emissions by 95.4 tons of HAP and have total capital and annual 

costs of $76.7 million and $30.2 million, respectively. The cost effectiveness would be 

approximately $317,000 per ton of HAP. 

A LDAR program equivalent to NSPS subpart VVa can achieve emission reductions of 

approximately 78 percent overall with capital and annual costs of $369,500 and $154,300 per 

facility, respectively. Therefore, a LDAR program for 212 facilities would be expected to reduce 

emissions by 146 tons of HAP with total capital and annual costs of $78.3 million and $32.7 

million, respectively. The cost effectiveness would be approximately $224,000 per ton of HAP. 

These additional control requirements would reduce the MIR from the source category to 

approximately 3-in-1-million for the subpart VVa level of control and 7-in-1-million for the 

subpart VV level of control.

As explained in the proposal, in accordance with the approach established in the Benzene 

NESHAP, we weigh all health risk measures and information considered in the risk acceptability 

determination, along with the costs and economic impacts of emissions controls, technological 

feasibility, uncertainties, and other relevant factors, in making our ample margin of safety 

determination and deciding whether standards are necessary to reduce risks further. Considering 

all of this information, we conclude that the costs of the options analyzed are not reasonable 

considering the emissions reductions and risk reductions potentially achievable with the control 

measures. Thus, we conclude that the MACT standards in subpart HHH (coupled with the new 

MACT standard for small glycol dehydrators) provide an ample margin of safety to protect 

public health and prevent adverse environmental effects. Accordingly, we are re-adopting those 

standards to satisfy the requirements of section 112(f)(2).

Changes made to amendments proposed under the authority of CAA section 112(d)(6)

As discussed in detail in the preamble for the proposed rule (76 FR 52784), we conducted a 

technology review for glycol dehydration units under the authority of 112(d)(6). We did not 

identify developments in practices, processes, and control technologies for glycol dehydration 

units. As a result of this assessment, we did not propose amendments to 40 CFR part 63, subpart 

HHH. We have not made any changes since proposal under the authority of section 112(d)(6)7. 

 

6

See memorandum titled Costs and Emission Reductions for NSPS subpart VV and VVa LDAR 

programs, dated April 1, 2012.

7 Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce, U.S. EPA, titled Technology 

Review for the Final Amendments to Standards for the Oil and Natural Gas Production and 

Natural Gas Transmission and Storage Source Categories. April 17, 2012. See Docket.
18

Further discussion on our technology review analysis can be found in section X.C of the final 

rule preamble, and in responses to comments in this document.

Other changes to the proposed rule

We are revising the emission reduction demonstrated using the manufacturers performance test 

from 98.0 percent to 95.0 percent. Specifically, if an owner or operator chooses to install a

combustion control device that is tested under, and passes, the prescribed manufacturers 

performance test the final rule states that the control device has demonstrated a destruction 

efficiency of 95.0 percent. This change is a result of comments and data provided on the actual 

performance of these devices in the field. 

In the proposed rule, we proposed that the standards apply at all times and removed provisions 

that provided an exemption from the emission standards during SSM. In response to comments

that the monitoring and reporting provisions related to excursions occurring during SSM events 

that remain in the subpart suggest exemption and therefore should be removed, we are removing 

these provisions in the final rule.

1.3 Summary of Impacts of Promulgated Action

1.3.1 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 population in 2008. Under the finalized 

limits for glycol dehydration units, we have estimated that the HAP emissions reductions will be 

670 tons 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. 

The primary baseline used for the impacts analysis of our NSPS for completions of hydraulically 

fractured natural gas wells takes into account RECs conducted pursuant to state regulations 

covering these operations and estimates of RECs performed voluntarily. To account for RECs 

performed in regulated states, the EPA subsumed emissions reductions and compliance costs in 

states where these completion-related emissions are already controlled into the baseline.

Additionally, based on public comments and reports to the EPA's Natural Gas STAR program, 
19

the EPA recognizes that some producers conduct well completions using REC techniques 

voluntarily for economic and/or environmental objectives as a normal part of business. To 

account for emissions reductions and costs arising from voluntary implementation of pollution 

controls the EPA used information on total emission reductions reported to the EPA by partners 

of the EPA Natural Gas STAR. This estimate of this voluntary REC activity in the absence of 

regulation is also included in the baseline.8 More detailed discussion on the derivation of the 

baseline is presented in a technical memorandum in the docket, as well as in the RIA. 

Additionally, in the RIA, we provide summary-level estimates of emissions reductions and 

engineering compliance costs for a case where no voluntary RECs are assumed to occur. This 

alternative case is presented in order to show impacts if conditions were such that RECs were no 

longer performed on a voluntary basis, but rather were compelled by the regulation, and serves in 

part to capture the inherent uncertainty in projecting voluntary activity into the future. As such, 

this alternative case establishes the full universe of emissions reductions that are guaranteed by 

this NSPS (those that are required to occur under the rule, including those that would likely 

occur voluntarily). While the primary baseline may better represent actual costs (and emissions 

reductions) beyond those already expected under business as usual, the alternative case better 

captures the full amount of emissions reductions where the NSPS acts as a backstop to ensure 

that emission reduction practices occur (practices covered by this rule).

Under the final NSPS, we have estimated that the emissions reductions to be about 190,000 tons 

VOC affected facilities subject to the NSPS. The NSPS is also expected to concurrently reduce 

1.0 million tons methane and 11,000 tons HAP. We estimate that direct reductions in HAP, 

methane and VOC for the final rules combined total about 12,000 tons, 1.0 million tons and 

190,000 tons, respectively. If voluntary action is not deducted from the NSPS baseline, the 

emissions reductions achieved by the final NSPS in HAP, methane and VOC are estimated at 

about 19,000 tons, 1.7 million tons and 290,000 tons, 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 selected 

data sets. We reviewed all information received and have decided to retain the data set and the 

 

8 Voluntary short-term actions (such as REC) are challenging to capture accurately in a prospective analysis, as such 

reductions are not guaranteed to continue. However, Natural Gas STAR represents a nearly 20 year voluntary 

initiative with participation from 124 natural gas companies operating in the U.S., including 28 producers, over a 

wide historical range of natural gas prices. This unique program and dataset, the significant impact of voluntary 

REC on the projected cost and emissions reductions (due to significant REC activity), and the fact that RECs can 

actually increase natural gas recovered from natural gas wells (offering a clear incentive to continue the practice), 

led the Agency to conclude that it was appropriate to estimate these particular voluntary actions in the baseline for 

this rule.
20

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.

1.3.2 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 $11 million (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 non-renewable energy resources.

1.3.3 What are the cost impacts?

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 

$2.6 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 $140,000. 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 $3.3 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 $180,000. 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 $25 million in 

2008 dollars. The total estimated net annual cost to industry to comply with the final NSPS is 

estimated to be approximately $170 million in 2008 dollars. This annual cost estimate includes: 

(1) The cost of capital, (2) operating and maintenance costs and (3) the cost of MIRR. This 
21

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 43 million Mcf (43 billion cubic feet) of natural gas and 160,000 barrels of condensate are 

estimated to be recovered by control requirements in 2015. Using the price assumptions, the 

estimated revenues from natural gas and condensate recovery are approximately $180 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 to be about $15 million. Totals may not sum due to independent rounding.

If voluntary action is not deducted from the baseline, capital costs for the NSPS are estimated at 

$25 million, and annualized costs without revenues from product recovery for the NSPS are 

estimated at $330 million. In this scenario, given the assumptions about product prices, estimated 

revenues from product recovery are $350 million, yielding an estimated cost of savings of about 

$22 million.

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 cost savings for the final NSPS are estimated at about $24 million. 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 

$3.66/Mcf. A $1/Mcf change in the wellhead natural gas price leads to a $43 million change in 

the annualized engineering costs of the final NSPS. Consequently, annualized engineering costs 

estimates would increase to about $29 million under a $3/Mcf price or decrease to about -$58 

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.
22

1.3.4 What are the economic impacts?

The analysis of energy system impacts EPA performed using the United States Department of 

Energy’s (DOE) National Energy Modeling System (NEMS) shows that domestic natural gas 

production is not likely to change in 2015 as a result of the final rules, the year used in the RIA 

to analyze impacts. Average natural gas prices are also not estimated to change in response to the 

final rules. Domestic crude oil production is not expected to change, while average crude oil 

prices are estimated to decrease slightly (about $0.01/barrel or about 0.01 percent at the wellhead 

for onshore production in the lower 48 states). All prices are in 2008 dollars. The NEMS-based 

analysis estimates that in the year of analysis, 2015, net imports of natural gas and crude oil will 

not change.

1.3.5 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 12,000 tons of HAP, 190,000 tons 

of VOC (a precursor to both PM2.5 and ozone formation) and 1.0 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 currently available.9In addition to health 

improvements, there will be improvements in visibility effects, ecosystem effects and climate 

effects, as well as additional product recovery.

 

9

Previous studies have estimated the monetized benefits-per-ton of reducing VOC emissions associated with the 

effect that those emissions have on ambient PM2.5 levels and the health effects associated with PM2.5 exposure (Fann, 

Fulcher, and Hubbell, 2009). While these ranges of benefit-per-ton estimates provide useful context for the breakeven analysis, the geographic distribution of VOC emissions from the oil and gas sector are not consistent with 

emissions modeled in Fann, Fulcher, and Hubbell (2009). In addition, the benefit-per-ton estimates for VOC 

emission reductions in that study are derived from total VOC emissions across all sectors. Coupled with the larger 

uncertainties about the relationship between VOC emissions and PM2.5 and the highly localized nature of air quality 

responses associated with HAP and VOC reductions, these factors lead us to conclude that the available VOC 

benefit-per-ton estimates are not appropriate to calculate monetized benefits of these rules, even as a bounding 

exercise. 
23

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, 2006

10 and U.S. EPA, 201011), 

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

restricted activity days and respiratory symptoms, as well as visibility impairment.12 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.13 

In addition to the improvements in air quality and resulting benefits to human health and nonclimate 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 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 

 

10 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>.

11 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>.

12 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>.

13 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.
24

to United States anthropogenic methane emissions.14 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 1.0 million short tons or 

about 19 million metric tons CO2e. After considering the secondary impacts of this rule as 

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 18 million metric tons CO2e. The methane reductions represent about 7 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 sector-level emissions in 2015 for this rulemaking. These 

emission reductions equate to the climate benefits of taking approximately 4 million typical 

passenger cars off the road or eliminating electricity use from about 2 million typical homes each 

year.15

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 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 

 

14 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.

15 U.S. EPA. Greenhouse Gas Equivalency Calculator available at: http://www.epa.gov/cleanenergy/energyresources/calculator.html, accessed 04/09/12.
25

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 12866.

16 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 $100 million to approximately $1.3 billion; the mean 

social cost of carbon at the 3-percent discount rate results in an estimate of about $440 million in 

2015.17

These co-benefits equate to a range of approximately $110 to $1,400 per short ton of methane 

reduced, depending upon the discount rate assumed with a per ton estimate of $480 at the 3-

percent discount rate. 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 cobenefits 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.18 This conclusion is reached using the 100-year GWP for 

methane of 25 as put forth in the IPCC Fourth Assessment Report (AR 4), as opposed to the 

lower value of 21 used in this analysis. Using the higher GWP estimate of 25 would increase 

these reported methane climate co-benefit estimates by about 19 percent. Although the IPCC 

Assessment Report (AR4) suggested a GWP of 25 for methane, the EPA has used the GWP of 

21 from the IPCC Second Assessment Report to estimate the methane climate co-benefits for this 

oil and gas rule. 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, 

 

16 Interagency Working Group on Social Cost of Carbon (IWGSC). 2010. Technical Support Document: Social Cost 

of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA-HQ-OAR-2009-0472-

114577. http://www.epa.gov/otaq/climate/regulations/scc-tsd.pdf, accessed 02/12/12.

17 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.

18 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.
26

and with the US GHG Reporting program. See the Regulatory Impact Analysis for further 

details. 

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 $5,200 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 benefit-cost comparison. If we assume 

the health benefits from HAP emission reductions are zero, the VOC emissions would need to be 

valued at $2,900 per ton or the methane emissions would need to be valued at $8,300 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),19 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.

 

19 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.
27

2.0 Response to Comments Regarding Subpart OOOO

2.1 Emission Sources Regulated Under the Proposed Rule

2.1.1 Gas Well Completions

Comment: One commenter (4264) points out an unintentional consequence of defining 

temporary/construction type activities as affected facilities is that recent completions since the 

proposal date of August 23, 2011, appear to have retroactive compliance obligations. The EPA 

has said that this was not its intent; however, the final rule needs to establish that 

owners/operators have at least 60 days after the publication of the final rule to comply with the 

completion requirements.

 

Response: Under section 111(e) of the CAA, it is unlawful to operate a new source (including a 

modified source) in violation of any applicable NSPS after the effective date of the standard. 

Compliance is not required for well completion activities conducted prior to the effective date of 

this final rule.

See section IX.A and B of the final rule preamble for further discussion.

Comment: One commenter (4241) agrees with the EPA that a well completed after the proposal 

date of the NSPS would be subject to the standards. However, a well completed before the 

proposal date of the NSPS should not be subject to the standards, even if such a well is later 

refractured.

Response: See section IX.A of the final rule preamble.

Comment: One commenter (4208) recommends that the application of capital expenditure 

requirements for modifications be removed from the rule. This will ensure that all recompletions 

and refracturings will qualify as modifications. The commenter points out that a modification 

occurs when a company spends more than 10 percent of the cost of a new well to recomplete a 

fractured or refracture an existing gas well; then the modification is subject to NSPS. This 

proposed capital expenditure test will be difficult to implement and enforce because: companies 

will not hire an accountant and/or attorney to determine which recompletions or refracturings are 

subject to the rule; permitting agencies will not have access to company accounting information 

prior to the activity; and enforcement authorities will not issue formal information requests 

unless they have reason to believe that a violation has occurred. The ratio of recompletion or 

refracturing costs to initial capital expenditures is not an indicator of the potential environmental 

harm. The commenter suggests using a size threshold (number of barrels of oil or standard cubic 

feet of gas per year) as an applicability threshold instead of using the capital expenditure test.
28

Response: See section IX.A of the final rule preamble.

Comment: One commenter (4228) states that well completion flowbacks are temporary 

emission sources from portable equipment and should be exempt from subpart OOOO. 

Response: The commenter is incorrect that the emissions are generated by any portable

equipment used in well completions. As explained in the preamble to the proposed rule, the VOC 

emissions originate from below the ground and are vented to the atmosphere during flowback of 

a hydraulically fractured gas well. With respect to the comment on the temporary nature of the 

emissions, see section IX.A of the final rule preamble.

Comment: A couple of commenters (4228, 4266) point out that NSPS are used to regulate 

emissions from normal operation of affected facilities. According to the commenters, a well 

completion, recompletion, or workover and associated feedback are not part of normal operation; 

they are construction and maintenance activities that employ portable equipment and typically 

remain at the well site for a small number of days. The commenters state that they are temporary 

and should not be subject to NSPS. A commenter (4266) challenges the legality of this regulation 

by stating that a well completion is not part of the normal operation of a well, in that completion 

activities do not continuously occur as a well is producing or, for that matter, are not repeated 

more than once or twice over the life of a well (a life that typically spans years and often spans 

decades). Instead, the commenter asserts that a well completion is a construction related activity 

that must be accomplished for a well to begin producing and thereafter engage in normal 

operations. Additionally, the commenter (4266) states that the agency did not explain why it has 

reversed the longstanding practice under section 111 of the CAA of regulating only emissions 

from normal operation of affected facilities and excluding construction-related emissions from 

regulation. According to the commenter, regulating construction-related emissions is a 

significant substantive departure in the Agency’s prior interpretation and implementation of 

section 111 of the CAA. The commenter asserts that the EPA’s failure to explain how this 

turnaround is justified and to present the legal basis for regulating non-routine emissions is 

arbitrary and capricious.

Response: See section IX.A of the final rule preamble.

Comment: One commenter (4228) points out that there are conflicting definitions between the 

proposed rule and longstanding, conventional definitions for modification. The commenter 

asserts that the proposed §60.5430 definition contradicts what is defined in §60.2 and §60.14 of 

the General Provisions. Furthermore, the commenter notes that hydraulic fracturing and 

refracturing activities should be subjected to a test that evaluated whether a VOC emissions 

increase has occurred as outlined in the historical NSPS approach. The commenter recommends 
29

that the General Provisions definition of modification be retained for well completion operation 

flowbacks. 

Response: See section IX.A of the final rule preamble.

Comment: One commenter (4228) urges the EPA to publish in the final rule detailed guidance, 

examples, and criteria for each affected facility or equipment to identify what individual actions 

will trigger NSPS applicability to avoid conflicts with historical approaches used previously. 

Response: The EPA has clarified in the final rule the actions that trigger the applicability of the 

NSPS for well completions. See section IX.B of the final rule preamble.

Comment: One commenter (4266) requests explanation why the EPA has reversed a decadeslong practice under CAA section 111 of regulating only emissions from normal operation of 

affected facilities and expressly excluding construction-related emissions from regulation. 

According to the commenter, the proposal to regulate construction-related emissions is a 

significant substantive departure in the Agency’s prior interpretation and implementation of 

CAA section 111. The commenter believes that a failure to explain why this departure is justified 

and the failure to present the legal basis for regulating non-routine emissions is arbitrary and 

capricious and plainly violates the EPA’s obligation to clearly set forth “the major legal 

interpretations and policy considerations underlying the proposed rule.” CAA section

307(d)(3)(C). Commenter 4266 adds that the EPA should remove the requirements for REC from 

the proposed regulation and suggests that, if the EPA chooses to proceed in regulating flowback 

immediately following hydraulic fracturing stimulation, the EPA should repropose the 

requirements and include sufficient justification for their departure from not regulating 

construction-related emissions and present the legal basis for regulating non-routine emissions 

under CAA section 111.

One commenter (4281) contends that the EPA’s decision to regulate emissions from well 

completions and recompletions is unprecedented, and the EPA has not provided any legal basis 

for regulating construction-related activities (such as flowback immediately following hydraulic 

fracturing stimulations during completion of a new well). Therefore, the commenter recommends 

that the EPA remove the REC requirements from the proposed rule. According to the 

commenter, to the extent that a producing well must be “recompleted,” this activity constitutes 

maintenance of the well because it is needed to assure the ongoing proper operation and suitable 

productivity of the well. Commenter 4266 argues that to date, the EPA has not sought to impose 

CAA section 111 emissions limitations or standards on construction or maintenance activities at 

affected facilities and that the EPA is not authorized to list or regulate flow back immediately 

following hydraulic fracturing stimulation at gas wellhead facilities onshore under CAA section

111.
30

Response: See section IX.B of the final rule preamble.

Comment: One commenter (4241) supports the EPA’s decision not to propose standards for oil 

and conventional natural gas wells and agrees with the EPA’s conclusion that control of VOCs at 

these types of wells is not cost effective.

Response: The EPA confirms that subpart OOOO does not include standards for oil and 

conventional natural gas wells that are not hydraulically fractured. 

Comment: Several commenters (4159, 4177, 4220, 4273) request that the Agency clarify in the 

final rule that only completions or recompletions that occur within 10 days of a fracture or 

refracture are included as modifications. One commenter (4177) asserts that the EPA did not 

provide a definition for a well completion “with” hydraulic fracturing in the proposed rule nor 

did the agency explain the timeframe for determining if a well completion that occurs any time 

after a hydraulic fracture or refracture is considered a completion activity subject to the rule. The

commenter also argues that if the EPA intended that any completion activities after an initial 

fracture or refracture would be modifications subject to subpart OOOO, then the agency has not 

provided proper notice of that to the public. Another commenter (4266) points out that §60.5375 

does not limit the applicability to the flowback immediately following the hydraulic fracturing. 

One commenter (4184) adds that the proposal did not specify any limitation on the amount or 

timeframe for flaring of vented gas for exploratory and delineation wells where gathering lines 

are unavailable.

One commenter (4228) asks that the EPA clarify in the proposed rule when a well completion 

flowback ends and that requirements to control emissions (§60.5375(a)) end when the well 

completion is finished. The commenter notes that a well completion flowback ends when 

produced gas is no longer passing through well completion equipment or vented directly to 

atmosphere or a flare, and the produced gas quality is such that it can be directed from the 

wellhead to a sales pipeline.

One commenter (4266) states that there is no time limit placed on “following” hydraulic 

fracturing or refracturing such that, as written, once a well has been hydraulically fractured, any 

subsequent well work could be subject to the REC requirements. 

The commenter (4266) notes that §60.5375in the proposed rule states that “for each well 

completion operation with hydraulic fracturing” the operational procedures of REC applies. 

However, the commenter further notes, as with §60.5365, there is no time limit placed on “with 

hydraulic fracturing or refracturing” and could be interpreted that any subsequent well work 
31

could be subject to REC. Also, the commenter asserts it does not limit the applicability to the 

flowback immediately following hydraulic fracturing.

One commenter (4135) states that fracturing operations are only a small part of the completion 

process, and flowback may occur at various times throughout the completion and expresses that 

it is unclear whether controls are required for all flowback operations that occur during the entire 

completion, or if the requirements are only applicable to the flowback operations after the 

fracturing process. The commenter requests clarification. 

One commenter (4375) requests that the EPA close a significant loophole by requiring nonsalable quality gas to go into the gas gathering lines within the same amount of time. This 

commenter further asserts that a limit on putting salable quality gas into pipelines should be 

required.

Response: Regarding the condition when the well completion flowback is deemed to have 

ended, the end of completion/flowback is based on having continuous flow to the flow line or a 

storage vessel for collection, or the well is shut in. This clarification also addresses the issue 

raised by commenters about the limitation on the amount or timeframe for flaring of vented gas 

for exploratory and delineation wells where flow lines are unavailable and on the limiting the 

amount of gas that may be combusted, since the flowback is deemed to end when the well is shut 

in.

Comment: One commenter (4231) requests that the definition of gas well be modified to be 

each respective state’s in-house definition of gas well. The commenter states that by doing this, 

the EPA would eliminate any confusion associated with having to apply different criteria (NSPS 

versus state regulations) for how to define a well-type in assessing the applicability of the rule. 

Another commenter (4241) points out numerous inconsistencies in definitions between subpart 

W of the GHG reporting rule and the proposed rule. First, the commenter states the definition of 

wellhead in the NSPS does not include other equipment at the well site while the MRR definition 

does. Second, the commenter states that the proposed rule does not define well workover but 

asserts this term is used in the definition of well completion operation. The commenter asks the 

EPA to add the definition of well workover from subpart W of the GHG reporting rule to the 

NSPS rule. Third, the commenter asserts that the proposed rule does not include an explanation 

of what is meant by “commencement of construction” for a wellhead facility.

Two commenters (4246, 4266) express that the definition of crude oil found in the proposed rule 

conflicts with the definition used in the subpart W of the GHG reporting rule, the EIA, and the 

definition recognized by most States. The commenters assert the API gravity for a well is not 

known at the time a well is completed; therefore, the definition of crude oil should not contain an 
32

API gravity. Both commenters recommend the EPA use the definition of crude oil from the EIA

and have provided that definition.

Response: With respect to using each State’s gas well definitions, the EPA believes this would 

cause undue confusion and may lead to inconsistencies in the affected source from state to state. 

Subpart W under the Greenhouse Gas Mandatory Reporting Rule and this rule each have 

different objectives. Subpart W is a reporting rule where operators supply activity factors to 

inform the EPA about the oil and gas industry. Subpart OOOO prescribe work practices 

requirements that must be followed for well completions operations following hydraulic 

fracturing. Given the different objectives of each action, the two rules sometimes use different 

definitions and nomenclature and one cannot be used for the other. However, in response to 

comment, we have made revision and clarification in the final rule to address the commenters’ 

concern with confusion and clarity of the terms. Specifically, for the reasons stated in the 

preamble to the final rule, we have included in the final rule a special provision defining 

modification as it relates to well completion operations covered by this NSPS. The final rule 

also does not include the term “workover.”

Comment: One commenter (4241) states that the EPA’s definition of REC in the NSPS is 

inconsistent with the proposed requirements, which include the option to utilize a pit flare under 

specific conditions.

Response: The EPA clarifies that the rule text explains the requirement for control of VOC 

during flowback of affected facilities, which is an operational standard. The operational standard 

requires a combination of gas capture and combustion, with provisions to allow for vents as 

stated within the rule text. The EPA clarifies that the operational standard is therefore inclusive 

of the REC activity as well as other requirements, so the REC definition does not need to be 

revised based on this comment.

Comment: One commenter (4263) requests that §60.5375(a)(1) be revised to provide for routing 

hydrocarbon liquids recovered during flowback operations to tanks other than “storage vessels,” 

as defined in §60.5430. The commenter asserts there are two reasons for this: (1) liquids are not 

“vented” and (2) portable tanks are used to receive flowback liquids during hydraulic fracturing 

well completion operations. In addition, the commenter notes that these temporary portable tanks 

are not designed to meet the standards for “storage vessels” in §60.669. A commenter (4266) 

requests that the rule should not require routing liquids to a storage vessel since sometimes 

flowback contains sands and other injection fluids that can damage storage vessels and make the 

condensate not salable; therefore, some of the flowback may get sent to a pit versus a storage 

vessel. The commenter (4266) adds that the ability to flow back to a pit should be allowed. One

commenter (4191) requests that the EPA include fracturing or refracturing of a well as a 

modification to the on-site storage vessel and the resulting emissions increases at the storage 
33

vessel should be regulated under the “modified” storage vessel provisions. The commenter 

believes that any increase in emissions to the on-site storage vessel resulting from fracturing, 

refracturing, or stimulation is a modification to the storage vessel. The commenter argues that 

increases in well emissions after fracturing or refracturing activities are emitted from the storage 

vessel.

Response: In response to comments on storage vessels at the wellsite, please see section V.D of 

the final rule preamble for further information on the storage vessel affected facility. With regard 

to designating any storage vessel as modified when the wellhead facility is modified, the final 

rule states that modifications to the gas well affected facility do not affect the modification status 

of other equipment, process units, storage vessels, compressors, or pneumatic controllers located 

at the well site. 

We disagree that the final rule should allow a portion of the flowback to be routed to an 

impoundment. Liquids that would be directed to the impoundment in addition to solid materials 

may contain significant amounts of VOCs which would likely be emitted from the impoundment. 

However, we have modified the final rule to give additional flexibility in how liquids are 

handled. In addition to routing liquids to a storage tank, the owner or operator may re-inject the 

liquids into the well or another well.

Comment: One commenter (2803) strongly supports the proposed rule as it attempts to address 

emissions from oil and gas operations but strongly urges the agency to regulate all gas wells, 

existing and future. The commenter states that many gas wells are installed as close as 200 feet 

from residential homes and all gas wells need to have capture and filtration devices installed to 

protect these residents.

Response: The EPA appreciates the commenter’s support for the rule and concern with existing 

sources; however, this rulemaking relates to EPA’s review and revision of two oil and gas new 

source performance standards, which apply to new and modified affected facilities. However, 

EPA notes that subpart OOOO covers certain uncontrolled completion operations of existing 

wells following refracturing. Please see section IX.A.1 of the preamble for a detailed 

explanation.

Comment: One commenter (3562) urges the agency to expand the regulated sources to include 

well completions where pressurized gases (such as nitrogen) are used for fracturing. The 

commenter is concerned that the definition in the proposed rule for hydraulic fracturing has 

omitted wells that are fractured using high pressure gases (which also result in a flowback period 

and may have similar emission profiles to wells fractured with pressurized liquids). The 

commenter also feels that the rule should address control or minimization of emissions during 

backflow period and alternatives to venting emissions to the atmosphere when safety hazards or 
34

other conditions prohibit flaring. One commenter (4236) requests that the EPA establish 

exemptions for operations where certain conditions exist (e.g. when air, nitrogen or carbon 

dioxide are principally involved in the process to extract natural gas or when the collection 

infrastructure is not in place). Another commenter (4240) takes issue with the definition of 

“hydraulic fracturing” with respect to specifying the material introduced into the well and 

implores the EPA to modify this definition to read as follows: “the process of directing 

pressurized substances, which may contain foam, gases, water, hydrocarbons, proppant, and any 

added chemicals, into a well whose casing is perforated, allowing these substances to leave the 

well bore.” 

Response: The final rule applies to well completions following fracturing with fracture fluids 

such as nitrogen or carbon dioxide or other vapors. The EPA disagrees that such operations 

would be exempt. The VOC control requirement is by means of gas capture through gas capture

in combination with combustion, and the EPA expects that the combustion option will be 

necessary for segments of the flowback when the vapor phase fracture fluid results in an overall 

gas composition that is not suitable for capture into the gathering line. Regarding the suggested 

definition that expands the type of fracture fluids that are possible, the EPA clarifies that 

hydraulic fracture may entail a variety of fracture fluids that may be liquid phase, gas phase, or a 

combination of both, in addition to the proppant used during the hydraulic fracture.

Comment: One commenter (4217) requests specific language be added to the final rule to 

exempt the first 48 hours of the completion flowback from REC or control requirements. The 

commenter asserts that during this time, the flowback stream is often very low in VOC content 

and/or is extremely high in inert gases preventing combustion.

Response: The EPA clarifies that the flowback begins when hydraulic fracture material begins 

flowing out of the well. The EPA acknowledges that the initial flowback may be mostly fracture 

fluid for a period of time, but the EPA does not have sufficient information to determine that the 

commenter's requested 48 hour initial period is representative of the industry nationally and 

therefore cannot specify a time period. As a result, the rule enables the overall objective of 

minimizing VOC emissions and maximizing VOC control via recovery, though VOC control is 

also accomplished by the combustion provision within the operational standard.

Comment: One commenter (4266) suggests that RECs only apply to onshore facilities. The 

commenter concludes that it did not appear that the EPA assessed the feasibility and cost for 

doing RECs offshore based on the TSD and the preamble for the proposed rule. The commenter 

states that without a pipeline or space for the specified REC equipment, it is not feasible to do 

RECs offshore. Also, according to the commenter, many offshore rigs are foreign and will not be 

designed to achieve U.S. regulatory requirements. Therefore, the commenter requests that RECs 

only apply to onshore facilities and provides suggested rule text.
35

Response: The EPA clarifies that the rule provisions for VOC control following a hydraulic 

fracture applies to onshore facilities only and has clearly specified this in the final rule. We 

received comments both in support of, and in opposition to, regulation of offshore facilities. We 

are not required to look at every emission point and pollutant under CAA section 111. Therefore, 

we did not evaluate these sources and have insufficient information to address these sources in 

this final action.

Comment: A commenter (4241) suggests revised rule language for §60.5375(a)(1)-(3) of the 

proposed rule. First, with regard to §60.5375(a)(1), the commenter provides the following 

revisions: “You must minimize the emissions associated with venting of hydrocarbon fluids and 

gas over the duration of flowback by routing the recovered liquids initially into storage vessels 

and/or reinjecting the recovered liquids or routing the recovered gas into a gas gathering line or 

collection system.” The commenter argues that the revised language in subparagraph (a)(1) 

would allow for reinjection where feasible and safe, which would be consistent with current 

industry practice. One commenter (3528) also asks if instead of flaring, whether the gas could be 

used to operate a generator or other gas fired equipment on the site.

Response: The EPA agrees with the commenters and has adjusted the rule language to allow for 

re-injection or recovery for another useful purpose. Section 60.5375(a)(1) has been revised to 

allow for re-injection of gas or liquid, or the use of recovered gas on-site as a fuel source or for 

another useful purpose. 

2.1.2 Pneumatic Controllers

Comment: One commenter (4266) states that, unlike the large emission sources regulated in 

other NSPS subparts, operators, manufacturers, and suppliers keep inventories of extra 

pneumatic controllers in stock as they are relatively inexpensive, and since malfunctions require 

quick repair or replacement to maintain production. This commenter claims a compliance date of 

only 60 days after promulgation will make large inventories of high bleed controllers potentially 

unusable. Therefore, the commenter requests that the effective date of this rule for pneumatic 

controllers be delayed for one year past the promulgation date to allow companies to adapt to the 

new requirements and make inventory adjustments.

Response: The EPA clarifies that, under this NSPS, a pneumatic controller is considered to have 

commenced construction when an owner operator has entered into a contractual obligation to 

acquire that piece of controller. This is consistent with the definitions of “commence” in the 

General Provisions at 40 CFR 60.2. Accordingly, controllers ordered prior to the proposal date of 

the standard (August 23, 2011) are considered existing facilities and therefore may be installed 

without being subject to the NSPS. Furthermore, the NSPS allows the use of high-bleed 
36

pneumatic controllers in certain specified circumstances. In light of the above, we do not 

anticipate a large inventory of potentially unused high bleed controllers. 

Comment: One commenter (4233) disagrees with the use of 6 scfh as the cutoff to categorize a 

pneumatic controller as either high- or low-bleed, claiming there is no justification for this 

number.

Some commenters (4104, 4228, 4233, 4266) argue that there is no discussion of how this 6 scfh 

emissions limit was derived in the proposed rule or in the TSD. Without this information, a 

commenter states that the EPA has not “adequately demonstrated” that this bleed limit is 

“achievable” as required by section 111(a)(1) of the CAA. The commenters object to the 6 scfh 

threshold for continuous high-bleed controllers for assorted reasons, including assertions that the 

market models available cannot support this threshold; that the emissions limit is based on an 

arbitrary continuous natural gas bleed rate of 6 scfh; and that the limit is outdated and should be 

lowered to reflect technology currently being sold and current practices. The commenters request 

that the EPA conduct additional analysis based on current practices, equipment population, and 

manufacturer product lines to determine what bleed rates are appropriate to define a regulatory 

threshold. 

One commenter (4266) states that a 6 scfh dividing line between high-bleed and low-bleed 

would mean that most operators would choose between continuous high-bleed and intermittent 

vent controllers that are no-bleed and explained why. This commenter concludes that this should 

be considered a desirable outcome. 

Another commenter (4240) argues that the 6 scfh bleed rate to define low-bleed controllers is 

higher than what modern technology can achieve in many circumstances. This commenter wants 

to see maximum bleed rates among pneumatic devices which would correspond to different 

functions for those devices. The commenter states that the EPA must therefore define a 

maximum bleed rate for each functional class of pneumatic controller, setting each bleed rate to 

force technological improvements, consistent with the goals of the NSPS program. The 

commenter believes that this range of allowable bleed rates must extend no higher than 5 scfh, 

the highest bleed rate supported in the record. For each class of controller, this commenter 

believes the EPA must fully justify that its standard is no higher than the lowest emission rates 

that each class of controller can achieve. This commenter concludes that this would “force” 

technological improvements, consistent with the goals of the NSPS program. This commenter 

also argues that rigorous leak detection and monitoring standards for low-bleed pneumatic 

devices should be in the final rule to ensure that “the EPA captures the full benefits of its 

proposal.”

Another commenter (4192) suggests specific revisions to §60.5410(d) based on the fact that 

continuous, low-bleed controllers typically range from 6 to no more than 10 scfh. The 
37

commenter’s recommended revisions are as follows: a 60-day reply period for demonstration 

that a high-bleed pneumatic controller is predicated, use of manufacturer documentation to show 

a pneumatic controller is low-bleed (where low-bleed is now defined as < 10 scfh), replacement 

of an existing high-bleed pneumatic controller with one that meets rule standards (or has been 

demonstrated to the Administrator) within 6 months of replacement or reconstruction, and 

inclusion of this information in the initial annual report submitted for pneumatic controller 

affected facilities according to the rule requirements.

Response: The EPA is maintaining the bleed rate set in this rule to be 6 scfh based on the use of 

this well-accepted and established methodology and the ability of pneumatic controllers on the 

market to achieve it. The EPA specified a methane emissions category labeled “gas-operated 

high-bleed pneumatic devices” in the 1993 Report to Congress (Opportunities to Reduce 

Anthropogenic Methane Emission in the United States, Report to Congress, October 1993, EPA 

430-R-93-012) wherein the EPA cited the industry study: PG&E (Pacific Gas and Electric), 

1990, Unaccounted for Gas Project Summary Volume, PG&E Research and Development; San 

Ramon, CA; GRI 90/0067.1. This study established a high-bleed device as a device with a 

continuous bleed emissions rate in excess of 6 standard cubic feet per hour (scfh), while lowbleed devices bleed at a rate less than or equal to 6 scf. Since the development of that study, EPA 

in collaboration with industry has further evaluated and adopted this definition of low bleed 

device as a voluntary Best Management Practice and developed detailed technical materials to 

promote this practice across the industry. The commenters did not provide sufficient information 

to support their statements to change the limit. Therefore, based on all available information, the 

EPA has determined that this limit is appropriate and is moving forward with the emissions limit 

at proposed. The methodology for this emissions limit is further detailed in Section 5.2 of the 

proposed rule Technical Support Document.

The EPA also clarifies that it does not require "low-bleed" controllers, only an emissions limit 

for affected facilities. The affected facility is defined in the final rule for pneumatic controllers 

located between the wellhead and the point of custody transfer to the natural gas transmission 

and storage segment other than at a natural gas processing plant as “a single continuous bleed 

natural gas-driven pneumatic controller operating at a natural gas bleed rate greater than 6 scfh 

which commenced construction on or after August 23, 2011...”

A commenter anticipates that the “low-bleed” requirements in the rule mean that operators will 

opt to install intermittent or no bleed controllers. The EPA clarifies that the rule specifies an 

emissions limit rather than use of a technology meeting specific “low-bleed” criteria. The EPA is 

not regulating separate power gas or actuation gas to position valves as part of this action, nor is 

the EPA regulating intermittent bleed emissions related to process control as part of this action. 

Given that pneumatic controllers operate on the same principle of sensing a process condition, 

transmitting a process condition, comparing that process condition to a set point, and actuating a 
38

valve based on that comparison, the EPA disagrees that pneumatic controller affected facilities 

must be further stratified by the function that they perform. 

The EPA disagrees with the comment arguing that the final rule should include rigorous leak 

detection and monitoring to assure compliance with the pneumatic controller standards in the 

production segment. The standard at issue is expressed in terms of a controller’s bleed rate (6 

scfh), based on our conclusion that using a controller with a bleed rate at that level or below is 

the BSER for reducing VOC emissions from pneumatic controllers in the production segment. 

Accordingly, compliance is achieved by installing controllers with a bleed rate at or below this 

standard. As long as controllers meeting the bleed rate are being installed, continued compliance 

is assured and there is no need for leak detection and monitoring after installation. As explained 

in section V.C. of the preamble, we expect that documentation from manufacturers will provide a 

controller’s bleed rate or information for determining the bleed rate. In light of the above, the 

EPA does not believe that leak detection and monitoring is necessary for assuring compliance 

with the pneumatic controller standard in the production segment. 

To address the commenter’s recommendation to remove manufacturers’ design guarantees, the 

EPA agrees with this comment and has removed the requirement to obtain design guarantees in 

the final rule. Please refer to the final rule §60.5420(c)(4) for the reporting requirements for 

pneumatic controller affected facility.

The EPA is not revising the rule to incorporate commenter suggestions of a wait period or a 

demonstration of compliance within 6 months of replacement or reconstruction. However, as 

explained further in sections V.C and IX.C of the final rule preamble, the EPA is allowing a oneyear phase-in period after the final rule is published in the Federal Register before the pneumatic 

controller bleed rate limit is effective for affected facilities located between the wellhead and the 

point of custody transfer to the natural gas transmission and storage segment, other than at a 

natural gas processing plant. 

Comment: One commenter (4241) suggests an alternate compliance method that should be 

added to the final rule. The commenter claims there should be provisions for alternate emission

controls for pneumatic controllers at processing or non-processing facilities (such as routing the 

vent streams to a flare, combustor, or vapor recovery unit to achieve 95 percent control 

efficiency). The commenter believes this would greatly reduce the cost of compliance at 

processing facilities that are not currently equipped with instrument air or other non-natural gas 

motive gas systems and would give greater flexibility to non-processing facilities.

Response: Regarding the commenter’s suggestion of alternate compliance methods for 

pneumatic controllers at processing or non-processing facilities, the final rule requires a natural 

gas bleed rate limit, not a technology requirement for pneumatic controllers. The affected facility 
39

is defined in the final rule for pneumatic controllers located between the wellhead and the point 

of custody transfer to the natural gas transmission and storage segment other than at a natural gas 

processing plant as “a single continuous bleed natural gas-driven pneumatic controller operating 

at a natural gas bleed rate greater than 6 scfh which commenced construction on or after August 

23, 2011...” The natural gas bleed rate of such affected facilities located between the wellhead 

and a natural gas processing plant must be less than or equal to 6 scfh, and must be zero for 

affected facilities at a natural gas processing plant. We believe there are pneumatic controllers 

available that meet these bleed rates and no other compliance options are necessary. However, 

the final rule does not provide the use of alternate controls to meet the bleed rate limits.

Comment: One commenter (4249) urges the EPA to simplify the reporting and recordkeeping 

requirements under subpart OOOO and recommends that the definitions and nomenclature used 

in the GHG MRR (subpart W) and the proposed subpart OOOO be identical to the maximum 

extent practical. The commenter claims this will help to avoid confusion in establishing 

compliance plans for the same device under separate rules. Another commenter (4213) notes 

that, per §60.5410(d)(3), requiring owner/operators to comply with emission standards on 

pneumatic controllers by relying on the manufacturer’s guarantee that the controllers emit less 

than or equal to 6 scfh is inconsistent with the EPA’s recent proposal of subpart W. The 

commenter notes that subpart W states the oil and gas industry may comply by using engineering 

estimates to determine whether pneumatic devices are low-bleed or high-bleed. The commenter 

believes the EPA should allow the industry to use engineering estimates for compliance with the 

6 scfh requirement and to determine emission rates to be consistent with the proposed 

amendment to subpart W. This commenter argues that if the EPA chooses not to do this, it must 

then promulgate a provision requiring manufacturers to provide this certification or guarantee. 

The commenter states that the EPA has done this for other types of equipment in the past (see 

§60.4231(a)).

Response: Subpart W under the Greenhouse Gas Mandatory Reporting Rule and this proposed 

rule each have different purposes. Subpart W is a reporting rule where operators supply activity 

factors to inform the EPA about the oil and gas industry. The rule allows the operator to estimate 

the total number of pneumatic devices, the emission factor, and the operating hours. The 

methodology in subpart W is not appropriate to apply to this NSPS action since the affected 

facility under this regulation is clearly defined and must be accounted for individually rather than 

estimated at a broader area level. The emissions factor table in subpart W is not equivalent to 

manufacturer specifications that will be readily available for a new controller. Subpart OOOO is 

an emissions limit rule that requires each affected facility to meet a specific standard for 

reducing emissions. Given the different objectives of each action, the two rules have different 

definitions and nomenclature and one cannot be used for the other. However, we believe that the 

final rule, which greatly lessens the compliance burden associated with the pneumatic controllers 

NSPS compared to the proposed rule, addresses the commenter's concerns.
40

Comment: A commenter (4254) requests that the EPA provide additional information about 

how to demonstrate that the use of high-bleed pneumatic controllers is predicated as stated in 

§60.5390(a). Additionally, the commenter urges the EPA to provide well-defined, specific 

examples and technical documentation of exemptions when high-bleed controllers can be used. 

Another commenter (4189) urges the EPA to more carefully define the circumstances when it 

will grant an exemption and allow the public to comment and challenge such exemptions. The 

commenter claims the proposed rule would allow operators to avoid using low- or no-bleed 

pneumatic controllers when their use is not “predicated.” This commenter states that the EPA 

does not define this term and risks undermining its own rule with such a vaguely worded 

exemption.

Response: In the final rule, the EPA has provided specific exemptions to the natural gas bleed 

rate limits for pneumatic controllers for certain safety requirements and considerations. The EPA 

believes that it is important to allow operator judgment to determine what these critical 

applications are and to provide records that document the need for a device that exceeds 6 scfh.

Section 60.5390(a) gives examples of variables that can be used to demonstrate the need for an 

exemption from the requirements in §60.5390(b) and §60.5390(c) for pneumatic controllers, 

including response time, safety, and actuation.

2.1.3 Compressors

Comment: Four commenters (4177, 4227, 4268, 4268) object to the language in the proposed 

rule that compressors are considered to have “commenced construction” on the date of

installation at a facility” and urged the EPA to remove the last sentence in the definition of 

affected facility for reciprocating compressors found at§60.4365(c). According to the 

commenters, the EPA gave no explanation as to why this definition was changed from the 

traditional NSPS definition of “commence construction” which applies when contractual 

commitments are entered into for the purchase of the equipment. The commenters state that the 

proposed rule preamble, regulatory impact analysis, and any other supporting rulemaking 

materials did not include an explanation or justification for changing the application of 

“commenced construction.” The commenters opine that the EPA’s proposed application of 

“commenced construction” to an existing source is contrary to the intent of the CAA. The 

commenters request that the traditional definition be put back into the final rule. One of these 

commenters (4227) provides an extensive list of CAA statutory provisions and the EPA 

regulations that confirm, in their opinion, that “commenced construction” is limited to “new 

sources” and should not be applied to existing sources which have been moved and not 

“modified” or “reconstructed.”
41

The commenters (4177, 4227, 4268, 4268) also want the EPA to clarify that the relocation of an 

existing compressor does not trigger the NSPS modification definition. The commenters state 

that, in §60.14(e), the term “modification” does not include the “relocation or change in 

ownership of an existing facility.” Therefore, according to the commenters, the relocation of 

existing compressors among sites managed by the same company would not trigger a 

modification under this rule. 

Five commenters (4192, 4218, 4220, 4246, 4263) object to the EPA’s current proposed text in 

§60.5365(b) and §60.5365(c).

Three commenters (4192, 4220, 4246) object to compressors being considered to have 

commenced construction on the date the compressor is installed at the facility. Two commenters 

(4192, 4246) argue that the EPA ́s current proposed text would make compressors subject to 

NSPS even if merely relocated. The commenters state that this would depart from the EPA ́s 

practice and section 111 of the CAA and recommended the current text be revised. One 

commenter (4220) states that the traditional NSPS “commence construction” definition applied 

when contractual commitments were entered into for the purchase of equipment. This 

commenter states that the wording in §60.5365(b) and §60.5365(c) deviates from this definition 

and would result in more compressors being brought into the program, even after financial 

commitments might have been made by companies. The same commenter (4220) requests that 

the EPA clarify that the relocation of an existing compressor does not trigger the NSPS 

modification definition under the proposed rule. The commenter notes that relocation of a 

compressor would typically also involve relocation of an attached driver to power the unit that 

might be subject to different “commence construction” rules under subpart JJJJ. 

Response: As the commenters note, the EPA traditionally defines the term “commence 

construction”, as it applies to an equipment, to mean the time an owner or operator has entered 

into a contractual obligation to acquire the equipment. This is reflected in the definition of 

“commenced” in the General Provisions at 40 CFR 60.2 as well as in the relevant NSPS (see, 

e.g., NSPS subpart JJJJ, 40 CFR 60.4230(a)). We therefore agree with the commenters that our 

proposed definition of “commence construction” in §60.5365(b) and §60.5365(c) as the time of 

installation is a deviation from our traditional view. Upon reviewing the comments and reevaluating the proposed definition, we conclude that there is no discernible difference between 

the compressors at issue and other equipment subject to NSPS that would make such deviation 

necessary or appropriate in this case. We have therefore removed these specific definitions of 

“commence construction” in §60.5365(b) and §60.5365(c) of the final rule. 

The NSPS also does not apply to relocated compressors. As provided in the NSPS General 

Provisions at 40 CFR 60.14(e)(6), relocation of an existing facility is not a modification. 
42

Comment: One commenter (4218) suggests that §60.5365(b) and §60.5365(c) be modified to 

state that they apply only to the extent that the compressor was manufactured after August 23, 

2011. The commenter argues that this would avoid imposing significant costs to retrofit existing 

wet seal centrifugal compressors. One commenter (4263) suggests modifying §60.5365(b) to 

limit the affected source to new centrifugal compressors and exclude centrifugal compressor 

facilities that compress natural gas that is less than 10 percent VOC. The commenter argues this 

would avoid requiring retrofitting a compressor equipped with a wet seal system with a dry seal 

system, something the commenter states could be cost-prohibitive. The commenter suggests 

adding to the provision a requirement that it apply only to centrifugal compressors that are in 

VOC service.

Response: The suggested definition change is not consistent with the definition of the term 

“commenced construction,” which is described in the comment response to the previous 

comment. In any event, for the reasons explained in IX.D of the final rule preamble, the final 

rule does not require that all centrifugal compressors be equipped with a dry seal system, as we 

proposed. Rather, the final rule applies only to wet seal centrifugal compressors and requires a 

performance standard of 95 percent control of VOC emissions. Retrofitting with dry seal would 

not be necessary for modified centrifugal compressors to meet the NSPS in the final rule.

Comment: Another commenter (4192) recommends that modification and reconstruction not 

subject a compressor to NSPS subpart OOOO, arguing that compressors are almost never 

modified or reconstructed.

Response: CAA section 111 requires that new and modified sources comply with the NSPS. The 

EPA considers reconstructed sources to be new sources. The General Provisions for modification 

(40 CFR 60.14) and reconstruction (40 CFR 60.l5) also clarify that facilities that re modified or 

reconstructed after the date of proposal of a standard are subject to the standard. There is no 

exception from this requirement on the basis that the facilities (in this case compressors) are 

almost never modified or reconstructed. 

Comment: One commenter (4241) requests that the EPA confirm that:

1) the reciprocating compressor affected facility that is subject to the proposed requirements 

at proposed §60.5385 is the individual compressor itself;

2) NSPS requirements would apply only to new compressors or replacement of old 

compressors with new compressors after August 23, 2011;

3) compressors installed before August 23, 2011 are not affected by the proposed ruling 

when modifications are made to other components of the reciprocating spark ignition 

engines; and

4) replacement of reciprocating compressor rod packing after August 23, 2011, at a 

reciprocating compressor that was installed before August 23, 2011, does not constitute 
43

either installation of a new compressor or a modification of an existing compressor that 

triggers the NSPS requirements.

Response: The EPA confirms that a reciprocating compressor affected facility subject to the 

NSPS in §60.5385 is the individual compressor and the NSPS apply to new compressors as well 

as replacement of old compressors with new compressors after August 23, 2011. In addition, 

under the General Provisions for modification (40 CFR 60.14) and reconstruction (40 CFR 

60.l5), the NSPS apply to compressors that are modified or reconstructed after August 23, 2011. 

We do not believe that replacement of reciprocating compressor rod packing would meet the 

criteria for “modification” under 40 CFR 60.14 or “reconstruction” under 40 CFR 60.15. 

However, as explained in a previous comment response above, under the final rule, “commenced 

construction” is not the date a compressor is installed but the date an owner or operator enters 

into a contractual obligation to acquire a compressor. We have therefore removed the proposed 

definition of “commence construction” in §60.5365(b) and §60.5365(c) (which was based on the 

installation date) in the final rule. 

Comment: One commenter (4241) recommends that the Agency develop a subcategory for 

reciprocating compressors that operate in low pressure environments with a higher standard for 

hours of operation (such as 52,260 hours of operation). 

Response: The EPA has determined the 26,000 hour fixed replacement period requirement for 

owners or operators to replace their reciprocating compressor rod packing is appropriate for all 

reciprocating compressors located between the wellhead and the point of custody transfer to a 

natural gas transmission and storage facility. The EPA is also providing flexibility by allowing 

operators in the final rule to change rod packing every 36 months in lieu of monitoring hours of 

operation. In addition, the commenter did not provide additional data for the EPA to evaluate 

compressors in low pressure environments.

Comment: A commenter (4275) requests that the EPA add reciprocating compressors in the 

production sector to be subject to subpart OOOO. The commenter asserts that reciprocating 

compressors in the production sector are significant sources of methane and excluding them from 

this rule will result in the loss of reduced emissions from existing reciprocating compressors.

Response: The EPA disagrees with the commenter that the EPA should add reciprocating 

compressors in the production sector to be subject to subpart OOOO. As outlined in the TSD to 

the proposed rule, section 6.4.2.3, the economic impact analysis for this rule determined that 

potential VOC reductions from wellhead reciprocating compressors' rod packing were not costeffective. However, the EPA determined that emissions control for gathering and boosting 

compressors were cost-effective. 
44

Comment: One commenter (4241) acknowledges that a requirement to conduct periodic leak 

testing or monitoring would be extremely costly. 

Response: The EPA appreciates this comment and has decided to retain the 26,000 hour fixed 

replacement period requirement for operators to replace their reciprocating compressor rod 

packing. In addition, the EPA is providing flexibility by providing in the final rule that operators 

may change rod packing every 36 months in lieu of monitoring hours of operation.

Comment: One commenter (4175) recommends that the EPA provide specific clarification in 

the rule that rotary screw compressors are not covered and cited an EPA letter to support the 

request. The commenter provides amended language to the definition of “compressor” and 

“centrifugal compressor” to ensure that rotary screw compressors are not covered by the rule. 

Another commenter (3528) asks the EPA to confirm that a “screw compressor,” which has a 

male and female rotor, but no vanes or impellers, is not a centrifugal compressor within the 

meaning of the proposed rule. Two commenters (4268, 4177) recommend that the EPA provide 

specific clarification in the final rule that rotary screw compressors are excluded from subpart 

OOOO. One commenter (4241) requests that the EPA confirm that the rule does not cover screw 

compressors, consistent with 40 CFR 98, subpart W. This commenter also asks the EPA to 

confirm that proposed §60.5380 would be inapplicable to screw, sliding vain, or liquid ring 

compressors, because these types of compressors typically are used in lower pressure 

applications normally associated with wellhead service. The commenter also objects to the 

definitions of centrifugal compressor and reciprocating compressor in the proposed rule as they 

are technically not correct and may cause confusion. Two commenters (4241, 4268) provide 

language for revised definitions of “compressor” and “centrifugal compressor.”

Response: The EPA agrees with the commenter that the subpart OOOO definition for 

centrifugal compressors does not include screw compressors. Therefore, screw compressors are 

not covered under this rule. The EPA has clarified the definition of centrifugal compressor to 

exclude screw, sliding vain, and liquid ring compressors.

2.1.4 SO2 Emissions from Natural Gas Processing Plants

Comment: One commenter (4039) requests that the EPA revert to the previous definition of a 

sweetening unit which clearly states that these are used to treat sour gas. The commenter notes 

that §60.5430 states “... a process device that removes hydrogen sulfide and/or carbon dioxide 

from the natural gas stream," whereas the previous definition found in subpart LLL recognizes 

that a sweetening unit is used to process sour gas. The commenter believes this would indicate 

that a natural gas stream processed solely for carbon dioxide removal would be subject to 

regulation regardless of the hydrogen sulfide content. 
45

One commenter (4275) recommends the EPA include additional SO2 reductions from existing 

plants in the final standards. One commenter (4241) supports the EPA’s conclusion that the 

regulation of SO2 emissions from boilers/heaters burning sour gas in the field is not appropriate 

under this NSPS. 

One commenter (4242) states that the SO2 control efficiency equation must account for all sulfur 

compounds. The commenter states the EPA’s proposed performance test and subsequent 

monitoring requirements require facilities to calculate the reduction efficiency by calculating the 

ratio of the combined weight of the sulfur recovered by the sulfur recovery unit and atmospheric 

SO2 emissions to the H2S content of the gas before it is processed by the sulfur recovery unit. 

The commenter states that this is not an apples to apples comparison. The commenter states the 

sulfur recovered by the sulfur recovery unit and the sulfur discharged to the atmosphere as SO2

may have originated from non-H2S compounds, but this amount is not included in the 

denominator in the proposed equation. Therefore, the commenter believes the proposed methods 

for determining compliance artificially inflate the SO2 reduction efficiency achieved by the 

natural gas processing plant. The commenter states that, significantly, tests of natural gas 

samples show that the non-H2S species of sulfur compounds can account for more than 50 

percent of the total sulfur volume in the natural gas. The commenter believes the EPA must 

require natural gas processing plants to measure the total sulfur content of the natural gas before 

it is processed by a sulfur recovery unit to accurately determine compliance with the required 

SO2 emission reduction efficiency.

Response: We agree with the commenter concerning the definition of “sweetening unit.” In the 

final rule, we have changed the definition back to what is in subpart LLL.

Regarding field boilers and heaters, these are not part of the Oil and Natural Gas source category 

and are generally too small to be regulated by the NSPS covering boilers (i.e., they have a heat 

input of less than 10 million BTUs/hr). They may be included in future rulemakings. Regarding 

control efficiency, subpart OOOO and subpart LLL specifically address the sulfur feed rate from 

the sweetening unit (i.e., the H2S in the acid gas), expressed as sulfur in determining compliance. 

In response to the comment concerning strengthening standards for existing units, we point out 

as discussed elsewhere in this document that subpart OOOO applies to new, modified and 

reconstructed facilities, not existing facilities.

We appreciate the comments concerning the SO2 control efficiency equation. However, subpart 

LLL was carried over essentially unchanged into subpart OOOO. We did not propose any 

changes to the compliance calculations, nor did we ask for any comment on them. Therefore, we 

believe that there is no logical outgrowth from the proposal to base any changes to the 

compliance calculation equations or methodology and we are making no changes as a result of 

this comment.
46

Comment: Two commenters (4174, 4263) state that the EPA should revise the definition of 

"natural gas processing plant" in part 60 subpart KKK to clarify the meaning of the term, as 

acknowledged by the EPA in numerous applicability determination memos and avoid the need 

for future applicability determination requests. The commenters provide suggested text. One 

commenter (4266) states that while the regulatory text clearly indicates that the standard applies 

to sweetening units located at onshore natural gas processing plants, this distinction is not made 

in the applicability provisions of §60.5365(g). To improve clarity on the applicability for 

sweetening units, the commenter recommends the provision be revised to read: 

§60.5365 (g) Sweetening units located at onshore natural gas processing plants that 

process natural gas produced from either onshore or offshore wells. 

Response: We agree that the suggested revision to §60.5365(g) provides additional clarity and 

have made the change in the final rule. In addition, we have revised the introductory language of 

§60.5365 to clarify that this subpart applies to onshore affected facilities. We do not believe any 

changes to the definitions of subpart KKK are warranted at this time.

Comment: One commenter (4240) agrees with the EPA that, as facilities with high sulfur feed 

rates can achieve a 99.9 percent control efficiency, the existing 99.8 percent feed rate no longer 

reflects BSER/BDT. The commenter supports the EPA’s decision to raise the maximum required 

control efficiency consistent with control rates achieved by the sources in the EPA’s database. 

One commenter (4282) states that the EPA’s rationale in proposing NSPS control at levels as 

high as 99.9 percent is flawed. The commenter states that use of the two facilities referenced in 

the proposed regulations addressing sweetening units may be a reasonable approach for a BACT 

determination, but is inappropriate for NSPS. The commenter believes NSPS need not and 

should not be as stringent as BACT. The commenter believes facilities were subject to control 

requirements much stricter than NSPS. The commenter states that operating data from their sour 

gas processing facilities indicates that the current NSPS subpart LLL control level of 99.8

percent is overly stringent when compared to other NSPS that regulate SO2 emissions. 

Response: As described in more detail in the TSD, after reviewing the available cost 

information, we believe a 99.9 percent efficiency is cost effective for facilities with a sulfur feed 

rate greater than 5 long tons per day and H2S content equal to or greater than 50 percent. Based 

on this review, the maximum initial and continuous efficiency for facilities with a sulfur feed rate 

greater than 5 long tons per day and a H2S content equal to or greater than 50 percent is raised to 

99.9 percent. We disagree with the commenter that installation of a tail gas cleanup unit is the 

only option available to a facility, and evaluated such options, as discussed in the preamble to the 

original proposed subpart LLL. We also disagree that the control level specified in other rules is 

a factor to be considered for subpart OOOO. Our data indicates that BSER for this industry is 
47

99.9 percent control, and that this level of control is cost effective. The conclusions drawn for 

other NSPS are dependent on the BSER cost effectiveness determinations for those industries 

and are based on different datasets and other industry-specific considerations that may not have 

any relevance to the oil and natural gas production industry.

2.1.5 Other Potential Emission Sources to be Regulated – Produced Water Ponds

Comment: Eight commenters (3468, 4225, 4258, 4236, 4251, 4266, 4317, 4472) oppose 

emission controls on produced water ponds. One commenter (3468) states that mature 

waterflood operations are common and production from such operations usually has lower 

gas/oil ratios than new flush oil production. The commenter asserts that these tank batteries may 

have lower emissions with the same or more crude oil throughput volume than from tanks used 

for new crude oil storage. The commenter states waterflood operations should be eligible for 

exemption from the proposed amendment. One commenter (4472) states that produced water 

ponds and flowback ponds should not be included. The commenter states that, because the EPA 

does not define "produced water ponds," it is not clear whether the EPA is considering regulation 

of emissions from flow-back ponds, produced water evaporation ponds, or produced water 

collection ponds (prior to deep well injection). The commenter adds that the EPA states in the 

TSD that "minimal amounts of emissions are caused by the fluid (mostly water) held in the 

impoundments or vessels since very little gas is dissolved in the fluid when it enters the 

impoundment or vessels." The commenter, therefore, believes that no emissions controls should 

be required for such ponds. In addition, the commenter is unaware of any available technology to 

safely control emissions from such ponds.

Two commenters (4225, 4258) contend that emissions from produced water ponds are more 

appropriately regulated by the individual States, as necessary, based upon the level of emissions 

associated with those ponds. The commenters believe a broad approach by the EPA may not be 

appropriate due to the significant differences in formation characteristics, including content of 

the gas, across various basins in the U.S. Two commenters (4236, 4266) state that VOCs from 

produced water ponds are unlikely to be a “significant source” of emissions. The commenters 

state that the EPA admits to having only “limited information” and demonstrates the difficulties 

associated with estimating emissions from produced water ponds, acknowledging that the VOC 

emissions will vary according to gas field and season and that the size and throughput of ponds 

may vary considerably. One commenter (4266) states that there is no data indicating that 

produced water ponds are significant emission sources. One commenter (4236) states that the 

EPA also appears to have limited information on the cost of any emission reduction 

technologies. 

Two commenters (4236, 4266) state that, prior to proposing limitations on emissions from 

produced water ponds, the EPA needs to collect more data and release any proposed limitations 
48

or standards for public review and comment. One commenter (4251) states it is not practical or 

feasible to measure emissions from produced water ponds. The commenter adds that the 

modeling software, Water 9, mentioned by the EPA, is designed for sewage treatment plants and 

is not applicable to measuring emissions from oil and gas operations. Further, the commenter 

states that in its operations, where ponds are used for water from CBM wells, the water contains 

de minimis volumes of VOCs or BTEX. The commenter believes that requiring industry to 

report on VOC emissions from produced water ponds would be a significant burden with limited 

to zero VOC reduction benefit. 

Several other commenters (3399, 3552, 4189, 4240, 4274, 4375) support implementation of 

emission controls for produced water ponds. One commenter (3399) is particularly concerned 

with the impact on the public of expanded drilling of natural gas in the Marcellus Shale, a 

significant source of significant air pollution. Two commenters (3552, 4189) state that the EPA 

should eliminate storage ponds and other open pit wastewater storage. One commenter (3552) 

states that these ponds are a source of air pollution and that many well site operators already 

store produced water in closed tanks to accommodate trucking to other sites for reuse or disposal. 

The commenter states that the EPA should prohibit open pit wastewater storage regardless of 

whether it receives sufficient additional information to quantify pond emissions. One commenter 

(4274) supports implementation of air quality controls relative to produced water ponds due to 

air quality impairments within their state. Two commenters (4189, 4274) state the EPA should 

consider a standard requiring all produced water to be stored in tanks. 

At a minimum, one commenter (4189) states the EPA should require operators to cover all pits, 

as required by many California air districts. One commenter (4275) adds that best available 

techniques to quantify emissions should be required. The commenter states that Colorado has a 

permitting system in place to help reduce emissions from produced water ponds and has 

developed ways to calculate emissions. One commenter (4375) states while they do not have 

firm data on the emissions from evaporation pond facilities, anecdotal evidence suggests these 

are a significant source of VOCs and HAPs. 

One commenter (4189) states that it is cost effective to require sources to install water treatment 

equipment which will reduce the emissions of VOC and HAP from the facility, which in 

combination can reduce VOC and HAP emissions by 90 percent or more. The commenter states 

that this is supported by the recently published study completed by Sonoma Technology, Inc., 

which discusses treatment and disposal options for produced water from conventional oil and gas 

wells. 

Another commenter (4191) recommends that the EPA include emission or control requirements 

for produced and flowback water facilities in the final rule. The commenter reports that they 

have found that produced and flowback waters have the potential to emit large quantities of VOC 
49

and HAP, with some water treatment, storage, or evaporation facilities having a potential to emit 

greater than 250 tons of VOC per year. The commenter provides emission and control 

technology information on five facilities in Colorado.

One commenter (4240) asserts that the EPA needs to develop controls for produced water ponds 

and sumps, holding these sources to a rigorous control efficiency standard. The commenter states 

that some reports establish that these ponds emit harmful pollution, including the EPA research 

showing emissions of VOCs, including the hazardous pollutants benzene, toluene, xylenes, and 

methanol, and New York State data concluding that these impoundments could be significant 

sources of methanol. The commenter states that California air districts have long controlled 

emissions from produced water ponds, for instance, by requiring such ponds to be covered, or 

that their emissions be captured or flared, or simply by requiring ponds to be replaced by tanks. 

One commenter (3562) states that while the EPA requested information on VOC emissions from 

water/liquid retention (tanks, ponds, etc.), it fails to address this issue. The commenter believes 

VOC emissions from backflow liquids and detention should be accounted for and reported. The 

commenter believes standard EPA methods for determining the VOC content in the water should 

be required. The commenter contends it should be assumed that 100 percent of the VOC content 

in backflow liquids and retention ponds or tanks that are open to the atmosphere is emitted to the 

atmosphere. 

One commenter (4184) agrees with the EPA that flowback ponds or impoundments can be a 

significant source of emissions for certain additive chemicals used in high volume fracturing 

operations. The commenter asserts that, based on information obtained from industry and 

consultants, it is necessary to use such emission models because there are no actual data 

collected or reported by industry on these specific chemicals. 

One commenter (4356) offers extensive guidance regarding the review and quantification of 

emissions from produced water at oil and gas production sites as recently published in the 

background documents for the Air Quality Standard Permit for Oil and Gas Handling and 

Production Facilities, effective February 27, 2011. 

One commenter (4240) states that well cellars, sumps, and even pools of oil can emit substantial 

VOCs, which are controlled by several different state regulators. The commenter asserts that the 

EPA must include standards for such sources based upon these available controls. 

Response: At this time, the EPA has decided not to propose regulations for produced water 

ponds. As noted in the comments received on this issue, there is limited firm data available on 

produced water ponds and we continue to have many concerns, including VOC content, methods 

which may be used to calculate emissions, cost of emission reduction technologies, and the 
50

parameters that could be used to define affected facilities. We thank the commenters for the 

additional information they have provided and will continue to monitor and evaluate this 

potential source category as appropriate.

2.1.5.1 Methods for Calculating Emissions

Comment: One commenter (4228) states it is premature to conclude that produced water storage 

ponds are a significant source of VOC emissions without representative data and conclusive 

results quantifying the evaporation of trace soluble VOC compounds. The commenter asserts 

that, prior to proposing emission standards, the EPA must collect and analyze a comprehensive 

data set to determine the significance of produced water ponds as a VOC source. The commenter 

also urges the EPA to select a more accurate VOC emission estimate than Colorado’s overly 

conservative 100 percent emission methodology. The commenter states that partitioning of 

highly water-soluble compounds and bacterial degradation would be expected to cause this 

assumption to have a very high bias. The commenter also states that water in the storage ponds 

can be reused as frac water or be sent to re-injection wells, which would reduce associated VOC 

emissions. The commenter adds that produced water that is reinjected or recycled into the 

producing formation should be exempted from consideration. 

The commenter (4228) notes that for subpart W of the GHG MRR, the EPA determined that 

produced water ponds are an insignificant source of gas emissions, and were not included in the 

reporting rule. 

One commenter (4237) states that produced water ponds should use the conservative Colorado 

mass balance approach which assumes 100 percent of the VOC content of the pond is emitted 

into the atmosphere based upon water sampling analysis. The commenter recommends that 

smaller evaporation pits co-located with drilling operations also be evaluated given the greater 

likelihood of being located near residential neighborhoods. 

One commenter (4241) believes that using a mass balance that assumes 100 percent of the VOC 

content is emitted to the atmosphere leads to consistent overestimation of actual emission rates 

from produced water ponds. The commenter states that, in August 2008, OAQPS, in conjunction 

with Arcadis, performed OP-FTIR measurements on two produced water ponds and one skim 

pond in the Piceance area in Colorado. According to the commenter, the study indicated that 

measured emissions were much lower than those that would have been calculated using a mass 

balance approach, assuming 100 percent volatilization, or using the AP-42 Chapter 4 method. 

The commenter does not believe that the WATER9 model is a suitable tool for estimating 

emissions from produced water ponds and urges the EPA to do additional comparisons of models 

and field tests to develop a more accurate estimating approach before attempting to regulate. 
51

One commenter (4266) states that the assumptions in WATER9 are quite conservative and tend 

to overestimate emissions. The commenter believes that assuming 100 percent of VOCs in the 

water enter the atmosphere is a false assumption that ignores the fate and transport of various 

chemicals. The commenter asserts that many chemicals, like methanol, have a very high affinity 

for water and do not evaporate; and many can only be removed from water using biodegradation. 

The commenter asserts that the EPA’s “Measurement of Emissions from Produced Water Ponds: 

Upstream Oil and Gas Study #1” found minimal emissions from the evaporation ponds. 

One commenter (4135) states that the WATER9 model is extremely difficult to understand in 

terms of input parameters and the units for those parameters. The commenter asserts that most 

users ultimately use widely varying, assumed values for input into the model. The commenter 

adds that a very small change in the numerous, assumed input values results in large changes to 

the modeled emission rates. 

Response: We appreciate the emissions information provided by the commenters; however, as 

stated in the previous comment response, we have decided to take no action concerning produced 

water ponds in the final rule.

2.2 Well Completions and Recompletions

2.2.1 Estimated Number of Wells

Comment: One commenter (4177) states that the EPA chose worst case emissions numbers 

(inflating the potential for controlled emissions) and applied those emissions to a limited number 

of facilities associated with new well sites (lowering the cost of control) without any 

consideration of potential applicability and costs at existing sites. The commenter provides the 

current producing well count data from Texas Railroad Commission. Another commenter (4356) 

presents data suggesting that the EPA underestimated the number of well completions 

throughout the country. In addition, one commenter (4191) explains the oil and gas regulatory 

entities in the state of Colorado and provides the number active (permitted) wells in the State; the 

commenter also informed that oil and gas well completion activities are regulated by a different 

department. One commenter (4240) provides information regarding recent years’ rapid growth of 

shale development in the U.S. Another commenter (4275) presents information on the number of 

CBM wells and states that while the VOC emissions per well might be lower for CBM wells 

than other types of wells, the cumulative impact of developing CBM reserves is extremely high.

Response: The EPA has estimated the regulatory impacts on the basis of expected number of 

new affected facilities, rather than the total number of existing wells. The EPA made its 

estimates using EIA NEMS which projects new drilling based on a national economic demand 

model.
52

Comment: Two commenters (4159, 4251) state that RECs are routinely used by the industry and 

one (4159) indicates they are more prevalent than the 15 percent of completions and 

recompletions suggested in this rulemaking. The commenters urge the EPA to work with 

stakeholders to develop better estimates of the frequency of RECs and emissions from well 

completions and workovers. A commenter (4233) notes that the benefits of complying with the 

proposed rule were overestimated because the RIA assumed that only a small percentage of 

operators currently capture gas. The commenter submits well completions information showing 

that one company captures gas from 91 percent (versus the EPA’s 15 percent) of wells annually. 

The same commenter submits well completions information showing that, for wells where gas is 

not captured, the company flares emissions from 57 percent (versus the EPA’s 51 percent) of 

wells annually. The commenter also submits data representing a total of 7 companies which 

shows that gas is captured from 92 percent of wells annually and that gas is flared from 55 

percent of the remaining wells.

Response: Based on public comments and reports to EPA's Natural Gas STAR program, EPA 

recognizes that some producers conduct well completions using REC techniques voluntarily for 

economic and/or environmental objectives as a normal part of business. To account for emissions 

reductions and costs arising from voluntary implementation of pollution controls EPA used 

information on total emission reductions reported to the EPA by partners of the EPA Natural Gas 

STAR. This estimate of this voluntary REC activity in the absence of regulation is also included 

in the baseline. More detailed discussion on the derivation of the baseline is presented in a 

technical memorandum in the docket, as well as in the RIA.

2.2.2 Description of Well Completion Process and REC Process

Comment: One commenter (4135) wrote for the removal of the words “inserting and cementingin well casing” from the preamble of the proposed rule on page 52757 under “NSPS for Well 

Completions.” The commenter points out that setting the casing and cementing it in place is part 

of the drilling process. The commenter adds that if the EPA includes this activity, it will lead to 

an overestimate of completion emissions.

Response: The EPA agrees that a description of inserting and cementing-in the well casing is not 

related to the flowback activity for which VOC requirements have been promulgated. To address 

this comment, the EPA has removed this description so that the definitions now only focus on 

the completion operations that pertain to the emissions source being regulated by this action.

Comment: In §60.5375(a)(3), one commenter (4184) asks the EPA to specify what type of 

conditions may result in a fire or explosion hazard that would allow a well completion to occur 

without a combustion device.
53

One commenter (4222) expresses that subpart OOOO is currently regulated in Alaska under the 

State's Gas Disposition regulations, 20 AAC 25.235. The commenter states these regulations 

require that operators take action to " ... minimize the volume of gas released, burned, or 

permitted to escape into the air." The commenter asserts that Alaska's regulations authorize short 

term venting as a result of an emergency or operational upset for safety considerations. 

Additionally, the commenter states that discretionary authorization may be granted for venting in 

cases of emergency that threaten life or property, when necessary to prevent loss of ultimate 

recovery, or for testing a well before regular production. The commenter argues that these 

important exceptions are absent from the proposed subpart OOOO, which only appears to allow 

venting when fire hazards or explosions may result and requests that these additional exceptions 

applicable to Alaska should be included in the final rule. 

One commenter (4162) concludes that the language specifying the combustion device raises a 

concern that the language does not clarify when the use of a combustion device may result in a 

fire hazard or explosion. Commenter 4356 adds that where pit flaring is proposed to be required, 

there is substantial concern about fire danger, particularly in urban areas or during drought 

conditions.

Response: The EPA believes the operator has the best capability to determine when flaring 

would be a fire or explosion hazard. However, the reasons for venting instead of flaring must still 

be documented.

Comment: One commenter (4222) believes that the EPA has made erroneous assumptions about 

captured emissions. In Alaska, the commenter asserts that logistical challenges encourage 

alternative uses of these vapors such as use on-site, underground storage, re-injection for 

enhanced oil recovery in other fields, use as a chemical processing component, use for 

generation of heat or power, or wholesale or retail sales. The commenter requests that the EPA 

revise the proposed rule so as not to preclude any of these uses.

One commenter (4240) urges the EPA to collect the information necessary to determine whether 

all wells, including wildcat wells, can use gas that would otherwise be flared as fuel for onsite 

operations, and the emissions consequences of such a diversion. The commenter believes that if 

onsite fuel use produces more limited secondary environmental impacts than flaring, it must be 

required, where possible, and may be an especially attractive option for wells that are not near a 

gathering line.

Response: The EPA clarifies that REC can include the capture of flowback gas containing the 

VOC and directing that gas to a useful purpose which may include fuel gas or compressor 
54

suction. Gas directed through the flow line may be sent to sales, reinjected, used as fuel gas, or 

used for other gainful purposes.

The EPA has clarified §60.5375(a)(1) to include the possibility of routing recovered gas and 

utilizing it as a fuel source or other useful purpose.

Comment: One commenter (4225) requests that the EPA defer to existing State regulation of 

RECs based on Colorado’s success with them. The commenter recommends the EPA specify 

limits on the amount of gas that may be flared within the 3 to 10 day period before shutting the 

well or connecting to a sales line and to review the proposed work practices identified in the 

recently completed revised draft Supplemental Generic Environmental Impact Statement 

(SGEIS) released by NYSDEC in September, 2011 for high-volume hydraulic fracturing 

activities in the Marcellus Shale and other low-permeability reservoirs. 

Response: The EPA reviewed the Colorado Oil and Gas Conservation Commission's 

requirements for REC during development of the nationwide rule. Based on these considerations 

and the additional information gathered by the EPA, the current rule is expected to be successful 

in reducing VOC emissions from hydraulically fractured well completions as well as other 

sources. The EPA reviewed the SGEIS released by NYSDEC during development of the 

nationwide rule. Based on these considerations and the additional information gathered by the 

EPA, the current rule is expected to be successful in reducing VOC emissions from hydraulically 

fractured well completions as well as other sources. In addition, the EPA disagrees that a volume 

limit of the amount of gas that can be flared before shutting the well or routing the gas to a 

gathering line should be established.

Comment: One commenter (4230) requests clarification from the EPA on items contained in 

proposed §60.5375(a)(3). The commenter asks, if the moisture content is too high on the 

flowback gas for combustion, would a completion combustion device be required or would this 

require additional REC (water and condensate separators) to lower the moisture content of the 

flowback gas to enable the use of a completion combustion device?

Response: The EPA clarifies that the requirement is to route the flowback stream through a 

continuous ignition source such that VOCs are exposed to an ignition source and are, therefore, 

controlled via combustion. The pre-treatment of the flowback stream to control water content is 

not required but also not precluded from occurring based on the final rule text.

Comment: A commenter (4230) requests clarification on what “as soon as practicable” means in 

proposed §60.5375(a)(2). Another commenter (4375) is concerned with the failure to define the 

term "practicable" and recommends that the EPA place strict limits on the length of time that 

salable quality gas is not required to go into the gas gathering lines. The commenter asserts that 
55

by requiring salable gas to go into pipelines only within a "practicable" amount of time, the EPA 

creates too vague a standard to apply effectively and consistently in this aspect of oil and gas 

operations. The commenter believes this standard may allow companies to make unwarranted 

claims of non-practicability. The commenter suggests a hard cap of 10 days before all salable gas 

must go into gas gathering lines.

Response: The final rule requires an operational standard for gas well completions requiring the 

operator to route all salable quality gas to the gas flow line as soon as practicable. In response to 

the commenters’ suggestion to define the term “as soon as practicable,” the EPA has determined 

it is not appropriate to set a fixed period of time by when the gas must be sent to a flow line as 

that situation will vary by well and needs to be determined based on each well’s individual 

operating circumstances. Therefore, setting a universal fixed period of time would require 

support of technical and cost-effectiveness analyses showing that a selected period of time is 

feasible and non-arbitrary. Furthermore, the EPA has determined that it is in the operator’s best 

interest to control VOC by collection and sale rather than combustion. 

Comment: One commenter (4240) takes issue with the definition of “hydraulic fracturing” and 

implores the EPA to modify this definition. The commenter proposes a definition removing the 

words “high rate of extended back flow” which the commenter believes are relative and never 

defined in the rule text and therefore, avoiding discussions/confusion about the magnitude of 

backflow and the purpose of the operation.

Response: We agree with the commenter and are therefore making the commenter’s suggested 

changes to the definition of “hydraulic fracturing” in final rule.

2.2.3 Subcategory 1 Wells (non-exploratory and non-delineation)

Comment: A commenter (4266) proposes that objectives for the control of VOCs be provided 

rather than specific methods and that the EPA adopt a management system approach to well 

completions rather than trying to specify methods that may work in one well or one region but 

not for every well in every region.

Response: The commenter suggests that the rule require a best management practice plan 

(BMP) 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.
56

2.2.3.1 REC in Combination with Combustion is BSER for Subcategory 1 Wells, with Provisions 

for Venting

Comment: One commenter (4266) adds that the EPA has the authority under section 111 to 

adopt a “future effective” BSER determination for well completions. The commenter cites the 

“Clean Air Mercury Rule” (“CAMR”). The commenter also provides two detailed case law 

examples: Portland Cement Association v. EPA (486 F.2d 375) (DC Cir. 1973) and Lignite 

Energy Council v. EPA, 198 F.3d 930 (DC Cir. 1999) stating that those cases make it clear that 

while a determination about a technology or performance standard’s achievability may not be 

based on ‘mere speculation or conjecture,’’ a technology or standard that may not necessarily be 

considered ‘‘adequately demonstrated’’ at present nonetheless can be considered ‘‘adequately 

demonstrated’’ for a compliance date in the future. Commenter 4266 concludes that given that 

the EPA has definitively determined that it has authority to under section 111 to establish such 

future effective BSER determinations, and in light of the record evidence indicating that 

sufficient REC equipment will not be available upon the effective date of the final rule but can 

become available within two years after the effective date of the rule, the EPA has ample legal 

and factual justification to defer the REC requirement , the EPA has ample legal and factual 

justification to defer the REC requirement. Two commenters (4266, 4266) state that the proposed 

requirement to implement RECs immediately upon the effective date of the final rule does not 

constitute BSER since the equipment is not available, cited section 111(a)(1) to support the 

statement, and requested that the EPA demonstrate that BSER is cost effective, accounting for 

the costs of delay in obtaining REC equipment. Commenter 4266 recommends that the EPA

rectify this problem by bifurcating its BSER determination for well completions such that: (1) 

BSER is no additional control for a period of two years after the effective date of the final rule; 

and (2) REC constitutes BSER for well completions beginning two years after the effective date 

of the final rule. The commenter declares that such an approach would require that the EPA 

adopt a “future effective” BSER determination for well completions.

Response: See section IX.B of the final rule preamble. 

Comment: One commenter (4191) recommends that well “shut in” be provided as an alternative 

to the requirement to route salable gas to a flow line in §60.5375(a)(2). The commenter (4191) 

provides the following text revision: “All saleable quality gas must be routed to the gas gathering 

line or the well must be shut in as soon as practicable.”

Response: The EPA disagrees with the commenter's suggested revision. The EPA notes that this 

action is regulating the VOC emissions that occur during flowback, after a hydraulic fracture or 

re-fracture. The rule requirements do not preclude a well from being shut in prior to the flowback 

so that the VOC control takes place at a time when the VOC control can take place.
57

Comment: One commenter (4184) states that language in §60.5375(a)(1) and (a)(2) is overly 

vague and recommends that the regulation should require facility owners to apply "green" 

completion in all instances when a gathering line is available.

Response: The EPA disagrees with the commenter's suggested revision. While the owner or 

operator may choose to shut in the well at any time, we do not believe that §60.5375(a)(2) needs 

to further prescribe actions required by the owner or operator beyond routing the saleable quality 

gas to the flow line as soon as practicable. 

Comment: One commenter (4184) believes that the EPA's rationale for preferring flaring to 

venting is based on calculations that indicate that the destruction of emissions of VOCs 

outweighs any increase in secondary NOx emissions. The commenter indicates that the EPA 

underestimated the NOx emissions due to flaring and did not recognize the potential for sulfur 

dioxide (SO2) emissions in the presence of hydrogen sulfide.

Response: The EPA disagrees with the commenter's statement that the EPA did not properly 

consider the secondary impacts of flaring produced gas. The EPA affirms the regulatory impact 

analysis done for the final rule which concludes that the secondary impacts of combustion are 

outweighed by the benefits of VOC control. 

Comment: One commenter (4320) states that gas well completion operations typically last 10-

15 days and flares utilized in these operations are temporary devices. The commenter believes 

that conducting Method 22 observations for these temporary operations is inappropriate and 

overly burdensome. The commenter requests that the Method 22 requirement should be deleted 

from the final rule, adding that there are less burdensome and costly ways of determining the 

efficacy of flare controls used temporarily in well completion operations. 

One commenter (4230) requests clarification on items contained in proposed §60.5375(a)(3)

such as whether temporary flares used as “completion combustion devices” are required to meet 

the standards set forth in §60.18 or whether they are subject to any standards other than a 

continuous ignition source. This commenter also requests that the EPA subcategorize completion 

combustion devices. The commenter states that the preamble only discusses pit flares and does 

not discuss temporary elevated flares, which do not pose the same fire hazards as an open pit

flare and would not need the proposed fire hazard or explosion exemption from operation. 

Three commenters (4192, 4266, 4246) provide remarks on the definition of “completion 

combustion device.” One commenter (4192) recommends a revision. The commenter states that 

while pit flares are typically used and may not have been intended to be defined as flares, some 

operators may choose to use traditional flare devices or be required to do so by State or local 

rules and asserts these would more clearly be subject to §60.18. Two commenters (4266, 4246) 

suggest the following text revision: 
58

§60.5430 - Flare means a thermal oxidation system using an open (without enclosure) 

flame. Completion combustion devices are not considered flares. 

One commenter (4246) quotes §60.5375(a)(3) and states that the EPA appears to have chosen the 

term “completion combustion device” so that the pit flares, which the preamble states at p. 52758 

are not a “traditional flare control device” would not be subject to 40 CFR 60.18. The commenter 

states that the preamble indicates that this is the case “because of the multiphase slug flow and 

intermittent nature of the discharge of gas, water and sand over the pit.” As a result, the 

commenter states that it is impossible for pit flares to comply with the requirements of that 

section. The commenter states that the definition of flare would include pit flares due to their use 

of an open flame to oxidize the gas portion of the flowback. The commenter adds that while pit 

flares are often used, they may not have been intended to be defined as flares, and cannot meet 

the requirements of §60.18. The commenter asserts some operators may choose to use temporary 

portable “field flare” devices or may be required to do so by State or local regulations. The 

commenter states that temporary portable “field flares” may or may not be capable of meeting 

the requirements of §60.18. The commenter requests that they receive a similar exclusion from 

the requirements of §60.18 that afforded to pit flares.

Two commenters (4266, 4246) state that the rule currently requires a completion combustion 

device with a “reliable continuous ignition device.” In many cases electronic igniters are used 

instead of a continuous ignition device. Commenter 4266 requests that the rule be modified to 

explicitly allow the use of electronic igniters. Commenter 4246 requests that the proposed rule be 

modified to allow the use of electronic igniters in place of continuous ignition devices.

One commenter (4274) inquires whether it is necessary to flare all wells on a site when there is 

no gathering line network and requests to the EPA the development of fact sheets explaining the 

purpose of flaring and the associated health risks, if any. The commenter expresses concern 

about flaring for extended periods as a method of operation and indicates the need to establish a 

standard reasonable flaring method and proper flare timeframes.

Response: With respect to the commenter’s concern about conducting Method 22 observations 

on combustion devices, completion combustion devices are not considered flares, therefore we 

are not requiring the use of Method 22. We have made the commenters’ suggested revision to the 

definition for “flare” in §60.5430 to clarify this. As discussed elsewhere in this document and 

stated in the proposal preamble (76 FR 52758, August 23, 2011), completion combustion devices 

are not traditional flares (as defined in §60.5430) and are therefore not subject to §60.18.

The EPA also clarifies that the rule is not allowing electronic ignition devices as surrogates for a 

continuous ignition source. The continuous ignition source is designed to combust the flammable 

portion of the flowback gas, even if the flowback gas has a low BTU content. An electronic 
59

ignition device designed for ignition of a combustible stream would not be successful at 

combusting VOC portions of low BTU flowback gas.

In response to the commenters’ concern about the use of flaring because of the associated health 

risks, our proposal identified NOx emissions as secondary to VOC emissions where the benefit 

of reductions of VOC outweighed the secondary increases of NOx.

2.2.3.2. Phasing in Requirement for REC Over a Period of Time, or Other Ways to Address 

Potential Short-term Equipment Shortage

Comment: One commenter (4266) believes that neither section 111(e) nor section 111(a)(2) 

prevent the EPA from allowing Proposal Period Wells additional time after the effective date of 

NSPS subpart OOOO to comply with reporting, recordkeeping and notification requirements. 

The commenter cites the definition of the term "standard of performance" from section 111(a) 

and affirmed that only the standard for emissions of air pollutants is referenced in section 111(e). 

Reporting, recordkeeping and notification requirements are not, therefore, standards of 

performance so that section 111(e) need not be read to require compliance with these 

requirements on the effective date of NSPS subpart OOOO. The commenter adds that this 

appears to be a distinction already recognized by the EPA as a general matter, since the EPA 

already allows time after the effective date of rules to submit reports and notifications for other 

new sources.

Response: Under section 111(e) of the CAA, it is unlawful to operate a new source (including 

modified source) in violation of any applicable NSPS after the effective date of the standard. 

This final rule becomes effective 60 days after its publication. Therefore, compliance with the 

NSPS requirements in this rule (including both the performance standards and the associated 

recordkeeping, monitoring, and reporting requirements) is not required for well completion 

activities conducted prior to the effective date of this final rule. 

Comment: Two commenters (4233, 4234) state that green completions are not always feasible 

and gave reasons including that regulations stipulating well pads too small to accommodate 

equipment and the potential layout of the production area.

One commenter (1124) supports the NSPS rule and requests the standards be enforced and to 

take into consideration pad site impacts versus single well impacts. Another commenter (4233) 

asserts that AEPP completions are not always possible for a couple of reasons including the size 

of the well pad is too small to accommodate temporary equipment.

Response: With respect to the infeasibility of the rule requirements based on well sites being too 

small to accommodate equipment and the potential layout of the production area, the EPA 

disagrees. Because the development and hydraulic fracture of a well involves the use of sand and 
60

water trucks, pumper trucks, tanks, and other support equipment that are present at the well site

at various times during the well development, the EPA expects that the site can accommodate 

equipment necessary to accomplish the gas capture in combination with combustion, either by 

virtue of the well pad’s size to accommodate the well development equipment or by virtue of 

scheduling the departure of equipment from previous steps in the development to allow for the 

necessary footprint.

Comment: One commenter (4209) requests that, where the implementation of REC is not cost 

effective, completions and recompletions of wells be exempt of compliance with the proposed 

requirements. Another commenter (4162) states that the proposed rule fails to adequately address 

fugitive emissions in exploratory and delineation wells and relies solely on economic benefit to 

industry as the basis for ensuring capture of fugitive emissions in other situations and presented a 

DVD that the commenter states proves otherwise.

Response: The EPA disagrees with the suggestion to exempt compliance based on wells not 

being cost effective and with the statement that the rule controls emissions on the sole basis of 

what is economically beneficial to industry. The EPA developed its emissions estimate based on 

best available data and figures reported by industry. Please see Section 4.4.2.3 of the TSD. The 

EPA analysis reflects operations across the U.S. related to flowback after a hydraulic fracture 

and is intended to be representative of the variety of flowback situations that will be encountered. 

The EPA therefore believes that the requirements, overall, are cost-effective for VOC emissions 

control and is not establishing provisions exempting specific wells on the basis of costeffectiveness.

2.2.3.3 Accuracy of Cost Estimate for REC Performed by a Contractor, Given the Estimated 

Number of Wells in 2015

Comment: One commenter (4236) questions the EPA’s estimates of cost-effectiveness of RECs. 

The commenter states that the limited data set upon which the estimates were based does not 

reflect the recent activity in the Marcellus Shale region. The commenter notes that even within 

that region, emission rates are likely to vary greatly from well to well. The commenter (4236) 

states that inaccurate or unsupported cost estimates have an impact on the EPA’s analysis of 

compliance with the Regulatory Flexibility Act (RFA) (4236) and that some RECs might not be 

cost-effective. Some commenters assert that the EPA underestimated the cost of implementing 

the RECs, and thus the cost-effectiveness of the RECs proposed by the EPA is significantly 

different than described by the EPA. One commenter (4246) believes that the average cost per 

ton of VOCs reduction without sales could be 20 times greater than that estimated by the EPA. 

Another commenter (3529) states that the EPA underestimated the cost of complying with the 

proposed rule because the cost of other equipment necessary to comply with the rule was not 

considered. Two commenters (4266, 4246) provide the estimated equipment and labor cost per 
61

well to do REC and state that the EPA grossly underestimates the cost. The costs provided by the 

two commenters are based on a survey in which 9 companies provided data for 29 producing 

areas. The results of the survey are summarized as follows: a) Cost of RECs in Conventional: 

$2,150 - $5,900 per day; b) Cost of RECs in CBM: $4,286 - $30,000 per day; c) Cost of RECs in 

Shale: $1,530 - $10,500 per day; d) Cost of RECs in Tight Gas: $6,000 - $15,000 per day. A 

weighted average of the results was developed and reported to be approximately $5,000 per day.

Response: The EPA developed its cost estimate and emissions estimate based on best available 

data and cost estimates reported by industry. Regarding EPA's emissions estimates, please see 

the proposed rule TSD and the response to comment on EPA’s emissions estimates for 

hydraulically fractured gas wells. Given that RECs were reported to cost between $700 and 

$6,500 per day in 2006, the EPA scaled these values to 2008 dollars. The resulting range was 

$806 to $7,486 per day. The arithmetic mean of the low and high end of the range is calculated 

to be $4,146 per day. This value was then multiplied by the typical length of RECs as reported 

by industry, which was 7 days, to obtain the average total cost of RECs. Please see Section 

4.4.2.3 of the TSD for more information. However, because the average cost per day the 

commenter calculated is similar to the value the EPA calculated and the actual data obtained 

from the survey are not provided, the EPA is not re-evaluating the costs at this time. The EPA’s

analysis was conducted with the available data that reflects operations across the U.S. related to 

flowback after a hydraulic fracture. The commenters did not provide the actual results of the 

survey, but rather simply provided a summary of the data. 

Comment: One commenter (4255) states that the REC requirements fail to take into account that 

hydraulic fracturing is an operating technology that has been in existence for decades and has 

been used for many diverse types of wells. As such, according to the commenter, the proposed 

NSPS fails to differentiate between the large scale hydraulic fracturing operations utilized in 

completing horizontal wells in the various shale plays and the small scale completions and 

reworking that involve hydraulic fracturing in low production vertical wells. The failure to 

differentiate and exempt small scale completions that utilize hydraulic fracturing will be costprohibitive in many instances, says the commenter, because production in traditional vertical 

wells is naturally much lower. The commenter adds that it may be economically feasible to 

perform a “REC” type completion on unconventional horizontal wells that produce at high rates, 

but this type of completion is not realistic on conventional vertical wells.

Response: With respect to the commenters' concerns that the evaluation is not representative of 

vertical wells, the EPA disagrees. The EPA’s cost estimates were developed using an emission 

factor that estimates gas release from well completions. The data sets used to develop the 

emission factor included primarily vertical wells in CBM, tight sands, and shale formations, 

though the data set includes a representation of horizontal wells. This data set represents the 

EPA’s best available information to characterize emissions during a flowback following a 

hydraulic fracture. The EPA’s cost estimates are therefore representative of vertical wells. For 
62

more information please see the memo titled Emission Factor for Hydraulically Fractured Gas 

Well Completions located in the docket.

Comment: Six commenters (4216, 4233, 4241, 4246, 4251, 4266) state that the EPA 

overestimated emissions from gas well completions. Three commenters (4216, 4241, 4266) 

assert that the EPA’s assessment of well completion emissions was based on a small number of 

instances and is not representative of the many producing areas in the United States. Three 

commenters (4216, 4233, 4241) argue that the EPA’s estimates are based on an erroneous 

assumption that gas reported as captured through green completions would otherwise be vented 

to the atmosphere. One commenter (4233) asks that the EPA acknowledge data provided by the 

industry with lower estimates of emissions from gas well completions. Two commenters (4216, 

4233) also object to the assumption that producers in States that do not mandate flaring or 

recovery vent to the atmosphere during flowback, suggesting that the EPA underestimates flaring 

and recovery. Commenter 4241 states that there are a number of uncertainties with respect to the 

accuracy of emissions calculations for well completions and recompletions, as such, the 

commenter suggests that it is premature for the Agency to establish NSPS for such activities at 

this time.

Response: The EPA evaluated all information received and has decided to retain the data set and 

the methodology used to develop the original emission factor of 9,175 thousand cubic feet (Mcf) 

per completion, but has made one change to the factor--rounding it to 9,000 Mcf per completion. 

The EPA notes that there has been a great deal of confusion about the emission factor, and 

acknowledges the need for clarification of the approach to develop the factor and the appropriate 

use of the factor. As such, the EPA has provided improved documentation and description of the 

emission factor data sources and analysis. See the memo titled Emission Factor for 

Hydraulically Fractured Gas Well Completions located in the docket.

Commenters state that the emissions estimates were based on four data points. This is an 

inaccurate characterization of the basis for the EPA’s estimate. The emission factor for gas well 

completions with hydraulic fracturing was developed using four data sources, together

representing data from over 1,000 well completions with hydraulic fracturing. These data were 

provided to the EPA or its technical contractors by industry for presentation at Natural Gas 

STAR technology transfer workshops from 2004-2007. For each data source, the EPA calculated 

the average gas release per gas well completion. The data from these wells collectively indicate 

that the true average gas release rate for a hydraulically fractured well completion is substantially 

higher (greater than two orders of magnitude) than the 1996 GRI/EPA emission factor that is 

applicable to conventional well completions. These data also indicate that there is a high degree 

of variability in gas release rates across hydraulically fractured well completions due to geology,

technology and operating conditions. The four calculated averages were each then rounded to the 

nearest single significant digit to reflect the precision of these averages. The resulting emission 

factors from each of the four data sources were arithmetically averaged to determine the final 

emission factor for gas well completions with hydraulic fracturing. 
63

The EPA used the best publically available data to develop this factor, which estimated 

emissions captured through reduced emission completions from over a thousand wells. The EPA 

determined this data was appropriate for developing this emission factor, in order to estimate 

potential emissions from an uncontrolled hydraulically fractured gas well completion and 

recompletion.

Commenters state that the EPA overestimated emissions from well completions and that the 

factor is not representative of the many producing areas in the U.S. The data sets used to develop 

the emission factor included wells representative of U.S. formation types where hydraulic 

fracturing is typical, including low pressure wells (e.g., coal bed methane wells). It is also 

important to note that the data set used to develop the factor primarily included vertical wells, 

while horizontal wells generally produce more gas.

This factor represents natural gas released from the completion of a hydraulically fractured 

natural gas well (i.e., potential gas emissions from the completion process in the absence of 

controls to capture or flare the released gas). It is very important to note that in calculating total 

national emissions from completions with hydraulic fracturing for the Inventory of U.S. 

Greenhouse Gas Emissions and Sinks, the EPA adjusts calculated methane release for methane 

that is actually not emitted (i.e., that is instead flared or controlled with certain technologies and 

practices) due to both voluntary action and State regulations. For more information, please see 

the memo titled Emission Factor for Hydraulically Fractured Gas Well Completions located in 

the docket. The NSPS analysis takes a similar approach in the development of its baseline 

emissions estimates, taking into account reductions from voluntary action and state regulations. 

Please see the RIA for more information on baseline emissions estimates.

Commenters provide or point to seven different data sets related to well completion emissions 

after a hydraulic fracture. The data varies in the level of detail provided. In most cases, the 

commenters shared total emissions and corresponding number of wells. One data set uses an 

engineering calculation and provides key input parameters (such as pressure, flowback duration, 

choke diameter, etc.). Both completions with and without REC were represented as well as tight 

sands, shale, and coal bed methane (CBM) formations. The average emissions per well 

completion ranged from 600 to 12,637 Mcf gas for the seven data sets. As discussed in more 

detail in the memo, the EPA evaluated all of the data (both data used to develop the original 

factor and data from the commenters) in several ways to determine whether an improved 

emission factor could be developed. As a result of this assessment, the EPA concludes that, 

although it does have uncertainty, the original EPA emission factor provides a valid central 

estimate of emissions from this source in the U.S. Therefore, the EPA has decided to retain the 

data set and the methodology used to develop the original emission factor for well completions. 

See the memo titled Emission Factor for Hydraulically Fractured Gas Well Completions located 

in the docket.
64

A comment submitted by Devon Energy20 contains a study conducted by URS for ANGA. In the 

study, 7 companies submitted information relating to hydraulically fractured well completions at 

nearly 1,200 wells. Of the 7 companies, 4 submitted emissions estimates for 98 well non-green 

completions (i.e., completions without RECs). Emissions estimates were not included for wells 

with RECs, which comprised 92 percent of the URS data set. For each of the 98 wells without 

REC completions, URS provided information on pressure, flowback duration, and choke size 

and used Equation W-11B from subpart W of the EPA’s Greenhouse Gas Reporting Rule to 

calculate the emissions from completions. Using this equation, and a number of simplifying 

assumptions, URS calculated an average emissions rate of 765 Mcf per completion. 

In reviewing the data and URS’ use of the subpart W equation, it became apparent that the 

resulting flowrate from Equation W-11B was misinterpreted to result in a flow rate at standard 

conditions when it was in fact a flowrate at actual conditions. Converting from actual volume 

(actual conditions) to standard volume (standard conditions), which is the input intended to 

estimate emissions from gas well venting during completions and workovers following hydraulic 

fracturing in Equation W-10A, the EPA re-calculated an average value greater than 50,000 Mcf 

per completion. This value is far higher than the value presented by URS (765 Mcf per 

completion) and values given in other data sets. The EPA’s evaluation shows that the URS study 

is significantly underestimating emissions by using the equation at actual conditions, however, 

due to highly conservative assumptions made by URS (e.g., 100 percent gas in flowback instead 

of a mixture of gas and fluids, and maximum choke size and casing pressure), the recalculated 

emissions average of over 50,000 Mcf per completion may also be an inaccurate depiction of 

emissions. Given this uncertainty, the EPA performed the analyses highlighted in the memo 

titled Emission Factor for Hydraulically Fractured Gas Well Completions located in the docket 

both with (using the URS-calculated values per completion) and without the URS emissions 

estimates, for completeness and transparency. 

Several commenters also questioned the EPA’s decision to not round the 9,175 Mcf per 

completion factor, which was developed from rounded factors calculated from 4 data sets 

(together containing over a thousand wells). The EPA agreed with the commenters that the final 

factor should be rounded as well, and has rounded the factor to 9,000 Mcf per completion. For 

more information please see the memo titled Emission Factor for Hydraulically Fractured Gas 

Well Completions located in the docket.

2.2.3.4 Inability to Set a Numerical Performance Standard

Comment: One commenter (4241) states that in the event that the EPA declines to revisit its 

emissions calculations as requested by the commenter and chooses to go forward with regulating 

such activities regardless of the underlying inaccuracies, the commenter supports the Agency’s 

 

20 http://www.epa.gov/quality/informationguidelines/documents/12003-attB.pdf
65

proposal to implement operational-based standards for well completions in lieu of performancebased standards. The commenter states that the flow measurement technologies to accurately 

measure emissions that occur during pit flaring or venting this stage are not widely available and 

are very expensive. As a result, the commenter claims that if the EPA were to develop a 

performance-based standard (e.g., a numerical emission limit) for well completions, there would 

be no cost-effective monitoring protocol that would allow a well operator to demonstrate 

compliance with a numeric limitation. The commenter asserts this falls squarely within the scope 

of circumstances that Congress contemplated when it included sections 111(h)(1) and (2) of the 

CAA allowing the Agency to substitute operational standards for performance standards where it 

is not feasible to enforce a performance standard due to technological limitations of 

measurement methodology.

Two commenters (4231, 4241) respond to the EPA’s requested input on whether alternative 

approaches to requiring REC for all operators with access to pipelines may exist that would 

allow operators to meet a performance-based standard if they can demonstrate that an REC is not 

cost effective. One commenter (4231) does not support a performance-based standard for REC 

stating that such a standard would require monitoring that is not readily available or 

implemented. Another commenter (4241) agrees that there will be cases where a REC could be 

demonstrated to not be a cost effective way to reduce VOCs, and did not believe a performancebased approach to regulating well completions is feasible for the reasons stated above.

Two commenters (4251, 4254) respond to the EPA’s request for comment on whether alternative 

approaches to requiring gas capture for all operators with access to pipelines may exist that 

would allow operators to meet a performance-based standard if they can demonstrate that gas 

capture is not cost-effective. One commenter (4251) agrees there may be cases a REC could be 

demonstrated to not be a cost-effective way to reduce VOCs and did not believe a performancebased approach to regulating well completions is feasible. Another commenter (4254) states that 

such a standard would require monitoring that is not readily available or easily implemented. The 

commenter adds that there may be periods of time when it is unlawful or impossible to flare, 

making compliance with a performance-based standard infeasible.

Response: In response to EPA’s solicitation of inputs on the feasibility of complying with a 

performance standard for well completions, the EPA received comments confirming the EPA’s 

belief that measuring and monitoring emissions to demonstrate compliance with a performance 

standard is not feasible at this time. The EPA is therefore proceeding with the operational 

standard that requires VOC control using reduced emission completions and combustion in 

combination, as specified in the rule text.

With respect to the comments that REC may not be cost effective in all cases, as we stated in the 

proposal preamble, we recognize that there is heterogeneity across well operations and costs. 
66

However, our analysis reflects operations across the U.S. related to flowback after hydraulic 

fracturing and is intended to be representative of the variety of flowback situations that will be 

encountered. The EPA therefore believes that the requirements overall are cost-effective and is 

not establishing provisions exempting specific wells on the basis of cost-effectiveness. 

2.2.3.5 Alternative Approaches if REC is not Cost Effective

Comment: One commenter (3618) requests the EPA to consider incorporating the following 

practices into the NSPS: a) Vapor Recovery Units- Equipment installed on condensate storage 

tanks that capture rather that vent vapors and b) Plunger Lifts- System using gas pressure in 

buildup in a well to lift a column of accumulated fluid out of the well to allow expected gas 

production. Two commenters (4189, 4275) state that liquids unloading and other well cleanup 

activities are the single worst source of methane emissions according to the EPA’s most recent 

greenhouse gas inventory. One commenter (4275) recommends covering liquids unloading by 

the reduced emission completion requirement under the final new rules. Another commenter 

(4316) expresses that it is already working with industry and DOE on providing a step-change 

cost reduction for a ultra-reliable electric downhole deliquification pump used in gas well 

deliquification.

One commenter (4162) cites sections of the proposed rule and comments that it does not 

consider how methane and other fugitive emissions can bypass the capturing systems. The 

commenter states that obtaining a quantity of marketable gas that can be sold is a powerful 

incentive for capturing fugitives, but the regulation should consider the potential for significant 

amounts of fugitive emissions to escape capture from these systems. The commenter asserts that 

the language does not set percentages or other numeric standards for recapturing amounts or 

regulate the natural gas emissions outside of recapturing, assuming that such processes are 

successful. The commenter attached a video to support their assertion that the industry is not 

sufficiently limiting the amount of leaks from drilling and processing operations and the full 

extent of those leaks both current and expected have not been adequately considered in this rule.

Response: The EPA clarifies that tank emissions are already covered under this rulemaking. In 

addition, the EPA clarifies that the final rule covers equipment leaks from onshore natural gas 

processing plants. Regarding well venting for liquids unloading, the EPA agrees with the 

commenter that liquids unloading may be a significant source of VOC emissions for existing 

conventional gas wells. The EPA conducted a preliminary screening of emissions sources in the 

development of this rule with the goal of maximizing emission reductions for new sources. 

Available information is not sufficient to evaluate whether emissions from liquids unloading is 

an issue for hydraulically fractured wells, which represent the majority of projected future 

production and new sources. Given this uncertainty, the EPA is not regulating liquids unloading 

at this time.
67

2.2.3.6 Exemption from Pit Flaring because of Proximity to Residences or Other Factors Make 

Pit Flaring Infeasible

Comment: One commenter (3475) suggests that pit flaring would be unrealistic in urban areas 

and not practicable during periods of drought. The commenter suggests that the rule include the 

ability to opt out of state oil and gas regulations when pit flaring is not feasible. One commenter

(4240) urges the EPA to tighten its venting exemption because the proposed wording would be 

vague. The commenter suggests the EPA revise §60.5375(a)(3) to require combustion except in 

conditions “that pose a material risk of fire hazard or explosion.” One commenter (4241) 

expresses support for the EPA’s proposed exemption to pit flaring under conditions that may 

result in a fire hazard or explosion. Further, the commenter recommends that the EPA broaden 

the conditions for exceptions to the pit flaring requirement. Specifically, the commenter suggests

that the EPA base the need for exemptions on engineering judgments that support venting.

Another commenter (3528) requests clarification on the pit flaring exemption. In particular, the 

commenter asks if the requirement would apply for all volumes or qualities of gas. Seven

commenters (4266, 4269, 4266, 4251, 4246, 4217, 4228) identify scenarios where the quality or 

quantity of the gas would affect flaring. The commenters suggest that the pressure and content 

(e.g., presence of nitrogen) make combustion infeasible. The commenters recommend that the 

EPA broaden in the regulatory text the conditions for exceptions to the flaring requirement. 

Specifically, one commenter (4251) suggests that the EPA base the need for exemptions on 

engineering judgment. Another commenter (4217) recommends that the EPA state in the 

regulatory text that venting is acceptable when the gas (1) does not meet sales quality, (2) will 

not sustain combustion, or (3) exhibits other technical properties that require venting to prevent 

well damage, well cleanup issues, or facility/production shutdown.

One commenter (4228) suggests that the EPA remove the requirement that non-flammable 

flowback gases be sent to a combuster. The commenter explains that this requirement would 

result in increased pollutant emissions and higher operating costs compared to venting the nonflammable flowback gas. In addition, the commenter requests that the EPA revise the rule text to 

require that completion combustion devices be equipped with a reliable continuous ignition 

source for the entire time flowback gases are directed to the combustion equipment, rather than 

over the duration of flowback.

One commenter (4266) requests that the EPA provide additional clarity in the rule to address the 

many operational and safety constraints to routing all salable gas to a gathering line. Another 

commenter (3562) urges the EPA to incorporate design requirements, work practice standards, 

and good combustion practices for pit flares in the regulations. One commenter (4240) urges the 

EPA to strengthen its flaring requirement to minimize emissions risks. The commenter 

recommends that the EPA require operators to document the reason that capture does not occur 
68

and venting or flaring occurs. The commenter also argues that the venting exemption is vague 

and the EPA should revise the rule language to require combustion except in conditions “that 

pose a material risk of fire hazard or explosion.” With regard to flaring, the commenter suggests

that the EPA require use of enclosed combustion devices where possible to reduce these 

pollutants. Another commenter (4269) indicates that the flaring requirements would impose a 

greater burden on smaller producers who are drilling conventional wells and maintaining 

marginal production.

Five commenters (4258, 3560, 4217, 4269, 4246) cite regional conditions as a concern that the 

EPA should consider in the rule. For example, these commenters explain that requiring pit 

flaring or other flaring could be dangerous in drought-stricken areas. One commenter (4217) asks

how the EPA would resolve conflicts between the rule requirements and burn bans from other 

Federal and State agencies. One commenter (4222) requests an exemption to allow venting in the 

Alaskan North Slope due to Alaska’s unique environment, or further study of the issue to 

understand the impacts of flaring on Alaska’s environment.

Response: The EPA agrees with the commenters and has clarified the combustion exemption.

Section 60.5375(a)(3) has been revised to state, “You must capture and direct flowback 

emissions that cannot be directed to the flow line to a completion combustion device, except in 

conditions that may result in a fire hazard or explosion, or where high heat emissions from a 

completion combustion device may negatively impact tundra, permafrost or waterways.

Completion combustion devices must be equipped with a reliable continuous ignition source 

over the duration of flowback.”

The EPA has also revised the VOC control requirement in §60.5375(a)(1) to state: “For the 

duration of flowback, route the recovered liquids into one or more storage vessels or re-inject the 

recovered liquids into the well or another well, and route the recovered gas into a gas flow line or 

collection system, re-inject the recovered gas into the well or another well, use the recovered gas

as an on-site fuel source, or use the recovered gas for another useful purpose that a purchased 

fuel or raw material would serve, with no direct release to the atmosphere.” In response to the 

commenter’s particular concern, the exemption applies to all volumes and qualities of gas. 

The EPA has considered the issue of venting flowback gas rather than capture or combustion. 

The purpose of this ruling is to minimize VOC emissions from hydraulically fractured gas well 

completion flowback. It is the operators’ responsibility to ensure the completion combustion 

devices are equipped with a reliable continuous ignition source over the duration of flowback 

and complete combustion of VOCs is occurring, except in conditions that may result in a fire 

hazard or explosion, in which case the control requirements allow for venting and documentation 

of the reasons and conditions that made the venting necessary.
69

The EPA does not agree with the commenter that this requirement would result in increased 

pollutant emissions and higher operating costs compared to venting the non-flammable flowback 

gas. The rule clearly indicates that completion combustion devices must be equipped with a 

reliable continuous ignition source over the duration of flowback and ensure complete 

combustion is occurring throughout the flowback. The EPA understands this may require 

additional fuel combustion to ensure complete combustion of the VOC but this requirement will 

achieve the EPA’s objective to minimize VOCs from all hydraulically fractured completions, 

excluding the times of a flowback when operator-documented reasons for venting are necessary.

2.2.4 Subcategory 2 Wells (exploratory and delineation)

2.2.4.1 REC is Not a Feasible Option

Comment: One commenter (4240) states that the proposed standard itself is dangerously 

unclear. The commenter states that the EPA’s proposed standard requires operators to 

“minimize” emissions by storing and then routing to pipelines as much recovered liquid and gas 

as possible, with the backstop of flaring or venting the remaining emissions, and to “minimize” 

releases to the environment. But, the commenter continues, it does not define what “minimize” 

means, or how the EPA will know when an operator is not “minimizing” in accordance with the 

standard. The commenter states that the EPA provides that resource recovery is to be “safely 

maximize[d],” it does not define that term either. The commenter further states that the EPA 

does not set any limit on how much gas may be flared, rather than captured, stating only that gas 

which “cannot be directed” to a gathering line is to be sent to flares. Similarly, according to the 

commenter, salable gas is to be routed to a gathering line as “soon as practicable,” a term that 

leaves considerable room for dispute, according to the commenter. The commenter believes that 

the EPA must tighten these definitional holes. The commenter recommends that the EPA resolve 

these problems by stating clearly that, except in the very narrow defined circumstances where 

safety considerations so warrant, all emissions from the wellhead must be either captured or 

flared, not vented, and that flaring is a disfavored secondary option, to be used only when it is 

not possible to capture the wellhead emissions for safety reasons. In doing so, the commenter 

asserts the EPA must avoid the use of the “maximize” and “minimize” terms which will 

otherwise cause substantial difficulties, according to the commenter, and it must do so by 

revising proposed §60.5375(a) to read as follows, in pertinent part, “... (1) You must capture all 

gases and liquids emanating from each well subject to these regulations at all times following 

perforation of the well casing until flowback has ceased. (2) You must route all recovered liquids 

into storage vessels and route all recovered gas into a gas gathering line or collection system, 

except as specified in paragraph (a)(3). (3) Where direction of recovered gases or liquids into 

storage vessels or gas gathering lines is not possible due to material safety hazards, you must 

direct these materials to a completion combustion device, except in conditions that pose a 
70

material risk of fire hazard or explosion. Completion combustion devices must be equipped with 

a reliable continuous ignition source over the duration of flowback.”

Response: The EPA disagrees that a definition for "minimize" and "maximize" are necessary 

since the well completions requirements are an operational standard and not an emissions limit. 

However, in order to provide clarity to these operational standards, we have removed the terms 

“minimize” and “maximize” from §60.5375(a)(1) and (a)(2), respecitively, and restated these 

requirements in the form of a general duty clause in §60.5375(a)(4).

Comment: One commenters (4216) states that the EPA’s definition of a natural gas well 

completion creates a significant inequity. The commenter states that the EPA applies its NSPS 

requirements to any natural gas well completion that uses hydraulic fracturing, and that this 

definition would capture natural gas well completions that include only a vertical component and 

wells with both vertical and horizontal components. However, the commenter asserts, it is clear 

that in developing its basis for its REC technology, the EPA bases its determinations on well 

completions with horizontal legs, yet, the EPA would require the same controls for vertical wells 

where the emissions would be far less. The commenter argues that requiring REC on all natural 

gas well completions makes no sense since while there can be similarities in fracturing 

treatments within a particular formation or depositional basin, there can be big differences 

between basins across the country. The commenter further states that virtually all of the nonconventional, horizontal completions use large-volume multi-stage hydraulic fracturing 

treatments, while most of the conventional, vertical well fracture treatments are relatively low 

volume, single stage events. Applying a one-size-fits-all standard to both types of wells is 

counterproductive, according to the commenter. Another commenter (4246) believes that the 

average cost per ton of VOCs reduction without sales could be 20 times greater than that 

estimated by the EPA. One commenter (3529) states that the EPA underestimated the cost of 

complying with the proposed rule because the cost of other equipment necessary to comply with 

the rule was not considered. of the RECs proposed by the EPA is significantly different than 

described by the EPA. Two commenters (4266, 4246) have provided estimated equipment and 

labor cost per well to do REC and state that the EPA grossly underestimates the cost. One 

commenter (4266) bases its conclusion of the EPA having a low cost estimate on its contention 

that REC equipment costs are incurred over a period of about 30 days per well completion and 

not just during the flowback days. Therefore, this commenter believes that it is more appropriate 

to represent the REC equipment costs as occurred over a 30 day period for each completion 

rather than the shorter number of days associated with the flowback.

Response: The EPA developed its cost estimate based on best available data and cost figures 

reported by industry. See Section 4.4.2.3 of the Technical Support Document. Though one 

commenter disagrees with the length of the REC rental period underlying the EPA’s analysis, the 

commenter did not include additional data or information to support this claim. The rule impacts 
71

analysis is intended to reflect the cost that the REC equipment for the purposes of complying 

with the rule, and the EPA has determined that assuming that the rental costs are only incurred 

for flowback period is appropriate for estimating REC costs. For vertical wells specifically, we 

believe that there are significant The VOC emissions from them which is why the affected 

facility definition includes all hydraulically fractured gas wells. Additionally, in the final rule the 

EPA is supplying a method to determine if a well is considered to be low pressure, in which case 

that well completion flowback is not required to perform gas capture for VOC control, and this 

reduces the cost burden for the so-defined low pressure wells.

2.2.5 Thresholds for Parameters to Define which Well Completions are Subject to REC 

Requirements

Comment: One commenter (3459) requests that the EPA extend green completions 

requirements to include new and existing oil wells that co-produce gas instead of only applying 

to gas wells. 

Another commenter (4240) expresses that the EPA needs to include hydraulically fractured oil 

wells that produce associated gas in its standards. These wells are excluded under the proposed 

standard, which applies only to gas wells. The commenter states that the EPA acknowledges that 

hydraulic fracturing at oil wells creates a period of flowback with increased natural gas and VOC 

emissions and requests that the EPA must require that the maximum amount of gas produced 

from hydraulically fractured oil wells during both flowback and normal production, be captured 

rather than vented or flared. The commenter provides information on how recent developments 

raise questions about the EPA’s estimates of low emissions from these wells. According to the 

commenter, the New York Times reports gas discharges of over 150 million cubic feet per day 

being flared in the Bakken Shale play in North Dakota that field regarding very large amounts of 

gas are being flared daily in the hydraulically fractured. The commenter states that this huge 

volume of flaring is undoubtedly producing significant air pollution, and is avoidable with RECs 

and connection to gas gathering lines. The commenter cites the report from North Dakota 

government that the commenter claimed very strongly argues that REC, and continuing gas 

capture from producing oil wells, would be economically and environmentally beneficial. The 

commenter recommends that although producers may have to focus on expanding gathering line 

construction to prevent this waste, other options, including reinjection, must be explored and 

requests the EPA to drive the process with a strong performance standard for such wells. The 

commenter adds that as a start, the EPA must require the productive capture and routing to a 

pipeline of vented associated gas at oil wells whenever natural gas gathering pipelines are within 

a reasonable distance that the commenter considers to be three miles to an affected oil well. The 

commenter states that if reinjection, productive use onsite, or capture for sale of gas cannot be 

required, then the EPA must ensure that emissions from flares are minimized.
72

One commenter (4266) states that based on the EPA’s discussion in Section 4 of the TSD, it 

appears the EPA’s intent is to require REC only for natural gas wells. However, the commenter 

believes that the rule needs to include “natural gas” versus “gas” throughout as API has proposed 

for clarity. The commenter supports that the EPA applied REC only to natural gas wellhead 

facilities and excluded oil wellhead facilities and other types of gas wells which have little or no 

VOC emissions. The commenter states that, as shown on page 4-13 on Table 4.4 “Nationwide 

Baseline Emissions from Uncontrolled Oil and Gas Well Completions and Recompletions” of 

the TSD, there are only 134 TPY of VOCs emissions from oil well completions and 

recompletions for the entire U.S., which is not worth regulating.

Several commenters (4192, 4246, 4266) have commented on the definition of gas well, providing 

recommended revisions. One commenter (4192) recommends the following revision: “Gas well 

means a well, the principal production of which at the mouth of the well is [add: hydrocarbon 

gas, not CO2]. . . .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.” One commenter (4246) proposes the following 

revision: “Gas well means a well, [DELETE the principal production of which at the mouth of 

the well is gas.] completed for production of natural gas from one or more gas zones or 

reservoirs. Such wells contain no completions for the production of crude oil. The commenter 

also proposes the following revision: Gas well means a well [STRIKETHROUGH: , the 

principal production of which at the mouth of the well is gas.] [ADD TEXT: completed for 

production of natural gas from one or more gas zones or reservoirs. Such wells contain no 

completions for the production of crude oil.]”

One commenter (4191) points out that Oil and Natural Gas Air Pollution Standards (ONGAPS) 

apply to oil and gas activities, but it is not clear whether the green completion requirement of the 

ONGAPS applies to wells producing condensate or crude oil. The commenter believes that the 

EPA should focus on emissions, as opposed to the constituent generating such emissions, and 

clarify that well producing condensate or crude oil are included within the ONGAPS. The 

commenter asserts that green completions may be a cost effective means of controlling emissions 

from “hybrid” oil and gas wells, while also reducing losses of a valuable domestic resource and 

recommends that the EPA clarify the inclusion of such wells within the NSPS. However, the 

commenter did not define the term “hybrid” in the comments submitted. One commenter (4275) 

recommends that emissions from existing and new oil wells that co-produce gas be included in 

the scope of the REC requirement because they can be significant sources of pollution and lost 

product that can be cost-effectively captured by RECs. Another commenter (4266) points out 

that §60.5375 never mentions “gas wellhead” which could be interpreted that all hydraulically 

fractured wells, gas AND oil, would be subject to these requirements.

Response: Section IX.B of the final rule preamble discusses the issues of the definition of “gas 

well” and coverage of oil wells by the NSPS. Because we are uncertain of the meaning of 
73

“hybrid” in the context of the public comments, we are unable to provide more clarity on 

treatment of these wells under the NSPS. 

Comment: One commenter (1443) requests that the EPA set and enforce strict regulations of the 

chemicals used in the fracking process and requests to require closed pits and strong under-pit 

linings for used water and chemical mixtures. Another commenter (3551) states that chemicals 

used in the hydraulic fracturing process may also contribute to sources of air quality impacts and 

until the EPA can provide information on the frequency, quantity, and concentrations of the 

chemicals used in the fracking process, a complete effective regulatory process air quality 

emissions remains unattainable. The commenter (3551) recommends that the EPA consider to 

analyzing the impacts of the chemical constituents used in fracking as a source of potential air 

quality contaminants.

Response: The EPA's Office of Research and Development is currently engaged in a major 

study of hydraulic fracturing, including the constituents of fracturing fluids. The results of this 

study are not yet available, so there is no information on air emissions from those fluids at this 

time that can be incorporated into this rulemaking.

Comment: One commenter (4164) states that subpart OOOO should not imply that “natural gas” 

is a regulated pollutant.

Response: The EPA clarifies that natural gas is not being regulated as a pollutant under the 

NSPS and that this action regulates VOC. The EPA based its VOC emissions on a methane 

emission factor combined with an average VOC emissions profile to quantify the impacts.

Comment: One commenter (4041) provides text from the recently amended oil and gas drilling 

and production ordinance for the City of Southlake, Texas. Citing the ordinance, the commenter 

suggests that the rule require a best management practice plan for reduced emission completions 

across a development area.

Response: The EPA has reviewed the requirements of the oil and gas drilling and production 

ordinance for the City of Southlake, Texas, and the EPA disagrees that a best management 

practice plan should be implemented. The EPA has considered this comment when finalizing the 

rule in a manner that does not prescribe the equipment required to control VOC. The final rule 

states an operational standard to reduce VOCs and does not specify control equipment, because 

the VOC control situation may vary from well to well and across U.S. regions. The EPA has 

addressed the commenter’s statement about a management system approach because the rule 

includes flexibility for achieving the operational standard.
74

In addition, the EPA believes the current recordkeeping and reporting requirements satisfactorily 

accomplish the same goals as the continuous monitoring plans included in the oil and gas drilling 

and production ordinance for the City of Southlake, Texas. Moreover, the EPA is not exempting 

wells based on the sole point that a flow line is not available as discussed elsewhere in this 

response to comments. Lastly, the EPA is regulating emissions from hydraulically fractured well 

completions and not the associated equipment required to perform RECs. 

Comment: One commenter (4135) suggests that the EPA modify the definition of a “wellsite” to 

specify that a wellsite may consist of one or more wells. The commenter states these types of 

multiple well wellsites may be referred to as PAD facilities, multiple well facilities, double well 

facilities, etc.

Response: The EPA clarifies that the final rule states that the affected facility is defined as, 

“Each gas well affected facility, which is a single natural gas well.” We further clarify that the 

overall well site is not the affected facility. The EPA has defined a well site as, “one or more

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.”

Comment: One commenter (4266) requests that the applicability of the proposed regulation to 

“flowback immediately following hydraulic fracturing stimulation at onshore gas wellhead 

facilities” should be clearly defined in §60.5365(a). The commenter believes that the following 

portion of the text is unnecessary and should be eliminated: “For the purposes of this subpart, a 

well completion operation following hydraulic fracturing or refracturing that occurs at a gas 

wellhead facility that commenced construction, modification, or reconstruction on or before 

August 23, 2011 is considered a modification of the gas wellhead facility, but does not affect 

other equipment, process units, storage vessels, or pneumatic devices located at the well site....” 

The commenter agrees that the text should clarify that other equipment, such as process units, 

storage vessels, pneumatic controllers, and compressors located at the well site are not affected 

by hydraulic fracture flowback operations. 

Response: The EPA has clarified the definition of a modification so that this regulation only 

pertains to the intended emissions sources.

Comment: One commenter (4192) recommends that the EPA add a new defined term, 

“produced water,” as follows: “Produced water is water from underground formations that is 

brought to the surface during oil or gas production. The produced water has gone through some 

means to remove it from other stream brought up from the formation.” The commenter adds that 

the definition is from the publication “Produced Water Volumes and Management Practices in 

the United States,” Argonne National Laboratory –ANL/EVS/R-09/1.
75

Response: The EPA disagrees that a definition for "produced water" must be added because the 

EPA believes the definition is immaterial to the affected facility and the VOC emissions being 

controlled.

Comment: One commenter (3474) asserts that environmental protection and economic growth 

need not be a zero sum game, supports the increased use of green completions, states that RECs 

are a proven, economical way to reduce methane emissions, and encourages industry-wide, 

voluntary adoption of this practice. Another commenter (4042) commends the EPA for this 

proposal, especially the requirement for Reduced Emission Completions for newly fractured 

wells or re-fracturing of existing wells. Another commenter (4266) states that API and its 

member companies fully support the EPA’s goals of minimizing VOC emissions from flowback 

immediately following hydraulic fracturing stimulation and have been among the earliest 

companies to adopt such measures; the commenter notes that REC make sense in many but not 

all scenarios. 

Response: The EPA appreciates these comments. The EPA conducted detailed analyses and 

conducted extensive research of best available data and information to develop requirements that 

cost-effectively reduce harmful air pollution from the oil and natural gas industry while allowing 

continued, responsible growth in U.S. oil and natural gas production. In regard to comments on 

REC applicability, the EPA has finalized operational standards for completion of hydraulically 

fractured gas wells that will effectively reduce emissions where it is technically feasible and safe 

to do so. 

2.2.6 Other Comments

Comment: One commenter (4208) requests that the EPA clarify the appropriate baseline for 

determining modifications. The EPA does not indicate the baseline a source should use in 

determining whether the recompletion or refracturing increases the amount of VOCs or natural 

gas emitted in the atmosphere. For example, the commenter notes that a well can be refractured 

approximately every three years but the operator may use a five-year baseline for determining 

existing emissions. In that case, the commenter asserts that a new refracturing might not cause 

any emission increases over the emissions baseline, since the baseline reflects the first 

refracturing. Thus the source would claim that the refractured well did not meet the definition of 

“modification.” The commenter indicates that the EPA should specify in the regulatory preamble 

that sources, in determining whether there were any increase in emissions, use as their baseline 

the emissions from the existing gas well occurring immediately before the recompletion or 

refracturing.
76

Two commenters (4220, 4240) express concern that the proposed rule departs from a longstanding definition of modification without explanation and presumably under the new proposed 

definition, a change that results in any measurable increase not just of VOC, a regulated NSR 

pollutant, but natural gas, a non-regulated substance, would ostensibly be considered a

“modification” for NSPS purposes. Both commenters ask why there is disparate treatment for the 

oil and natural gas production source category and state that the EPA has effectively denied 

stakeholders adequate notice of the intended scope of this change to the presumptive definition 

of “modification” in 40 CFR §60.14.

Response: See section IX.A of the final rule preamble.

Comment: One commenter (4209) cites the EPA’s proposed definition of modification and does 

not believe the EPA has adequately justified how it can regulate recompletions as modifications. 

Another commenter (4209) asks how the EPA’s own definition allows the regulation of recompletions or re-fracturing operations of an existing formation within a gas wellhead facility 

when the initial production volumes may have been higher than subsequent re-completions or refracturing operations because the formation has been depleted by production activities. 

Commenter 4220 states that the proposed definition of “modification” is a significant departure 

from the EPA‘s existing definition of “modification” in 40 CFR § 60.14, which defines 

“modification” in terms of an increase in “emission rate,” a concept that, with few exceptions, 

has provided industry with a clear and measurable standard to determine whether NSPS review is 

triggered and provided how the concept was explained by the EPA in a prior rulemaking. In 

addition, commenter 4220 states that even more significant is that the EPA redefines NSPS 

modification by adding a new term – “amount of emissions” – where previously the emissions 

test was based on the maximum achievable hourly rate of emissions for determining whether a 

modification would occur. According to the commenter, there is no explanation in the proposal 

as to whether this change is intentional, the basis for such a change if it is intentional, and how 

the “amount” of emissions would be measured. Commenter 4220 explains that the EPA cannot 

upset 30 years of precedent on the definition of modification without at least providing explicit 

notice and explaining its basis for doing so. The commenter asserts that the public simply cannot 

reasonably participate in the rulemaking process with this inadequate notice. Moreover, the 

commenter believes that such a departure is substantively inappropriate. The commenter 

continues by saying that measuring the “actual amount” – if that is what is intended – of the 

pollutants is impractical and unreasonable because the EPA has explained that a work practice 

standard is justified here on the grounds that measuring emissions during these periods is not 

feasible. 76 FR 52758.

Three commenters (4220, 4273, 4251) provide detailed explanation of the basis for the following 

statements: 1) The proposed definition of ”modification” unreasonably and arbitrarily assumes 

certain operations such as ”recompletions” and ”workovers” are modifications on the basis of 
77

assumed and unsubstantiated emission changes, 2) Workovers should not be included in the 

definition of modification because they are not physical or operational changes and do not result 

in an emissions rate increase, 3) Recompletions and refracture activities should not be included 

in the definition of modification, and 4) Even if recompletions could be modifications, the EPA 

must clarify that the proposal includes only recompletions that occur at the same time as 

hydraulic fracturing. Commenter 4251 indicates it is debatable whether a recompletion would 

constitute a “change” since it has been termed by the EPA as simply maintenance. 

Response: See section IX.A of the final rule preamble.

Comment: One commenter (4251) states that when a well is recompleted, it would be located at 

a site that already has viable gathering and sales lines. The commenter contends that the presence 

of this infrastructure means that gas from a recompleted well is recovered and routed to a sales 

line for maximum profit, meeting the EPA's definition of a REC, and the amount of VOCs 

emitted would be de minimis, if any at all and that regulation that requires onerous notification, 

record keeping, and reporting of this routine business practice creates an unnecessary cost burden 

on operators with no human health or environmental benefit.

Response: We appreciate the commenter’s view that recompletions are often performed in areas 

where a flow line is available, and that RECs are performed on some portion of these 

recompletions. Based on public comments and reports to EPA's Natural Gas STAR program, 

EPA recognizes that some producers conduct well completions using REC techniques 

voluntarily for economic and/or environmental objectives as a normal part of business. To 

account for emissions reductions and costs arising from voluntary implementation of pollution 

controls EPA used information on total emission reductions reported to the EPA by partners of 

the EPA Natural Gas STAR. This estimate of this voluntary REC activity in the absence of 

regulation is also included in the baseline. More detailed discussion on the derivation of the 

baseline is presented in a technical memorandum in the docket, as well as in the RIA.

Comment: One commenter (4240) states that there is a definitional flaw in the EPA’s proposed 

language for modification; first the commenter cites the CAA “modification” definition under 

section 111. The commenter indicates that the EPA points out in the proposed rule and TSD that 

during the fracturing or refracturing of an existing well, “physical change occurs to the existing 

well, which includes the wellbore, casing and tubing, resulting in an emissions increase during 

the completion operation.” The commenter continues, saying that for purposes of NSPS, an 

emissions increase occurs whenever emissions after a physical change are greater than emissions 

immediately prior to the change and cites Wisconsin Electric Power Co. v. Reilly. Further, the 

commenter says that not only do hydraulic fracturing activities meet the statutory definition of 

modification, but the EPA’s proposed NSPS that recompletions of these wells are modifications 

for the purposes of this industry overrides any conflicting provisions in the general NSPS 
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definition of modification. According to the commenter, the EPA previously has relied on 

§60.14(f) to depart from its general regulatory definition of modification by delineating what 

constitutes a modification under a sector-specific subpart of the NSPS “to eliminate ambiguity.” 

Thus, to the extent that any of the exemptions contained in §60.14(c) would otherwise prevent 

recompletions and refracturing from being considered modifications, they would be overridden 

by the specific oil and gas provision. The commenter states that, while the proposed §60.5430 is 

sufficient to override any conflicting portions of §60.14, they encourage the EPA to clarify the 

regulatory language by explicitly invoking §60.14(f) and explaining that the capital expenditure 

test codified at 40 C.F.R. §60.14(e)(2), for example, does not apply. Second, according to the 

commenter, the EPA is wrong to define a modification in this context as “each recompletion of a 

fractured or refractured existing gas well” because “recompletion” is an undefined term and so 

will lead to confusion. The commenter states that the relevant modification – and source of 

increased emissions – in this context is, in fact, the hydraulic fracturing operation at the well. 

The commenter requests that the EPA say so. Commenter 4240 proposes a revised §60.5430: 

Modification means any physical change in, or change in the method of operation of, an 

affected facility which increases the amount of VOC or natural gas emitted into the 

atmosphere by that facility or which results in the emission of VOC or natural gas into 

the atmosphere not previously emitted. For the purposes of this subpart, each hydraulic 

fracturing operation at an existing gas well is considered to be a modification regardless 

of any provision of 40 C.F.R. §60.14(e) stating regulatory exemptions to the term 

“modification.

One commenter (4266) states that “modification” should apply to flowback of a recompletion 

immediately following hydraulic fracturing that has a reasonable expectation to be greater than 

the original completion. According to the commenter, wells that are recompleted within the same 

reservoir/zone that was previously hydrofractured will necessarily have fewer emissions than 

previously experienced due to the depletion of reservoir pressure. However, the commenter 

asserts that a well that is recompleted in new reservoir may have more or less emission than in 

original completion operations. The commenter states that, by including recompletion in the 

definition of modifications, the EPA has exceeded the intent of the CAA. The commenter opines 

that the definition of modification should remain under §60.14. However, the commenter 

recommends that, if the EPA chooses to define modification in this subpart, the recompletions 

portion of the definition of modification should be removed. Commenter 4266 provides two 

suggested rule text revisions for §60.5430.

1. Preferred Option: 

[STRIKETHROUGH: 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 
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VOC or natural gas into the atmosphere not previously emitted. For the purposes of this 

subpart, each recompletion of a fractured or refractured existing gas well is considered to 

be a modification.] 

2. Alternative option: 

Modification means any physical change in, or change in the method of operation of, an 

affected facility which increases the amount of VOC [STRIKETHROUGH: or natural 

gas] emitted into the atmosphere by that facility or which results in the emission of VOC 

[STRIKETHROUGH: or natural gas] into the atmosphere not previously emitted. 

[STRIKETHROUGH: For the purposes of this subpart, each recompletion of a fractured 

or refractured existing gas well is considered to be a modification.]

Response: See section IX.A of the final rule preamble.

Comment: Eight commenters (1369, 1498, 1519, 1375, 1396, 1467, 1496, 1498) express 

concern about air and water pollution and health risks from fracturing operations. Five

commenters (1369, 1498, 1519, 1375, 1467) express mistrust of information provided by oil 

companies implying that fracturing poses little to no risk or actual pollution. Some of these 

commenters (1498, 1519, 1375, 1396) also cite personal experience or media vehicles, such as 

movies and articles, to assert dangers and damage associated with fracturing. One commenter 

(1496) asserts that the extraction industries should pay the full cost of their business practices, 

including associated adverse impacts. Two commenters (1491, 1496) request that the EPA 

conduct further studies to determine the impacts from fracturing before allowing the practice to 

continue and emphasize the importance of transparency of that information. 

Response: The EPA acknowledges these commenters’ concerns regarding potential air and 

water pollution and health risks from hydraulic fracturing. The EPA views natural gas as having 

an important role in our country’s clean energy future, and this rule will reduce harmful air 

pollution from the oil and natural gas industry while allowing continued, responsible growth in 

U.S. oil and natural gas production. At most fractured natural gas wells, the rule requires 

producers to capture a high volume of natural gas that contains VOCs and methane, along with 

air toxics such as benzene, ethylbenzene and n-hexane by using REC. 

In its FY2010 Appropriations Committee Conference Report, Congress requested that the EPA 

study the relationship between hydraulic fracturing and drinking water, using the best available 

science, independent sources of information, and to conduct the study in consultation with others 

using a transparent, peer-reviewed process. The EPA announced in March 2010 that it would 

conduct a research study to investigate the potential impacts of hydraulic fracturing on drinking 

water resources. This study is intended both to provide data where there is inadequate 

information and to contribute to resolving scientific uncertainties. A first report of results is 

expected by the end of 2012. However, certain portions of the work will be long-term projects 
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that are not likely to be finished at that time. An additional report of study findings will be 

published in 2014 as the longer-term projects progress.

2.3 Pneumatic Controllers

2.3.1 Compliance Options and Compliance Schedule

Comment: One commenter (4219) believes that the continuous compliance demonstration 

requirements for low-bleed pneumatic controllers should be limited to a demonstration that the 

controller was properly installed and is being properly maintained. The commenter states that 

this requirement would not be overly burdensome to industry.

Response: The EPA provides guidance rather than exact conditions that define proper 

maintenance to demonstrate continuous compliance, and the final rule relies on the application of 

manufacturers' specifications to document bleed rate.

Comment: A commenter (4263) recommends revising §60.5410(d)(3) to provide for cases 

where facilities other than gas plants operate pneumatic controllers using air or other gas other 

than natural gas. The commenter’s rationale for this is that pneumatic systems driven other than 

by natural gas (e.g., air or other inserts) are used at facilities other than natural gas processing 

plants (e.g., compressor stations).

Response: The commenter is recommending revisions to the proposed rule to provide for 

facilities other than gas plants to operate pneumatic controllers using air or gas other than natural 

gas. The EPA clarifies that the rule specifies a natural gas bleed rate limit rather than use of a 

technology meeting specific “low-bleed” criteria. Therefore, as long as the pneumatic controllers 

are below the rule’s bleed rate for the specified affected facility (i.e., an affected facility located 

in either the production or processing segment), then the use of air or gas other than natural gas 

is permitted.

Comment: One commenter (4246) believes that, in lieu of requiring new controllers at gas 

processing plants to be on air assist the day of startup, owners or operators should have the 

option to convert all controllers in the gas processing plant to air assist (except for those 

exempted as per 40 CFR §60.5390(a)) no later than 3 years after the date of installation and 

startup of the first new controller, provided that all new controllers installed at the plant are lowbleed or exempted during the 3-year transition to compliance.

Response: The commenter did not provide supporting information explaining why non-gas 

driven controllers cannot be readily used at gas processing plants or why implementing 

instrument air would require three years. Based on the information available to the EPA, most 
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gas processing plants are equipped to use instrument air pneumatic controllers. We further note 

that the NSPS provides exemption from the zero bleed rate limit if there is a functional need for 

gas driven controllers. In light of the above, we do not believe that a three-year transition period 

is warranted.

2.3.2 Proposed Emission Limit for Processing Plants

Comment: One commenter (4228) states that residue natural gas-driven pneumatic controllers 

should be permitted at gas processing plants. According to the commenter, the EPA’s data show 

that the VOC content of processing plant residue gas is about an order of magnitude lower than 

plant feed gas (i.e., field gas); thus, a rule requirement that all gas plant pneumatic controllers be 

powered by residue gas rather than field gas would provide VOC emissions control without 

requiring each new plant to install and maintain costly air compression equipment. The 

commenter believes that, at a minimum, the rule should include an exception to allow gas plants 

to use natural gas-driven pneumatic controllers for emergency plant shut down and subsequent 

start up. The commenter notes that air driven devices require an air compressor and, if the plant 

loses power during an emergency, then compression could be lost; thus, a reliable alternative to 

gas-powered controllers, is needed for safe plant operation during an emergency.

Response: The EPA disagrees with the commenter and is not exempting pneumatic controllers 

that process residue gas in the final rule. Our analysis showed that BSER for pneumatic 

controllers at natural gas processing plants is zero emissions of natural gas, which would also 

mean zero emissions of VOC. Even if the commenter is correct that residue gas has a lower VOC 

content than field gas, the use of residue gas would still result in emissions of natural gas and 

VOC. This would not meet BSER; therefore, operating pneumatic controllers at processing 

plants with residue gas cannot be allowed.

Concerning the comment on emergency situations, our data show that processing plants are large 

facilities that typically have backup electrical systems in case of emergency. Thus, there should 

be no need for an exemption for emergency shutdown and startup. We do point out, however, 

that the final rule does provide a functional exemption from meeting the bleed rate limit for 

reasons such as safety, response time and actuation.

2.3.3. Proposed Emission Limit for Production, Transmission and Storage

Comment: One commenter (4246) states that for pneumatic controllers not located at a natural 

gas processing plant, that are (1) designed for continuous, gas-assisted, high-bleed and (2) that 

require immediate replacement or reconstruction due to an emergency situation, the EPA should 

allow immediate replacement with a like-kind or reconstructed controller for a six-month period. 

After which, the commenter states the owner/operator would be required to replace the 
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pneumatic controller with one that complies with subpart OOOO, or submit a demonstration to 

the Administrator that a high-bleed controller is necessary.

Response: The EPA has considered the commenter’s request to include a six-month period due 

to emergency replacement situations. Based on the EPA's understanding that pneumatic 

controllers meeting the bleed rate limit at processing plants are readily available and serve a 

variety of control functions, the EPA expects that the rule can be met in cases of emergency 

replacement. Furthermore, processing plants have a zero bleed rate limit with provisions for the 

use of pneumatic controllers that exceed the zero bleed rate limit when certain functional 

considerations are met. The EPA expects that new sources coming into existence due to 

emergency replacement will have a zero bleed rate limit or will meet a functional exemption as 

specified in the final rule.

Comment: One commenter (4234) states that the EPA should clarify that the proposed rule 

would not apply to pneumatic devices used in distribution or for a gas utility’s LNG peak 

shaving operations. Alternatively, to focus subpart OOOO more appropriately on natural gas 

streams that are more likely to include VOCs and avoid regulation of pneumatic controllers 

dispersed along pipelines as well as in distribution systems, the commenter suggests this affected 

facility description could be revised to limit applicability to pneumatic controllers located from 

the wellhead through the gas processing plant (or custody transfer to natural gas transmission if a 

gas processing plant is not present).

Response: The final rule applies to continuous bleed natural gas driven pneumatic controllers in 

the production and processing segments. Pneumatic controllers in the transmission and storage 

and distribution segments are not affected facilities in the NSPS. See section IX.C of the final 

rule preamble.

2.3.4 Low Bleed Devices

Comment: One commenter (4275) states that the EPA should require additional pollution 

reductions from existing pneumatic devices.

Response: Section 111(b) of the CAA 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. Thus, the EPA does not have the authority under section 111(b) to extend the rule 

to existing sources, until the existing sources undergo a modification or reconstruction that 

triggers an NSPS standard.
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2.3.5 Other Comments

Comment: One commenter (4228) claims that the EPA has overstated the reduction analysis for 

production segment pneumatic controllers as the analysis does not consider current industry 

practices that reduce emissions. The commenter also questions the EPA’s use of the production 

segment gas composition and VOC content to estimate emissions in the processing segment. The 

commenter states that, based on industry practice, the transmission segment gas composition and 

VOC content would provide a more accurate VOC reduction estimate.

Two commenters (4104, 4270) argue that emissions reduction estimates are overstated and the 

analysis provided is based on invalid data. The commenters note that the data sources used to 

estimate VOC emissions reductions are flawed, and actual VOC reductions will be much lower. 

One commenter (4104) notes that the data used to estimate the VOC emissions reductions from 

using a low-bleed rather than high-bleed pneumatic controller is based on a limited data set of 

pneumatic controller population from a handful of sites and a few manufacturers, rather than 

considering the cross section of industry segments, operating companies, and controller 

manufacturers. 

One commenter (4104) reasons that the EPA’s VOC estimates for the transmission and storage 

segment are overestimated because the EPA included VOC emissions reductions that result from 

standard industry practices that already occur due to safety, economy, and best practice 

considerations. The commenter argues that the failure to consider incremental reductions from 

actions above and beyond current practices overestimates the VOC reductions. 

Another commenter (4270) argues that the emission factors for compressors and pneumatic 

controllers, and the premise for the entire proposed rule, is based on invalid assumptions. The 

commenter states that the EPA made the following assumptions: that the proposed action will be 

supported by forthcoming data; that the emission factors used to calculate data in subparts 

OOOO and HHH is valid (when in fact, it is outdated); that the cost and benefits analysis is valid 

based on questionable emissions factors; and that the data is sufficient for the discussion and 

further analysis put forth in part VIII of the preamble to the proposed rule.

Two commenters (4104, 4158) argue that the VOC emissions from pneumatic devices and 

compressors, when further analyzed, would be trivial and not worth the regulatory burden 

proposed. One commenter (4101) notes some statistics and states that the EPA’s estimated 

subpart OOOO reductions from pneumatic controllers in transmission and storage are 0.000046 

percent of the total anthropogenic VOC inventory or 0.00001 percent of biogenic and 

anthropogenic VOC emissions. 
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One commenter (4104) argues that some of the data captured in the EPA’s emissions analysis 

includes VOC reductions taking place due to current industry standards and, therefore, the VOC 

emissions reductions attributed to the proposed rule would be incremental VOC emissions 

reductions. The commenter claims incremental natural gas VOC emissions reductions that 

directly result from subpart OOOO would be small and the least cost-effective reduction 

opportunities. The commenter remarks that codifying these on-going, standard industry practices 

would unnecessarily increase the administrative costs of such practices. The commenter also 

states the EPA’s cost-benefit analysis should be based on incremental, regulatory-driven 

emissions reductions and not include reductions achieved through current industry practice. One

commenter (4158) states that, within the transmission and storage segment, the VOC content in 

natural gas translates to an insignificant bleed-rate from pneumatic controllers.

Response: Regarding the commenter’s questioning of the use of the production segment gas 

composition for the processing segment, the EPA believes this composition more accurately 

describes the amount of VOCs in processing segment gas streams, not the transmission segment 

gas composition. Gas in the transmission segment is lower in VOC content because the gas has 

already gone through treatment processes which remove VOCs. Regarding commenters’ 

concerns that the proposed rule’s emissions reduction estimates are overstated and based on 

invalid data, the EPA has incorporated best available public data and documentation on industry 

practices for reducing the bleed emissions from pneumatic controllers. The approach, 

methodologies, and sources used by the EPA are summarized in Section 5.0 of the proposal 

TSD. Another commenter claims the EPA overestimates VOC estimates for the transmission and 

storage segment because emissions reductions that already result from standard industry 

practices are included. With regards to the regulation of pneumatic controllers in the 

transmission and storage segment, the EPA is revising the requirements to apply to affected 

facilities located between the wellhead and a natural gas processing plant, as well as affected 

facilities at natural gas processing plants. Pneumatic controllers in the transmission and storage 

segment are not affected facilities.

With regard to the comments on the minimal amount of VOCs in emissions from pneumatic 

devices, the EPA disagrees. A summary of the estimated VOC emissions is in Table 5-2 of the 

TSD, with an outline of the data sources used in Table 5-1. This summary depicts the significant 

VOC impacts achieved through this rulemaking and addresses the issue raised by the comments. 

A commenter claims the EPA overestimates the reductions for pneumatic controllers in the 

production segment because it did not consider current industry practices for reducing emissions. 

The EPA did consider current industry practices and the emissions limit in the final rule is based 

on the EPA’s understanding of widely available technology updates for pneumatic controllers. In 

part of the EPA’s research for the impact analysis, it characterized the costs of higher and lower 

emitting pneumatic controllers per what is currently available in industry. The costs used in this 
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proposed rule are estimated using recent comprehensive vendor research in combination with 

population factors from the U.S. inventory. The EPA explains its methodology for calculating 

VOC emissions and reductions in Sections 5.3 and 5.4 of the proposal TSD. The EPA used 

established and published sources on methane emissions and used a VOC weight ratio, 

calculated from a literature review of available sources, to convert to VOC emissions. This 

investigation can be found as a memo in the rule docket.

In addition, as described in Section IX.C of the preamble, the EPA is defining the pneumatic 

controller affected facility as a continuous bleed natural gas driven pneumatic controller with a 

bleed rate greater than 6 scfh. In response to the comments on increased administrative costs and 

current industry practice, the revised definitions exclude from the NSPS coverage owners and 

operators who are already using (including replacement) pneumatic controllers that meet the 

applicable standards, thus, relieving them from the cost and other burdens related to compliance.

Comment: A commenter (4191) suggests a revision to specific text in the proposed rule. The 

commenter notes that the reference to §60.5490(a) in the initial compliance requirement is a 

typographical error as there is no §60.5490 in subpart OOOO. 

Response: The EPA has corrected this typographical error.

2.4 Compressors

Comment: Two commenters (4175, 4268) believe that the Natural Gas STAR program is not 

suitable for mandatory widespread use in the oil and gas industry. The commenters state that the 

Natural Gas STAR program attempts to instigate a pro-active maintenance approach whereby the 

leakage on the seals is monitored and the seals replaced when the value of the gas lost exceeds 

the cost of the replacement seals. The commenters state that the program is not suitable for 

several reasons including: the value of the gas savings is overstated, the beneficiary of the gas 

savings may not be the same entity that bears the cost of seal replacement, the majority of 

facilities are remote and unmanned, and the program is duplicative for reciprocating compressors 

and would provide no significant benefit over a reasonable proactive replacement schedule. The 

commenters believe that if the EPA is intent on utilizing a program similar to the STAR 

program, it should be voluntary and exempt the operator from the 26,000 hour replacement 

interval. One commenter (4159) notes that it appears that some proposed NSPS requirements 

may be based on preconceived notions from the STAR program and not substantiated by a 

thorough cost-benefit analysis. The commenter states that codifying existing, prevalent practices 

in an NSPS is neither necessary nor cost effective, as the administrative aspects of complying 

with the rulemaking will add cost without any additional environmental benefit.
86

Response: The EPA used data from the Natural Gas STAR program as well as a variety of other 

sources to estimate emissions from reciprocating and centrifugal compressors, determine 

appropriate control techniques, and estimate the costs of those controls. We documented the data 

sources we used in the compressor analyses in the TSD for the proposed rule. Additionally, we 

documented our data sources in additional compressor analyses in the Supplemental TSD for the 

final standards. While the Natural Gas STAR program was one source of data, it was by no 

means the only source we relied upon. Since the commenters did not specifically point out which 

Natural Gas STAR data they believed were inaccurate and did not provide additional data for the 

EPA to evaluate, we made no changes in response to these comments.

Comment: One commenter (4263) suggests that the EPA exclude centrifugal compressor 

facilities that compress natural gas that is less than 10 percent, weight basis, VOC. The 

commenter asserts that compression of gas that does not contain VOC (propanes plus) should not 

be subject to standards for VOC. The commenter states that this is consistent with equipment 

leak rules which do not regulate components that are not in VOC service. The commenter also 

argues that due to low VOC content, the Agency should exclude centrifugal compressors in the 

T&S sector located after the point-of-custody transfer. Another commenter (4270) states that the 

EPA should suspend rulemaking and expand its fact-finding to include a statistically significant 

sampling of affected sources. Another commenter urged the EPA to revise §60.5365 to exclude 

centrifugal compressors not associated with the Crude Oil and Natural Gas Production, 

Transmission, and Distribution sector (4270).

Response: The EPA acknowledges that the VOC concentration in natural gas can vary across 

centrifugal compressors in different industry segments and within each industry segment. With 

respect to the suggestion that the EPA develop a specific threshold for VOC concentrations and 

exempt compressors below such threshold, the EPA determined that the information provided by 

commenters is not sufficient to warrant a change in the EPA’s VOC emissions estimates or to 

develop a VOC threshold that can be applied universally. 

The EPA has however revised the final rule requirements for compressors to apply to the 

production segment and the natural gas processing segment. The EPA has revised the 

centrifugal compressor affected facility in the final rule to be wet seal centrifugal compressors 

located between the wellhead and the point at which the gas enters the transmission and storage 

segment. Thus, centrifugal compressors with dry seals are not affected facilities. Compressors 

located at the wellhead and located in the transmission and storage and distribution segments are 

not affected facilities. We acknowledge the commenters concerns about low VOC emissions and 

potentially high burden in this segment. The EPA has concluded that additional evaluation of 

these compliance and burden issues is appropriate prior to taking final action on pneumatic 

controllers in the transmission and storage segment. See section IX.D of the final rule preamble 

for further details. 
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Comment: One commenter (3552) requests that the EPA include measures to control emissions 

from compressor station blowdowns. The commenter argues that several cost-effective control 

measures exist, such as installing automatic engine control systems, keeping engines pressurized 

during shutdowns, routing the blowdown vent to the fuel gas system, and installing static seals to 

prevent rod packing leaks.

Response: Under CAA section 111, the EPA has 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 performance standards for those affected 

facilities. The EPA is therefore not required to address every single emission source of a listed 

source category. In any event, with respect to compressor station blowdowns in the development 

of the proposed rule, the EPA conducted a preliminary screening of oil and gas emissions 

sources. The EPA’s analysis showed that total compressor blowdown emissions are significantly 

lower on a national level than the other new sources the EPA is regulating under this action. The 

commenter did not provide information that contradicts EPA’s preliminary screening.

Comment: One commenter (4184) states that in §60.5420(b)(4)(ii) the rule incorrectly cites the 

rod packing replacement interval as being 24,000 hours when it should be 26,000 hours, as 

specified in §60.5385(a).

Response: The EPA appreciates the commenter’s observation. The EPA intended for the rod 

packing replacement interval to be 26,000 hours and has corrected the text in §60.5420(b)(4)(ii).

Comment: Two commenters (4246, 4192) suggest replacing “if it is located at an onshore 

natural gas processing plant” with “if it is part of a process unit at an onshore natural gas 

processing plant” to exclude equipment unrelated to natural gas processing but co-located within 

the plant boundary from subjecting the natural gas processing plant to subpart OOOO, 

particularly for pneumatic controllers.

Response: The EPA does not agree with the commenters. The EPA does not intend to include 

equipment unrelated to natural gas processing but co-located within a gas processing plant 

boundary under the rule. The EPA is not aware that this is a significant issue. In addition, the 

commenter did not provide sufficient detail to further evaluate the language in the rule.

2.4.1 Applicability

Comment: Four commenters (4192, 4252, 4266, 4268) are proponents of a 43,800-hour 

standard. In support of this interval, two commenters (4246, 4252) note the EPA’s assertion in 

the NPRM preamble that rod-packing rings might last as long as five years without replacement, 

and argue that a five-year timeframe better represented the commenter’s experience as an 
88

appropriate lifetime for rod packing. The commenters observe that the typical cycle for such 

operations is five years, and that a 43,800-hour/5-year replacement cycle would best maintain 

standard industry practices and cost-effectiveness. Two commenters (4209, 4219) not opposed to 

having an hours-based standard simply suggest more than 26,000 hours as the appropriate 

interval. One commenter (4233) argues simply for a 5-year maintenance interval, offering no 

suggestion on an hours-based interval. Two commenters (4251, 4226) who oppose an hoursbased requirement nevertheless offer different intervals for rod packing replacement should the 

Agency decide to keep such a standard. One of these commenters (4226) says the interval should 

be 40,000 hours at a minimum, based on the company’s experience. 

One commenter (4227) says the Agency should permit owners and operators to demonstrate 

compliance by replacing the rod packing within a designated period (e.g., three to five years). 

This commenter asserts that such flexibility would not lessen the rule’s effectiveness, most likely 

would result in more frequent packing replacement than the hourly operational requirement, and 

would reduce the regulatory burden of hourly monitoring. The commenter offers language 

reflecting this suggestion, noting also that changing to a yearly replacement requirement would 

be similar to management practices for NESHAP area sources under subpart ZZZZ. 

Five commenters (4104, 4228, 4229, 4264, 4265) not opposed to having an hours-based standard 

variously suggest 35,000 or 43,800-hour intervals. Proponents of the 35,000 hour standard state

that the 35,000 hour interval is consistent with a four-year maintenance schedule that better 

represented operator experience and practice, is within the range of replacement intervals the 

EPA identified in the preamble, and is within the Natural Gas STAR Lessons Learned document 

the EPA cited.

Response: The EPA is maintaining the the rod packing replacement period in the final rule. The 

TSD for the proposed subpart acknowledges in its cost impacts analysis for reciprocating 

compressors that gathering and boosting compressors and processing compressors operate for 

only a fraction of the year, and therefore may replace their rod packing at intervals longer than 3 

years if the operating hours for the compressor are monitored. For additional flexibility, we are 

providing in the final rule that operators may change rod packing every 36 months in lieu of 

monitoring hours of operation. Also, commenters did not provide additional operational data for 

the EPA to further evaluate the operational standard for reciprocating compressors rod packing. 

In addition, the EPA understands from industry comments from the November 2010 proposal of 

subpart W of the GHG reporting rule that compressors are shutdown at least every three calendar 

years for maintenance and therefore, the reciprocating compressor rod packing replacement can 

be implemented during a regular maintenance schedule. 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 
89

or operators can elect to change the rod packing every 36 months in lieu of monitoring 

compressor operating hours. However, this final rule does not apply to compressors located in 

the transmission and storage segment.

Comment: One commenter (4266) recommends that the definition of centrifugal compressor 

exclude centrifugal compressors associated with vapor recovery because shutdowns to replace 

seals would increase emissions as compared to waiting for the next scheduled process shutdown. 

The commenter suggests modified text to §60.5430 to exclude such compressors.

Response: 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. 

A dry seal centrifugal compressor is not an affected facility in the final rule. The control option 

in the final rule is to reduce VOC emissions by 95 percent, which may be achieved by routing

captured seal-oil gas to a control device, such as the compressor suction, fuel gas system, or 

flare. The EPA determined this control system is cost-effective for new, modified, and 

reconstructed facilities.

Comment: In support of permitting design flexibility, one commenter (4192) asks the EPA to 

revise proposed §§60.5410(b) and 60.5415(b) to provide the option of achieving compliance 

with a dry seal “or an equivalent wet seal system.” The commenter says that although it supports 

the dry seal standard for centrifugal compressors, there are circumstances where it is impractical 

or infeasible to install a dry system. One commenter (4241) recommends that the EPA retain the 

option of using wet seals to control emissions, although dry seals are likely to be used in most 

cases. Two commenters (4192, 4246) request that §60.5380 be modified to allow for wet seal 

systems upon startup, when equivalent to dry seal systems. The commenters argue that wet seal 

systems might be the only viable options for some situations because of housing design or 

operational requirements. One commenter (4246) also requests that §60.5410(b) be modified to 

include the option of an equivalent wet seal system. One commenter (4158) requests that existing 

wet seal compressors not be deemed affected by the proposed rule. A second commenter (4233) 

asserts simply that the Agency should permit operators to control emissions from wet seals. 

However, this commenter recommends that the Agency permit the use of wet seals combined 

with a capture device, asserting that modifying or replacing a wet seal with a dry seal could be 

cost-prohibitive or technically impossible. One commenter (4246) conditionally supports the dry 

seal standard for centrifugal compressors, if the EPA would permit owners and operators to 

achieve compliance with a dry seal “or an equivalent wet seal system.” Another commenter 

(4263) suggests the EPA permit routing back to a process as a compliance option. Additionally, 

one commenter (4249) requests that wet seals be allowed on new centrifugal compressors if 

VOC emissions are equivalent to dry seal emissions. Another commenter (4254) agrees with the 

use of wet seals with a closed vent system and control device as an acceptable alternative to dry 

seals for centrifugal compressors. Yet another commenter (4263) recommends allowing the use 
90

of wet seal systems provided that emissions are routed to a control device or back to a process. In 

addition, capturing emissions from wet seal systems and routing such emissions to a process or 

to a control device may result in a greater reduction in overall emissions. One commenter (4164) 

says the rule should permit wet seal systems on new centrifugal compressors if an operator can 

demonstrate that the emissions would be similar to a compressor with a dry seal. This commenter 

says having such an option would give the operator design flexibility should one seal system 

design be preferable to the other in a given context. Objecting to the EPA’s proposal to require a 

particular type of technology, a commenter (4220) says there are wet seals now on the market 

that can achieve performance as good as, or better than, dry seals, and that the Agency did not 

provide for the use of equally performing equipment. The commenter argues that the EPA had 

not demonstrated whether dry seals were superior to wet seals, and says that for turbine drive 

compressors, some manufacturers already provide wet seal gas recovery systems that result in no 

emissions. Another commenter (4193) recommends exempting centrifugal compressors from the 

requirement where the owner or operator is unable to retrofit the compressor with dry seals.

Response: See Section IX.D of the final rule preamble for further discussion.

Comment: One commenter (4222) notes that the applicability definition for compressors in 

§60.5365 refers to “compressors located between the wellhead and the city gate.” The 

commenter states that most Alaskan facilities do not supply their product to a city gate and that 

the product is typically used on-site or re-injected. The commenter then concluded that 

compressors located in such Alaskan facilities would not be subject to the applicability 

definitions of §60.5365. 

Response: In regards to compressors in Alaskan facilities that move gas primarily for on-site 

purposes or for re-injection, the EPA directs the commenters to the facility definitions in 

§60.5365. For compressors, an affected facility in the final rule is defined as a single compressor 

located between the wellhead and the point of custody transfer to the natural gas transmission 

and storage segment, except at a well site. Therefore, a compressor located at a facility in Alaska, 

as described by the commenter, would not be subject to the NSPS subpart OOOO if it is located 

at a well site or after the point of custody transfer to the natural gas transmission and storage 

segment.

2.4.2 Number of Compressor Affected Facilities

Comment: Three commenters address the EPA’s definition of “affected facility.” One 

commenter (4240) agrees with the Agency interpretation that each compressor is an affected 

facility, because each compressor was an “apparatus,” and because installing a new replacement 

compressor was “construction” given the definition of the term in 40 CFR 60.2 of “fabrication, 

erection, or installation of an affected facility.” Another commenter (3475) describes the EPA as 

imposing an undue burden on operators and regulators by applying a narrow definition of 
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“affected facility.” This commenter asserts that the Agency definition of the term would mean 

regulation of individual pieces of equipment, rather than of complete well sites or plants. A third 

commenter (4251) asks the EPA to confirm that as proposed, §60.5380 would apply only to the 

compressor itself and to the installation of new compressors (including replacement of existing 

compressors) after August 23, 2011, and not to modification of other turbine components. 

Finally, this commenter (4251) asks for confirmation that replacing reciprocating compressor rod 

packing after August 23, 2011 on a compressor installed before that date would not constitute 

installing a new compressor or modifying an existing compressor, because such a replacement 

would not result in increased VOC or natural gas emissions.

Response: The EPA confirms that each compressor is an affected facility. As one comment 

notes, this definition is consistent with the General Provisions in 40 CFR 60.2, which defines 

“facility” to include an apparatus. The EPA has previously issued NSPS that apply to individual 

equipment on a plant instead of the whole plant. We disagree with the comment that the affected 

facility definition would impose an undue burden on owners and operators. Our analysis shows 

that the standards are cost effective. The commenter also provides no support for its claim of 

undue burden. Concerning the comment on whether replacing rod packing would constitute a 

modification, we reiterate that §60.14 defines modification. We believe it unlikely that rod 

packing replacement would be a modification.

Comment: Noting that the cost of retrofitting wet seals to dry can be as high as $1 million, one 

commenter (4192) further asserts that such a retrofit is cost-prohibitive. Another commenter 

(4270) agrees that the actual cost of replacing wet seals is significantly higher than the Agency’s 

estimate of approximately $270,000 for equipment and $540,000 for installation, with a 

reduction in emissions under the proposal costing $23,000/ton of VOCs rather than the EPA 

estimate of $3,485/ton. One commenter (4266) says that because the analysis in the TSD 

addresses only centrifugal compressors in the processing and transmission and storage segments, 

the EPA had no cost-benefit data to support regulating compressors in the gathering and boosting 

sector, and should exclude this sector from the rule. Five commenters (4158, 4218, 4263, 4246, 

4265) agree that in some circumstances, it would be too costly or technologically infeasible to 

replace wet seals with dry ones. Four commenters (4218, 4219, 4233, 4246) say a conversion 

from wet to dry seals could cost anywhere from $600,000.00 to $1 million. One commenter

(4263) states that retrofitting compressors equipped with wet seal systems with dry seal systems 

is cost-prohibitive. The commenter states that in the case of a unit that undergoes modification, 

changing to dry seal could be cost prohibitive or technically impossible. Two commenters (4146,

4265) request that existing centrifugal compressors be excluded from the proposed rule. The 

commenters state that existing units with wet seals could face major redesign or rebuild costs if 

they become subject to the rule as a result of a rebuild or modification. One commenter (4254)

adds that for some existing units that are modified, changing to a dry seal may be cost prohibitive 

or technically impossible. 
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Response: See section IX.D of the final rule preamble.

Comment: Citing information and calculations from an EPA study, a commenter (4270) says the 

Agency should recognize a broad disparity between seal oil degassing rates, and recalculate 

emissions based on the mean number rather than an average that excludes the zero emissions. 

The commenter further asserts that other reasons for more fact-finding are the variability in the 

Agency study of the volume of methane emissions from wet-seal degassing in any given 

compressor, and the reliance on an assessment examining natural gas losses at only 0.6 percent 

of the estimated 726 gas processing plants in the United States.

Response: With regards to the commenter’s request about revising the emissions factor using 

zero-values, the EPA does not agree with the commenter. When determining the methane 

emission factor for venting from centrifugal compressor wet seal degassing, as part of its 

methodology the EPA removed the zero emissions values as not valid based on the intended 

function of the seal oil system. The EPA expects seal oil to absorb the gas in the compressor gas 

under high pressure and then to release that absorbed gas when the seal oil is returned to 

atmospheric pressure in the sump. The EPA also acknowledges the possibility that bulk gas in 

the compressor case can be entrained in the seal oil piping where it reaches the atmosphere at the 

seal oil sump. Zero emissions implies that the seal oil pressure setting is sufficiently high to 

allow seal oil to be forced into the gas where it can damage the compressor and accumulate in 

the pipelines downstream. Therefore, the EPA excluded the zero emission data points when 

determining the mean emissions from centrifugal compressor wet seals. Regarding the 

commenter’s statement that this action affects only 0.6 percent of gas processing plants, the EPA 

clarifies that its promulgation of centrifugal compressor seal oil degassing NSPS is based on 

consideration of the emissions source itself which is the degassing vent(s), and the EPA 

considers this emissions source to be significant with available and cost-effective control 

options.

2.4.3 Centrifugal Compressor Wet Seals

Comment: One commenter (4270) asserts that the following are disadvantages to retrofitting: 

the necessity for compressor head machining; changes in compressor rotor dynamics; increased 

susceptibility to failures due to reverse rotation, or due to dirt or liquids in the gas; and high 

assembly complexity.

Response: The EPA has concluded that dry seals are not the BSER for all new and modified 

centrifugal compressors. Instead, the EPA separately evaluated 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 
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reduce VOC emissions by 95 percent, which can be achieved by routing captured seal-oil gas to 

a control device, such as the compressor suction, fuel gas system or flare. See section IX.D of the 

final rule preamble.

Comment: One commenter (3528) asks the EPA to confirm that a centrifugal compressor is not 

“on a well site” if the compressor served multiple well sites from an associated pad in proximity 

to a well site, and consequently, would not be an “affected facility” subject to the rule.

Response: 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 rule does not include standards for compressors at the wellhead. The EPA has clarified 

the final rule to also exclude compressors located adjacent to the well site that service one or 

more wellheads from an associated site.

2.4.3.1 Control Options – Replace with Dry Seal

Comment: Regarding the EPA’s proposal to set an equipment standard requiring dry seals for 

centrifugal compressors, one commenter (4170) supports the standard as proposed. This 

commenter agrees with the Agency that dry seal systems are BSER for reducing VOC emissions 

from such compressors, and notes further that dry seals reportedly reduce operational costs, 

maintenance costs, and methane emissions as well. Another commenter (4275) recommends that 

the EPA require owners and operators to replace wet seals on existing compressors with dry 

seals, because dry seals represented the best-demonstrated technology, are an important 

component in protecting human health and the environment, and are consistent with the law.

Response: See section IX.D of the final rule preamble.

Comment: Although supporting the dry seal requirement, another commenter (4240) argues that 

the EPA must investigate whether to require dry seal centrifugal compressors as BSER, and 

prohibit new installations of reciprocating compressors.

Response: Centrifugal and reciprocating compressors are unique types of equipment that satisfy 

the variety of compression needs in oil and gas operations. The EPA does not intend, in this rule, 

to prohibit new installations of reciprocating compressors because rod packing emissions from 

reciprocating compressors can be controlled. Therefore, the EPA is requiring separate control 

standards for reciprocating and centrifugal compressors. See sections V.B and IX.D of the final 

rule preamble.

Comment: One commenter (4240) asserts the Agency must require the use of tandem or doubledry seal systems as BSER, because tandem seals substantially improved emissions control.
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Another commenter (4159) argues that the Agency had not demonstrated the superiority of dry 

seals and should not mandate using a particular type of technology.

Response: In the final rule, the EPA is requiring standards for wet seal centrifugal compressors 

located between the wellhead and the point at which the gas enters the transmission and storage

segment. A dry seal centrifugal compressor is not an affected facility in the final rule. See section 

IX.D of the final rule preamble.

Comment: One commenter (4159) says the EPA should set a performance standard rather than 

mandate using dry seals. Another commenter (4251) supports the proposed use of a technologybased operational standard for centrifugal compressors as opposed to an emissions-based 

standard.

Response: See section IX.D of the final rule preamble.

Comment: One commenter (4245) asserts that the EPA should implement the switch from wet 

to dry seals by setting requirements for compressor manufacturers. The commenter recommends 

replacing the proposed rule with a “stipulation to state agencies” to examine gas compressor 

integrity as “part of the normal process of engine testing, maintenance and recordkeeping.”

Response: In response to the comment on dry seals, 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. A dry seal centrifugal compressor is not an affected facility in 

the final rule. The EPA also clarifies that the emissions source being regulated by this action is 

related to compressors and not engines, and the emissions source being regulated by this action 

does not involve combustion.

Comment: A commenter (4245) further recommends phasing out wet seal pumps for wet seal 

centrifugal compressors over a five year period as they need to be replaced.

Response: The EPA does not agree with the commenter. This rule intends to control emissions 

from new, modified, and reconstructed wet seal compressors located between the wellhead and 

point at which gas enters the transmission and storage segment by reducing VOC emissions from 

the seal fluid degassing system by 95 percent. See section V.B of the final rule preamble. 

Comment: One commenter (4219) states that methane, not VOCs, is the substance emitted from 

wet seals used for processed gas, and that it is unreasonable to compel owners and operators to 

spend half a million dollars to reduce already de minimis VOC emissions. This commenter 

asserts the rule should not apply to facilities midstream or downstream, which are the ones 
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handling processed gas. One commenter (4246) states that in some situations, a wet seal system 

may be the only viable control option, and that dry seal conversions are impractical for some 

compressors due to housing design or operational requirements.

Response: The EPA does not agree with the commenter that operators would need to spend half 

a million dollars to comply with the requirements for centrifugal compressors in this rulemaking.

The final rule requires 95 percent reduction of the emissions from each wet seal centrifugal 

compressor affected facility, which can be achieved by capturing and routing the emissions to a 

control device that achieves an emission reduction of 95 percent. The EPA determined the BSER 

for new, wet seal centrifugal compressors is cost-effective for compressors located between the 

wellhead and point at which gas enters the transmission and storage segment.

Comment: A commenter (4164) says that codifying a requirement to use dry seals on centrifugal 

compressors is unnecessary, because the practice is already the industry standard.

Response: As explained in the preamble, 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. A dry seal centrifugal compressor is not an affected facility in 

the final rule. See section IX.D of the final rule preamble.

Comment: One commenter (4273) is concerned with the requirement that centrifugal 

compressors use "dry seals" rather than setting a performance standard. The commenter states 

that there are wet seals that can achieve the same performance or better performance than dry 

seals. The commenter states the EPA has not demonstrated that dry seals are by definition 

superior to wet seals and provides no option in the proposed rule for the use of equally 

performing equipment. The commenter states that the EPA should not mandate a particular type 

of technology and that CAA section 111 indicates that a performance standard should be 

imposed.

Response: See section IX.D of the final rule preamble.

2.4.4 Reciprocating Compressors – Rod Packing Replacement

Comment: Five commenters (4104, 4158, 4193, 4268, 4185) suggest that the EPA set a 

maintenance standard instead of, or as an alternative to, the 26,000 hour operational standard. 

One commenter (4158) argues that a “condition-based maintenance program” is the best way to 

manage costs and reduce emissions. One commenter (4193) observes that current practice is to 

monitor reciprocating compressors for leaks and replace equipment at appropriate intervals. One

commenter (4185) suggests text that would require owners or operators to maintain and operate 

reciprocating compressors “consistent with good air pollution control practice for minimizing 
96

emissions,” to use quarterly ultrasound measurements or metering for leak detection, and to 

replace the rod packing within 180 days of detecting a leak greater than 2.0 standard cubic feet 

per minute. 

Another commenter (4158) reports that, in routinely monitoring for leaks and using a “financial 

objective based on a targeted payback period,” its company determined the most cost-effective 

time for packing replacement. One commenter (4266) suggests rule text for §§60.5385(a), 

60.5415(c)(2) and 60.5420(b)(4) permitting owners or operators to specify the frequency interval 

for rod packing replacement in terms of a set number of hours, years, or in a preventive 

maintenance plan designed both to maximize the reliability of the reciprocating compressor and 

minimize VOC emissions. This commenter’s suggested changes would require that the owner or 

operator conduct and monitor operations according to the chosen option for packing 

replacement.

One commenter (4251) says the interval should be 50,000 hours of operation, with a requirement 

for conducting periodic monitoring and preventive maintenance to detect and correct leaks 

throughout the life of the packing. However, this commenter says the preferred approach would 

be a periodic monitoring program and “as needed” rod packing replacement. 

Six commenters (4104, 4185, 4214, 4228, 4229, 4265) argue for a “condition-based” or 

preventive maintenance program as an option to the hours-based standard. These commenters 

say such programs would reflect safety, maintenance, and replacement practices in the industry; 

and should include requirements to assess performance by measuring the rod packing leak rate. 

Three commenters (4229, 4251, 4265) request that the EPA change the rule text to require a rod 

maintenance program, rather than a replacement program. 

Two commenters (4104, 4228) state that owners and operators should document condition-based

maintenance/replacement procedures and leak rate results, and retain these records under subpart 

OOOO. The commenters (4104, 4228) assert that the measurement should be in accordance with 

standard practices defined in subpart W; and that the standard should require 

maintenance/replacement, respectively, within nine months or three months of discovering a leak 

rate exceeding 150 scfh or at the next unit shutdown, whichever is sooner. Another commenter 

(4185) asserts that a leak rate of 2.0 scfm or more should be the emissions threshold for rodpacking replacement. 

One commenter (4039) states that the EPA should permit replacing rod packing based on 

periodic monitoring, which would give owners and operators additional flexibility – particularly 

on units already subject to monitoring requirements under the Greenhouse Gas Mandatory 

Reporting rule. The commenter believes the final rule should refer to rod packing maintenance 

rather than rod packing replacement. The commenter suggests operators could use proven 
97

maintenance practices to address rod packing leakage without replacing all of the components. 

Second, the commenter recommends increasing the time before maintenance work is required 

from 26,000 hours of operation to 43,500 hours of operation, based on the typical maintenance 

outage schedule. The commenter suggests requiring owner/operators to implement a program of 

condition-based maintenance or predictive maintenance to avoid possible leaks. Third, the 

commenter suggests requiring testing the leak rate of the packing every subsequent 8,760 hours 

of operation after the initial 43,500 hours of operation to determine if maintenance work is 

required. The commenter recommends a leak rate of 150 standard cubic feet per hour (scfh) in 

determining whether rod packing maintenance (including component replacement) would need 

to occur.

With regard to the same subject of rod packing, two commenters (4249, 4254) agree that the 

final rule should refer to rod packing maintenance rather than rod packing replacement for the 

same reasons as above and because replacement could cause wasteful discard of fully or nearly 

full functioning equipment. However, these commenters recommend allowing up to 35,000 

hours of operation before requiring maintenance or replacement of rod packing. One commenter 

(4249) supports condition-based maintenance that would assess rod packing leak rate 

performance against industry standards and maintain or replace the rod packing within nine 

months if the leak rate exceeds a threshold such as 150 scfh and continued use of the packing 

beyond 35,000 hours if it has been properly maintained and has an acceptable leak rate.

Response: The EPA has determined that a 26,000 hours-of-operation or every 36 months fixed 

replacement period for reciprocating compressor rod packing will control rod packing emissions. 

The EPA reviewed comments that suggested establishing a monitoring and repair program and 

reviewed options for establishing a potential emission limit for replacing reciprocating 

compressor rod packing. However, the EPA determined that an emission limit for rod packing is 

not appropriate, given that emissions tend to increase continuously over time and the limited 

available data depicting that change. Some commenters have requested that the EPA adopt a 

specific emissions limit of 150 scf/hour, but did not provide new data or information to allow the 

EPA to evaluate the derivation of that proposed limit. Based on these factors, the EPA is 

retaining the 26,000 hour fixed replacement period requirement for operators to replace their 

reciprocating compressor rod packing. In addition, we are providing flexibility by providing in 

the final rule that operators may change rod packing every 36 months in lieu of monitoring hours 

of operation.

Comment: One commenter (4266) said the Agency should exempt reciprocating compressors in 

the transmission and storage segment located after the point of custody transfer, because there is 

low VOC content in natural gas from that segment. Another commenter (4104) argued that even 

without regard to fundamental flaws stated in the five factors or methods, there still would be 

only trivial and inconsequential VOC reductions relative to the national VOC inventory. The 
98

commenter observed that achieving VOC reductions of one percent of the national anthropogenic 

VOC inventory would require over 21,000 regulations at 6.9 TPY, and that the EPA’s estimated 

annual VOC reductions for compressors was similarly inconsequential. Nor, said the commenter, 

had the EPA adequately considered administrative burdens associated with reporting, 

recordkeeping, and permitting. The commenter asserts that the trivial, incremental emissions 

reductions that would result from the rule failed to justify the associated compliance costs, and 

that the final rule should exclude transmission and storage sources. Another commenter (4228) 

expressly requests that the EPA reanalyze VOC emissions reductions and reassess whether the 

rule would be cost-effective. 

Response: The EPA agrees with the commenters that costs are an important consideration in a 

rulemaking. In fact, the EPA believes that such consideration is particularly important here given 

that coverage of the transmission segment would result in a significant number of sources, and 

owner and operators being subject to the rule that are not subject to the current standards. We 

have concluded that additional evaluation is appropriate prior to taking final action on 

reciprocating compressors in the transmission and storage segment.

For the reasons stated above, the requirements for reciprocating compressors in the final rule 

apply to affected facilities located between the wellhead and the point of custody transfer to the 

natural gas transmission and storage segment. Our current data indicate that the VOC content of 

the natural gas used in the transmission and storage segment is low, whereas the natural gas used 

in the segments we are regulating has a higher VOC content. See section IX.D of the final rule 

preamble.

Comment: One commenter (4170) says it supports the Agency’s analytical approach of looking 

at industry experience with the Natural Gas STAR program and other sources to substantiate a 

finding of 26,000 hours (equivalent to 3 years of operation) as a cost-effective, reasonable, and 

adequate rod packing replacement standard.

Response: We appreciate the commenter’s support of the methodologies used to develop subpart

OOOO. 

Comment: Two commenters (4170, 4274) support the proposed operational standard of 

replacing rod packing based on 26,000 hours of usage for reciprocating compressors. They call 

the proposed standard “imperative” and assert that it would create industry savings.

Response: The EPA appreciates this comment.

Comment: One commenter (4274) says the Agency should adopt a procedure for verifying 

operating hours and determining whether owners and operators made timely replacements. 
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Response: The commenter has not provided an explanation as to why they do not believe that 

the proposed recordkeeping and reporting requirements for verifying operating hours are 

insufficient. The EPA believes that the current requirements of recordkeeping and an annual 

report of the cumulative number of hours of operation or the number of months since the 

previous reciprocating compressor rod packing replacement provides verification of timely rod 

packing replacements. The recordkeeping requirement will provide documentation that the 

engine is operating in compliance with the rod packing requirements, and the reporting 

requirement will provide the EPA a way to track rod packing replacements. 

Comment: One commenter (4274) states that although the EPA’s proposal codified standard 

industry practices reflecting appropriate and effective measures for reducing emissions, the 

Agency rulemaking action is necessary to bring all of the industry to the same standard as 

responsible companies.

Response: The EPA appreciates this comment.

Comment: One commenter (4104) states that requiring reciprocating compressor rod packing 

replacement could lead to wasteful discard of functioning components and equipment, or to 

stifling innovation in rod packing maintenance. This commenter says setting a blanket standard 

number of hours for rod-packing replacement could allow units to continue operating after 

significant leaks occurred or require premature replacement of working systems. The commenter 

adds that if all of these equipment components were in good working condition, there would not 

be leaks substantial enough to justify replacement at the “overly prescriptive interval” of 26,000 

hours. The commenter says the 26,000-hour standard could result in prematurely removing 

properly functioning equipment, adding unnecessary operational costs; could eliminate 

incentives for developing superior rod-packing technologies; and could increase emissions due to 

more frequent maintenance-related start-up and shutdown. 

Four commenters (4185, 4214, 4233, 4251) say the 26,000-hour standard could lead to 

unnecessary down time and equipment replacement. 

Two commenters (4241, 4251) support the EPA’s use of an operational standard to address 

fugitive emissions from piston rod packing wear; however, state that a requirement to change out 

rod packing at 26,000 hours of operation could prematurely remove properly functioning 

equipment, result in an expensive and infeasible maintenance program, and undermine the 

incentive to develop superior rod packing technologies.

One commenter (4219) endorses an alternative method based on operation time as opposed to a 

leak-based threshold, and supports the EPA’s proposal to allow for coordinating packing 
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replacement with planned maintenance shutdowns before operating hours reached the designated 

level.

Two commenters (4104, 4228) state that the EPA’s analysis assumes that there would be no rod 

packing replacement and maintenance in the absence of the proposed rule, but the commenters 

believe the rule would yield a small fraction of total industry reductions given existing practices.

Response: With regard to premature replacement and stifling innovation, the EPA acknowledges 

that rod packing replacement and maintenance occurs in the absence of the final rule. The TSD

for the proposed subpart OOOO explains that rod packing emissions increase as the packing 

components wear, and the EPA understands that rod packing must be replaced periodically to 

ensure the mechanical integrity of the compressor. The EPA has promulgated the rod packing 

replacement requirements based on VOC control which may require replacement of the rod 

packing before the point at which the rod packing has mechanically deteriorated. The EPA 

believes that the benefits of VOC control warrant the rod packing replacement requirement.

The replacement period for reciprocating compressor rod packing was determined based on 

industry information from the Natural Gas STAR Program. As discussed above, the EPA is 

retaining the rod packing replacement period in the final rule. The background TSD for the 

proposed subpart OOOO rule acknowledges in its cost impacts analysis for reciprocating 

compressors that gathering and boosting compressors and processing compressors operate for 

only a fraction of the year, and therefore will replace their rod packing at intervals longer than 3 

years if the operating hours for the compressor are monitored. For additional flexibility, we are 

providing in the final rule that operators may change rod packing every 36 months in lieu of 

monitoring hours of operation. Also, commenters did not provide additional operational data for 

the EPA to further evaluate the operational standard for reciprocating compressors rod packing. 

With regards to unnecessary operational costs and downtime, industry comments from the 

November 2010 proposal of subpart W of the GHG reporting rule state that compressors are 

shutdown at least every three calendar years for maintenance and therefore, the reciprocating 

compressor rod packing replacement period is based on a typical maintenance shutdown cycle. 

Comment: One commenter (4185) says its suggestions are consistent with practices at its 

facility, and notes further that the EPA should make the standard for rod packing replacement 

consistent with the associated maintenance standard for engines subject to subpart JJJJ. This 

commenter also notes that the EPA should make the standard for rod packing replacement 

consistent with the associated maintenance standard for engines subject to subpart JJJJ. To that 

end, the commenter suggests the Agency model the rule on §60.4243(b)(2)(ii), and require 

owners or operators to maintain and operate reciprocating compressors “consistent with good air 

pollution control practice for minimizing emissions.”
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Response: Regarding consistency with associated maintenance standard for engines subject to 

subpart JJJJ, the EPA has determined that immediately replacing the rod packing after 26,000 

hours of operation or after 36 months will control rod packing emissions. The EPA reviewed 

comments that suggested establishing a maintenance and repair program and reviewed options 

for establishing a potential emission limit for replacing reciprocating compressor rod packing. 

However, the EPA determined that an emission limit for rod packing is not appropriate, given 

that emissions tend to increase continuously over time and the limited available data depicting 

that change.

Comment: In contrast to other remarks endorsing the Natural Gas STAR program, a commenter 

(4268) says that for reciprocating compressors, the program is duplicative and would not provide 

significant benefit over a reasonable, proactive replacement schedule. The commenter states that

if the EPA uses the Natural Gas STAR program, the program must be voluntary, with 

participants exempted from the 26,000-hour replacement interval.

Response: The EPA used available information on viable emission reduction technologies and 

practices from the Natural Gas STAR program and other sources and conducted analyses with 

this best available information to inform the development of this rulemaking. 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 change the rod packing every 36 months in lieu of 

monitoring compressor operating hours. The EPA also clarifies that the Natural Gas STAR 

Program is a voluntary partnership to reduce methane emissions cost-effectively and is a separate 

activity from this rulemaking. This NSPS action is not being used in lieu of Natural Gas STAR, 

or vice versa.

Comment: One commenter (4270) opines that the EPA is mistaken in assuming that replacing 

compressor rod packing necessarily would reduce or eliminate leaks. The commenter asserts that 

reducing leaks depends upon related issues such as rod alignment, compressor-rod coating 

deterioration, and condition of crossheads; all these, the commenter asserts, can damage new 

compressor rod packing soon after installation. Another commenter (4193) notes that by 

reconditioning or rebuilding the system, it might be possible to restore performance without 

replacing the packing.

Response: We appreciate the commenter’s concerns for the rod packing replacement period. The 

EPA is aware rod packing emissions are a result of the fit of the rod and the packing and that 

there is variance in the rate of packing wear from one compressor to another. However, there is 

not enough publically available data to appropriately characterize this variance. Therefore, we 

determined an operational standard for rod packing replacement..
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2.4.4.1 Replacement Frequency – Hours of Operation versus Time in the Field

Comment: One commenter (4240) says that if the EPA continued to permit the use of 

reciprocating compressors, the Agency must strengthen the rod-packing standard by evaluating a 

more aggressive replacement schedule (i.e., less than the proposed 26,000 hour operating 

threshold as the trigger for packing replacement). Acknowledging that such a schedule might 

result in further cost savings to operators through avoided methane losses, the commenter argues 

that the Agency still is obliged to go beyond requiring only those emissions reductions that 

would be profitable to the operator.

Response: The EPA acknowledges the commenter’s suggestion to reduce the proposed 26,000 

hour reciprocating rod packing replacement period; however, the EPA does not agree that 

shortening the replacement period will necessarily increase cost saving for operators. The EPA 

has determined that the additional cost of shortening the replacement period does not justify the 

additional emissions reductions. The EPA has decided to retain the 26,000 hour-of-operation 

fixed replacement period, and in addition, the EPA is providing further flexibility by allowing 

operators to change the rod packing every 36 months in lieu of monitoring hours of operation.

Comment: One commenter (4266) references an assertion in the preamble that the rule should 

permit owners and operators to complete rod-packing replacement during a normally scheduled 

maintenance shutdown. One commenter (4191) states that because most operators routinely track 

the number of hours a compressor operates, the EPA should require tracking according to actual 

operating hours. 

Response: The EPA appreciates the comment; however, we are retaining the 26,000 hours fixed 

replacement period requirement. The EPA believes that the 26,000 fixed replacement period 

allows owners and operators to complete rod-packing replacement during a normally scheduled 

maintenance shutdown at the owner and operators' discretion. In addition, the EPA is providing 

flexibility by providing in the final rule that operators may change rod packing every 36 months 

in lieu of monitoring hours of operation.

Comment: One commenter (4245) requests that the requirement to replace reciprocating 

compressor rod packing at a fixed time interval be changed so that the emissions source is 

regulated through testing, maintenance, and recordkeeping. The commenter requests that the 

requirement be based on the existing State agency normal processes of engine testing, 

maintenance and record keeping. 

Response: The EPA disagrees with the commenter that rod packing emissions requirements 

should be associated with State engine testing, maintenance, and recordkeeping. The emissions 
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source being regulated by this action is related to compressors and not engines. Therefore, we 

did not evaluate State testing requirements and the commenter did not provide us with any 

information on State testing requirements for us to evaluate. 

Comment: One commenter (4251) requests that the EPA modify the monitoring requirement so 

that an operation could assume the maximum number of operating hours per year, rather than 

track the unit’s actual operating hours. One commenter (4192) states that, except during periods 

of down time, the EPA should allow owners and operators to assume that a compressor is 

operating continuously. One commenter (4241) requests that the EPA modify §60.5385(a) to 

allow an operator the option of assuming the maximum number of operating hours in a year in 

lieu of installing an hour meter and tracking the unit’s actual hours of operation. Two 

commenters (4175, 4268) recommend an option of replacing rod packing based on a calendar 

frequency of 36 months of actual operation. The commenters state that this approach would give 

owners and operators sufficient operational flexibility and serve the purpose of replacing packing 

before it is worn and leaking. One commenter (4246) suggests changing §60.5415(c) by 

permitting owners and operators to monitor a compressor’s days operated or downtime, in 

addition to hours of operation. One commenter (4263) suggests that, rather than setting an 

impractical continuous monitoring rule, the Agency should follow standards similar to those 

based on implementation by operating hours that require periodic recording rather than 

monitoring.

Response: In regards to the recommendation to require replacement on a calendar frequency of 

36 months of actual operation, the EPA has decided the final rule require replacement of the rod 

packing based on usage. When the hours of operation of a reciprocating compressor reach 26,000 

hours, the owner or operator is required to change the rod packing immediately.

In order to provide additional flexibility, the final rule allows owners and operators to change the 

rod packing every 36 calendar months in lieu of monitoring the reciprocating compressor’s 

actual operating hours. Please see section V.B and IX.D of the final rule preamble for more 

details.

Comment: One commenter (4246) suggests that §60.5420(c)(3)(i) and (c)(3)(ii) be modified to 

add that hours of operation recorded be those since initial startup “at the current location” or the 

date of publication of the final rule in the Federal Register, or the previous replacement of the 

reciprocating compressor rod packing “since the reciprocating compressor became subject to the 

rule at the current location.” The commenter asserts that the added wording would clarify that 

subpart OOOO does not apply to compressors that have merely been relocated.

Response: The EPA agrees that the NSPS does not apply to relocated compressors and further 

clarification would be helpful. However, the EPA is not certain that the commenter’s suggested 

revision clarifies the status of relocated compressors. Rather, in the final rule, the EPA revised 
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§60.5365(b) and (c) to state that the term “commenced construction” does not include 

relocation.

2.5 Storage Vessels

2.5.1 Number of Storage Vessels

Comment: Eight commenters (4177, 4192, 4231, 4241, 4245, 4246, 4251, 4266) state that the 

EPA greatly underestimated the number of storage vessels that would be subject to the NSPS. 

The commenters believe that the EPA should reexamine available data and develop a more 

realistic impacts analysis.

Response: Although some commenters provided anecdotal data to support their claims, these 

data were localized and based on the proposed throughput applicability metric, which has been 

replaced in the final rule with an emissions threshold. Thus, the data provided were not adequate 

to allow for a comprehensive reexamination of the population of storage vessels that would be 

affected by the final rule.

2.5.2 Equipment Costs

Comment: One commenter (4240) states that assuming, as the EPA does, that half of facilities 

use combustion devices and half use VRUs, the proposed rule would achieve significant VOC 

reductions at just $143/ton (accounting for additional revenues from recovered condensate). The 

commenter asserts that this is an eminently reasonable control cost, and is reflected in the wide 

use of vessel emissions control measures throughout the industry. 

Response: We agree with the commenter that the storage vessel rules are reasonable and cost 

effective. Please see the RIA for further details of our cost effectiveness calculations for storage 

vessels.

Comment: Four commenters (3447, 3468, 4255, 4472) are concerned that storage vessel control 

costs will be prohibitively expensive for oil and natural gas wells with low production. The 

commenters are primarily concerned that because many wells are only marginally profitable, 

particularly in the Midwest and Texas, the additional cost of installing controls on a storage 

vessel and conducting performance tests would render the wells to be uneconomical for the many 

small businesses that operate such wells.

Response: The final rule applies only to individual storage vessels with annual VOC emissions 

of 6 tpy or greater. Our analysis of the associated costs shows that the required controls are cost 

effective, with average costs of around $3,400 per ton of VOC reduced. In addition, our analysis 

of the impacts of the final rule on small businesses shows that they will not be significantly 
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affected (see Section 4 of this document). It should also be noted that because the rule is an 

NSPS, it applies only to new, modified and reconstructed storage vessels, and not to the existing 

storage vessels serving the many existing, low-producing wells in the Midwest, Texas and 

elsewhere.

Comment: Two commenters (4216, 4256) believe that the throughput thresholds would result in 

unacceptable costs for modified operations, particularly marginal wells. One of the commenters 

(4216) points out that the storage tank battery system must be designed to manage production 

when a production site is initiated, and then remains in place as existing wells decline and are 

plugged, as new wells are drilled and begin production, and as existing wells are reworked to 

increase production. The commenter notes that when a well is reworked, its production may 

increase for 6 or 8 months before declining back to its prior flow rate. Thus, the commenter 

believes, the consequences of normal well field development could result in a storage tank being 

under the threshold for 1 year, over the threshold the next year and below again the year after. 

The commenter asserts that under the proposed NSPS, a tank could be over the threshold and 

require installation of a vapor recovery unit (VRU) or flaring system that would no longer be 

required by the time it was in place.

The commenter (4216) asserts that control requirements for existing tanks create both economic 

and safety issues. The commenter believes that a marginal well producing operation would be 

hard pressed to economically absorb the costs of a VRU or flare system. The commenter also 

states that as many as 30 percent of existing tanks subject to emissions control could require 

replacement, primarily because of the potential that the existing tanks would allow oxygen into 

the vapor recovery process and create an explosive mixture. The commenter concludes that the

EPA needs to develop an approach that does not create an unreasonable burden on existing 

production, particularly marginal well operations, resulting from short-term increases in 

production. 

Response: We disagree with the commenters that the final rule will require excessive costs for 

modified operations or marginal wells. As discussed previously, the NSPS applies only to new, 

modified and reconstructed storage vessels. The reworking of a well or the introduction of 

production from a new well does not render the associated existing storage vessels subject to the 

rule. Thus, the ebb and flow of production associated with normal well field development does 

impact existing storage vessels. 

In addition, for well sites with no other wells in production, the final rule provides a 30-day 

period after installation, modification or reconstruction of a storage vessel for throughput to 

stabilize and for the operator to estimate VOC emissions to determine whether a control device 

will be required. Where control is required at such sites, the final rule provides an additional 30 

days for the control device to be installed and become operational. These estimation and 
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installation periods are not provided in the final rule at well sites with one or more wells already 

in production.

Finally, as noted previously, our analysis shows that the controls required under the final rule are 

cost effective for storage vessels with annual VOC emissions of 6 tpy or greater. This analysis 

holds true for modified and marginal operations as well as for new operations.

Comment: One commenter (4178) believes that virtually no tank constructed after August 23, 

2011 in Oklahoma will be exempted at the proposed throughput levels, which will require more 

facilities to be permitted, potentially inspected, and required to submit annual reports, thereby 

increasing the burden for regulatory agencies in areas of heavy natural gas and oil production. 

The commenter contends that agencies will be required to take manpower and focus away from 

larger emitting facilities.

Response: We do not agree with the commenter that the requirements of the final rule for 

storage vessels are overly burdensome. As noted above, under the final rule, applicability for 

storage vessels is based on annual VOC emissions, rather than on throughput. This may reduce 

the number of new storage vessels in Oklahoma that are subject to the NSPS, depending on a 

number of parameters related to the storage vessels and the fluids being stored. 

In addition, the EPA reexamined the proposed notification, recordkeeping and reporting 

requirements, and reduced these requirements where warranted. As a result, operators of storage 

vessels will not be required to submit, and permitting authorities will not be required to review, 

the notifications of construction, startup and modification in §60.7(a)(1), (3) and (4) of the NSPS 

General Provisions as proposed. Although annual reports will still be required for storage 

vessels, these reports will only be required to identify those affected vessels that were installed, 

modified or reconstructed during the reporting period. Thus, we believe that we have reduced 

these requirements to the essentials necessary to assure compliance.

As proposed, the final rule exempts area source affected facilities from title V permitting, and we 

do not expect most storage vessels to be subject to major NSR permitting under the CAA. Where 

state minor source permitting regulations require permitting of storage vessels based solely on 

their status as affected facilities subject to an NSPS, we note that this is not a requirement under 

the CAA.

Comment: One commenter (4178) asserts that it is industry practice to not maintain records of 

the throughput of each individual tank; rather, total load out records are kept, which only show 

the total volume, rather than the volume at each individual tank. The commenter believes that 

putting the mechanisms in place to be able to track the totals at each individual tank in addition 

to the reporting requirements could prove to be a great burden on industry.
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Response: We do not believe that the concerns expressed by the commenter apply under the 

final rule. The final rule does not determine applicability based on throughput, nor does it require 

monitoring of throughput. Instead, operators are required to determine at the outset whether a 

new, modified or reconstructed storage vessel will have uncontrolled VOC emissions equal to or 

greater than 6 tpy and, if so, must install controls. The operator is not required to track VOC 

emissions thereafter.

Comment: One commenter (4266) states that infrequently used tanks such as blowdown tanks, 

emergency tanks, and dehydrator drip tanks were not considered in the EPA’s cost effectiveness 

analysis. The commenter states that for blowdown tanks, the piping system for the combustion 

device will provide too much back pressure during a blow down event and the safety devices will 

vent the tanks as they should. The commenter believes the EPA needs to recognize that 

implementation of this requirement is far more complicated than connecting up existing tanks to 

combustors. The commenter states the entire tank system would need to be evaluated and 

possibly replaced with a “code stamped” pressure vessel/tank and appropriately sized and 

designed safety valves, hatches, and gas piping. Accordingly, the commenter asserts that the 

EPA needs to fully recognize the associated costs which are substantially more.

Response: We do not agree that our analysis inappropriately omitted the retrofitting costs raised 

by the commenter. As an NSPS, the final rule applies only to new storage vessels; existing 

vessels would not need to be retrofitted to be controlled unless they were modified or 

reconstructed. In addition, we note that the cost effectiveness analysis was based on VOC 

emissions and controls, not type of storage vessel or fluid. This analysis found that controls are 

cost effective for those storage vessels that emit 6 tpy or more of VOCs, and the final rule 

applies only to storage vessels with emissions at or above this level. We also note that the 

definition of storage vessel in the final rule states that surge control vessels and knockout vessels 

are not storage vessels.

Comment: One commenter (4269) indicates that the cost of purchase or prolonged rental of 

VRUs is grossly underestimated over the life of a well, particularly “stripper” production which 

may never recover the cost of the prescribed equipment. According to the commenter, the cost of 

the unit would be $50,000-$100,000 plus $10,000 of piping and installation, and rental of these 

units can be $2,000 per month plus piping and installation. The commenter believes that small 

producers would be required to hire new staff or pay new and additional consulting fees to 

comply with the EPA proposal, and would be unlikely to recover the investment in purchasing 

VRUs.

Response: The EPA disagrees that the cost of a VRU is unreasonable. We reanalyzed these costs 

based on comments received and determined that the total capital investment to purchase and 
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install a VRU is about $98,000 and the total annual cost (including the annualized cost of capital 

and annual O&M) is about $20,000 without accounting for the value of reclaimed materials 

(which averages over $1,100 per year). At the minimum level of applicability (6 tpy of 

uncontrolled VOC emissions), this results in cost effectiveness of around $3,400 per ton of VOC 

emissions reduced, which we believe to be cost effective. 

In addition, we analyzed the impact of the final rule on small businesses and determined that the 

rule would not result in significant impacts for a significant number of small businesses. For 

more on the small business impacts, see the RIA for the final rule, section XI of the preamble to 

the final rule and section 4 of this document.

Comment: One commenter (4158) states that if the EPA intends to extend the control 

requirements of this rule to storage tanks in the transmission and storage segment, then the EPA 

should conduct additional cost analysis. The commenter asserts that the cost of control would be 

well in excess of the average annual cost of $14,528 included in the EPA’s RIA at proposal, and 

that based on costs solicited from a manufacturer, budgetary expenditure would be 

approximately $986,427 for total installed costs including materials and installation for a VRU 

for one condensate tank with greater than 1 bbl/day throughput. According to the commenter, the 

present value of annualized costs over a 5-year period ranges from $632,000 – $1.57 million 

including operating expenditure.

Response: The EPA disagrees with the commenter that additional cost analysis is necessary for 

storage vessels in the transmission and storage segment, and with the commenter’s estimate of 

control costs for storage vessels in this segment. 

The control requirements of the final rule are based on annual VOC emissions, without regard to 

the location of the storage vessel within the various segments of the natural gas industry. Thus, it 

is possible for storage vessel in the transmission and storage segment to be affected by the final 

rule, although we do not expect a large number of storage vessels in this segment to have VOC 

emissions greater than the 6 tpy threshold. In any case, our analysis of the costs and cost 

effectiveness of controlling storage vessel emissions was based on VOC emissions and controls, 

and the location of the storage vessel is not germane to the analysis. Thus, controls at the 6 tpy 

level are cost effective no matter where the storage vessel is located. The commenter did not 

provide any details or rationale for why costs would be greater in the transmission and storage 

segment, so we were unable to evaluate this assertion.

We revisited our cost analysis for storage vessel controls based on comments received on the 

proposal. Our revised analysis indicates that total annual costs for storage vessel controls average 

$19,864 for 95 percent control without accounting for product recovery, assuming that half of the 

tanks are controlled with VRUs and half with combustion devices. The commenter did not 
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provide specific information to support the cited capital and annualized costs for a VRU, so we 

were unable to evaluate these costs.

Comment: One commenter (4266) contends that the EPA’s cost for controls of $18,983 per year 

is inconsistent with the EPA Air Pollution Control Cost Manual, which addresses enclosed 

combustors in Section 3.2. The commenter presents a cost analysis purportedly based on the 

method prescribed in the EPA Cost Manual which results in an annual cost of controls of 

$55,207. (The commenter indicates that this cost is conservative in that it includes no costs for 

data management required by the proposed rule, and it does not adjust for inflation since 

calendar year 2000.) The commenter presents a cost effectiveness analysis based on this cost that 

concludes that the threshold needs to be 12 tpy to be cost effective at the EPA’s threshold of 

$5,000/ton. Numerous other commenters (4177, 4192, 4217, 4220, 4233, 4264, 4281) support 

this analysis and threshold.

Response: As noted above, we reanalyzed control cost for storage vessels based on the 

comments that we received on the proposal. Our revised analysis show that the average annual 

control cost for storage vessels (half VRUs and half combustion devices) is $19,864 without 

consideration of the value of reclaimed product and $19,281 considering those savings. These 

costs represent revisions primarily to account for the operating labor associated with flares. 

While we are not disputing the Control Cost Manual analysis performed by the commenter, we 

used a different source of cost information (see the docket for more details). This information 

was developed specifically for this industry; therefore, we believe it may be more accurate than 

the more generalized Control Cost Manual analysis.

Comment: One commenter (4240) asserts that the EPA’s proposal to exempt “small throughput” 

storage vessels is unlawful. The commenter indicates that the EPA’s own calculations show that 

the annualized cost of installing a VRU is $18,983 and $8,909 for a flare – translating into 

control efficiencies of about $3,000 per ton of VOC emissions reduced for a VRU (depending on 

the tonnage of emissions captured) – which are not exorbitant costs. The commenter states that in 

exchange for these costs, the EPA would significantly reduce VOCs at these facilities. The 

commenter concludes that these are substantial emissions reductions at fairly low costs and the 

EPA must, therefore, either abandon or strictly limit the exemption.

Response: The EPA disagrees that our threshold for control of storage vessels is inappropriately 

high. For the final rule, we have set the applicability threshold at 6 tpy of uncontrolled VOC 

emissions based on our revised control cost and cost effectiveness analysis. The EPA has the 

latitude to decide which emission points to regulate in setting thresholds. 

As noted above, the revised cost analysis indicates that the average annual control cost, not 

including the value of reclaimed product, is nearly $20,000. At the applicability threshold of 6 
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tpy, this translates to a cost effectiveness of about $3,400 per ton of VOC reduced. We believe 

that this is a reasonable cost effectiveness value, and our analysis of the final rule’s insignificant 

impacts on small businesses bears this judgment out.

2.5.3 Affected Facilities

2.5.3.1 Definition of storage vessel

Comment: Five commenters (3560, 4258, 4219, 4263, 4266) assert that units such as process 

vessels, pressure vessels, knockout vessels, separators, open top pit tanks and tanks that receive 

pigging fluids should not be included in the definition of storage vessel.

Response: The EPA agrees with the commenters that process vessels, pressure vessels and 

knockout vessels should all be excluded from the definition of storage vessel. Process and 

knockout vessels are typically used within a process to collect material from one unit before 

being transferred to another, and thus are not used for storage. Pressure vessels are expected to 

be operated without venting to the atmosphere and are regulated by 40 CFR part 63, subpart HH. 

However, the EPA disagrees with the commenters that tanks storing pigging fluid discharge are 

not a storage vessel, as these tanks are storing liquids that have the potential to emit VOC. 

Therefore, if the vessel meets the 6 tpy VOC threshold, it would be subject the storage vessel 

requirements.

Comment: Four commenters (4241, 4251, 4252, 4320) request that the EPA exclude temporary 

and mobile storage vessels, such as “frac tanks,” from regulation. The commenters variously 

suggest on-site time limits of 90 days, 180 days, and 12 months to qualify as a temporary or 

mobile storage vessel. 

Response: We agree that these temporary tanks are not truly stationary, but believe that 180 days 

is an appropriate length of time to determine whether the storage vessel is temporary or 

stationary. Temporary and “mobile” vessels that are intended to be located at a site for 180 days 

or more will be considered subject to the storage vessel requirements of subpart OOOO. We 

have also added provisions to subpart OOOO that require records to be kept on the number of 

days that a temporary or “mobile” storage vessel has been located at a site.

Comment: Eight commenters (4104, 4158, 4219, 4220, 4249, 4252, 4265, 4266) assert that the 

EPA should clarify that the VOC reduction requirement in proposed subpart OOOO would only 

apply to tanks at production sites. The commenters indicate that a variety of materials convey 

that this is the EPA’s intent.
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The commenters state that the proposed rules, however, do not reflect this apparent intent and 

that additional clarification is warranted. One of the commenters (4104) recommends revising 

the definition of “storage vessel” in §60.5430 and/or revising the affected source in §60.5365(e) 

to clearly define the sectors that include subpart OOOO affected tanks. 

One of the commenters (4219) contends that applying the VOC control requirement to 

midstream and downstream tanks would be unreasonable because the product in such tanks tends 

to have little VOC content, and the cost per ton of VOC reduction for tanks with low VOC 

content is unreasonably high. The commenter adds that establishing a threshold emission limit of 

12 tpy VOC for storage tanks would accomplish this result because storage tanks downstream of 

gas processing plants typically have lower VOC emissions than tanks at production sites. 

Another commenter (4220) similarly states that applicability should be limited to tanks located in 

the production field, upstream of the “point of custody transfer” between oil production 

operations and liquid distribution pipeline operations.

In contrast, one commenter (4275) believes that storage vessels used in the Natural Gas Storage 

and Transmission source category should also be regulated because these are also significant 

pollution sources.

Response: The EPA disagrees with the commenters who contend that storage vessels in the 

transmission and storage segment of the natural gas industry should not be regulated. The final 

rule applies to storage vessels based on their uncontrolled VOC emissions, regardless of their 

location. As discussed above, our analysis shows that VOC controls are cost effective at the final 

rule’s applicability threshold of 6 tpy without regard to the type of storage vessel, its location or 

the fluid that is stored. 

However, we understand the concern expressed by the commenters based on the proposed rule’s 

throughput applicability metric. We believe that the shift to VOC emissions as the applicability 

metric in the final rule will result in few storage vessels in the transmission and storage sector 

requiring control, as well as other storage vessels handling low VOC materials for which the 

commenters expressed concern. 

Comment: Two commenters (4104, 4158) state that if the EPA intends to regulate tanks in the 

transmission and storage segment, it has not supported the regulatory basis for the decision, and 

the EPA needs to complete additional analysis. One of the commenters (4104) indicates that, for 

example, the preamble cost-benefit discussion on tanks is based solely on production sources, 

and the EPA has not provided analysis on VOC emissions, prevalence of affected sources, costs 

of controls, or relative cost-benefit for tanks in the transmission and storage segment. 
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Response: As discussed above, the EPA disagrees with the commenters that additional cost 

analysis is necessary for storage vessels in the transmission and storage segment. Applicability 

under the final rule is based on annual VOC emissions, without regard to the location of the tank 

within the various segments of the natural gas industry. Thus, it is possible for storage vessel in 

the transmission and storage segment to be affected by the final rule, although we do not expect a 

large number of tanks in this segment to have VOC emissions greater than the applicability 

threshold. In any case, our analysis of the costs and cost effectiveness of controlling storage 

vessel emissions was based on VOC emissions and controls, and the location of the storage 

vessel is not germane to the analysis. The commenter did not provide any details or rationale for 

why costs would be greater in the transmission and storage segment, so we were unable to 

evaluate this assertion.

Comment: One commenter (4039) states that the EPA should evaluate an alternative threshold 

of tank volume to determine rule applicability for storage tanks that are not located at processing 

facilities. The commenter contends that the proposed approach (requiring 95 percent control of 

VOC emissions on tanks with throughput or 1 bbl/day of condensate or 20 bbl/day of crude oil, 

along with initial performance tests continuous monitoring) be valid for tanks that are in a 

processing facility, but this requirement is very cumbersome to implement for most smaller 

storage tanks in the field that do not have flow indicators or meters that allow the operator to 

know the throughput at any given point in time. The commenter points out that most small 

storage tanks in the field are allowed to accumulate liquid products and then emptied when 

reaching a certain capacity, and that these field storage tanks are designed so that they can be 

emptied at a reasonable interval, usually monthly or quarterly. The commenter requests that the 

EPA evaluate an alternative threshold of tank volume to determine rule applicability for tanks 

that are not located at processing facilities and would suggest a volume threshold of 5,000 

gallons. The commenter believes that this approach has the advantages that it is easy to 

determine and does not change, making it clear whether a tank is regulated or not, and also 

eliminates the need for extensive recordkeeping for small, remotely located tanks. 

Response: Under the final rule, controls are required for tanks based on uncontrolled VOC 

emissions rather than throughput. We believe that this change addresses the commenter’s 

concerns related to storage vessels that are not located at processing facilities.

Comment: Five commenters (4192, 4193, 4218, 4231, 4246) commented on whether the EPA 

should or should not aggregate storage vessels in defining the affected facility.

Two commenters (4193, 4231), referring to proposed §60.5365(e) which states, “A storage 

vessel affected facility, which is defined as a single storage vessel,” assert that a storage vessel 

affected facility should not be defined as a single storage vessel. The commenters believe that the 
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affected facility should not be every tank, but instead an entire tank farm or battery, including all 

tanks that store only condensate or crude oil. 

Two commenters (4192, 4246) note that the proposed rule defines a “storage vessel” as “...a 

stationary vessel or series of stationary vessels that are either manifolded together ...” The 

commenters understood from the EPA Conference Call on September 9, 2011, that if one storage 

vessel at a compressor station or natural gas processing plant is replaced, subpart OOOO would 

only be applicable to the one new storage vessel and not the series of storage vessels that might 

be manifolded together. The commenters request that the EPA confirm this interpretation in the 

final rule. 

One commenter (4218) states that the definition of “storage vessel” should not include multiple 

vessels that are either manifolded together or located at a single site in order to avoid imposing 

significant control costs on vessels with very low emission rates. Other commenters who 

provided suggested definitions for “storage vessel” also support deleting this language; these 

suggested revisions appear elsewhere in this section.

Response: The EPA agrees that the regulations should apply to each individual storage vessel, 

which is clearly stated in §60.5365 of both the proposed and final rule. The proposed definition 

of “storage vessel” confused this issue, and we have revised the definition to reflect this intent. 

Regarding the situation where one storage vessel at a site is replaced, we agree that only the 

replacement vessel would become subject to the rule; other existing vessels with which it is 

manifolded would not become subject, although the owner or operator would have to vent the 

entire manifold to a control device if the existing vessels share a common vent with the 

replacement vessel. 

Comment: One commenter (4230) asks for guidance on implementing the proposed 1 bbl/day 

exemption and whether sources can install additional condensate storage vessels to lower the 

annual average barrel throughput.

Response: As noted above, the final rule applies to each individual storage vessel based on its 

annual VOC emissions. Therefore, any questions concerning throughput are no longer relevant.

The EPA notes that subpart OOOO is an NSPS and that under the NSPS program, only new, 

modified and reconstructed sources are subject to the rule. Thus, we agree with the commenters 

that new and reconstructed (as defined under part 60) storage vessels are subject to the final rule. 

Existing storage vessels are not subject to the rule unless they are modified as defined in the final 

rule at §60.5430 and according to the provisions of §60.14 in the subpart A General Provisions

for the NSPS program.
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Comment: Four commenters (4191, 4192, 4246, 4251) request clarification on when storage 

vessels are considered modified for purposes of subpart OOOO.

Three commenters (4192, 4246, 4251) point out that existing storage vessels operating below the 

applicability threshold of the rule could, with the addition of a new well, exceed the threshold. 

According to two of the commenters (4192, 4246), the EPA verbally stated during the September 

9, 2011 NSPS Webinar that an increase in the throughput without a capital expense would not 

trigger NSPS for these tanks. These commenters request that the EPA confirm in the final rule 

that an increase in the production rate would not subject an existing tank to subpart OOOO. In 

addition, the commenters request clarification on whether this answer would also be the case for 

a tank that commenced construction after August 23, 2011.

One commenter (4191) requests that the EPA consider fracturing or refracturing a well to be a 

modification to the on-site storage vessel, and that the resulting emissions increases at the 

storage vessel be regulated under the “modified” storage vessel provisions. The commenter 

points out that fracturing and refracturing of existing wells will result in an increase in 

production and associated increase in emissions from the well operation, and that after fracturing 

or refracturing is complete, all emissions from the well operation are typically conveyed first 

through the separator and then through the storage vessel on-site used to store produced 

hydrocarbon liquids. The commenter concludes that ultimately, increases in well emissions after 

fracturing and re-fracturing activities are emitted from the storage vessel, warranting regulation 

under the modified storage vessel provisions.

One commenter (4251) asks if replacing a storage vessel with a new vessel of the same size 

would trigger this rule, or would the new vessel have to be larger and, thus, per the EPA's 

general definition of modification “increase 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 not previously 

emitted” to trigger the rule.

Response: The EPA agrees that an increase in production rate would not, by itself, subject an 

existing storage vessel to subpart OOOO. As an NSPS, subpart OOOO applies only to new, 

modified and reconstructed facilities. Under the part 60 General Provisions at §60.14(e)(2), a 

modification does not include “[a]n increase in production rate of an existing facility, if that 

increase can be accomplished without a capital expenditure on that facility.” 

However, this modification provision does not apply to a storage vessel on which construction 

commenced after August 23, 2011 because such vessels are considered new facilities under 

subpart OOOO. If a new storage vessel is not initially subject to control due to low VOC 

emissions but a subsequent increase in production rate increases its emissions above the 
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applicability threshold of 6 tpy, the vessel would become subject to the requirements of subpart 

OOOO upon the increase in emissions.

We do not agree that fracturing or refracturing a well should cause the associated existing 

storage vessels to be considered modified vessels subject to the requirements of subpart OOOO. 

We disagree with the commenter’s characterization that increased emissions from the fractured 

or refractured well are routed to and emitted from the associated storage vessels. We have added 

§60.5365(h) to the final rule to specify which well completion operations following fracturing or

refracturing are modifications, and also state that the completion operations do not affect the 

modification status of other equipment (including storage vessels).

Regarding the question of replacing a storage vessel, the replacement vessel would be considered 

a new storage vessel, rather than a modified vessel, regardless of its size or emissions relative to 

the existing tank it replaces, and would be subject to subpart OOOO. If the storage vessel’s VOC 

emissions are projected to be equal to or greater than 6 tpy, then the storage vessel would be 

subject to the emission reduction requirements of the rule. As defined at §60.5430 of the final 

rule, “modification” means “any physical change in, or change in the method of operation of, an 

affected facility....” Under subpart OOOO, an individual storage vessel is defined as the affected 

facility, and replacement of an entire affected facility does not fall under the intended scope of a 

“physical change in ... an affected facility.” Rather, a “physical change” to an affected facility is 

intended to connote an alteration of some part or parts of the affected facility that leaves other 

parts of the existing affected facility unaltered. Note that the threshold for “reconstruction” under 

NSPS at §60.15 is the “replacement of components of an existing facility to such an extent that 

... [t]he fixed capital cost of the new components exceeds 50 percent of the fixed capital cost 

that would be required to construct a comparable entirely new facility....” If an affected facility 

is reconstructed, it is subject to the NSPS regardless of whether emissions increase, provided that 

it is technologically and economically feasible to meet the applicable standards. Thus, the 

effective upper bound for expenditures for a physical change that could be considered a 

modification is 50 percent of the cost of a new affected facility, and replacement of an affected 

facility clearly requires the expenditure of the entire cost of a new affected facility. 

We are aware that §60.14(e)(1) of the part 60 General Provisions states that a modification does 

not include “[m]aintenance, repair, and replacement which the Administrator determines to be 

routine for a source category....” We do not believe that “replacement” as used in this provision 

is intended to refer to the replacement of an entire affected facility; rather, we believe that it 

refers to replacement of components of a larger affected facility. Again, replacement of an entire

affected facility would, at a minimum, constitute reconstruction. In any case, we do not believe 

that replacement of a storage vessel is ever a “routine” event in this industry.
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Comment: Three commenters (3459, 4240, 4275) believe that the regulations should be applied 

to existing storage vessels. One of the commenters (4240) asserts that existing storage vessels 

must be subject to the same degree of emissions control as is required for all other tanks. The 

commenter believes that such a standard would be cost-effective, especially if phased in over a 

reasonable time period. The commenter concludes that whatever control efficiency requirement 

the EPA ultimately applies to new tanks must be extended to existing vessels which are not 

already covered by the NESHAP, and must be applied on a reasonably strict retrofit schedule.

Response: The EPA has promulgated subpart OOOO as an NSPS, and is statutorily only able to 

apply these standards to new, modified and reconstructed sources. Therefore, we cannot apply 

these standards to existing storage vessels unless they are modified or reconstructed.

Comment: One commenter (4241) seeks clarification that refurbished tanks (e.g., tanks that are 

recoated) would not be considered a modified source. 

Response: As discussed above, subpart OOOO is an NSPS and, as such, applies only to new, 

modified and reconstructed facilities. Thus, a refurbished existing storage vessel would become 

subject to the rule only if it were modified or reconstructed.

Section 60.14 of the NSPS General Provisions specifies that a modification is “any physical or 

operational change to an existing facility which results in an increase in the emission rate to the 

atmosphere of any pollutant to which a standard applies.” Section 60.14 further states that 

modifications do not include “maintenance, repair, and replacement which the Administrator 

determines to be routine for a source category.” It is unlikely that refurbishing a storage vessel 

would, in itself, increase the emissions from the vessel or cause VOC or natural gas to be newly 

emitted. In addition, it is likely that refurbishment, as generally understood, would be considered 

maintenance or repair. Thus, it is unlikely that refurbishing a storage vessel would be considered 

a modification within the meaning of part 60.

Under §60.17, “reconstruction” means the replacement of components of an existing facility to 

such an extent that: (1) the fixed capital cost of the new components exceeds 50 percent of the 

fixed capital cost that would be required to construct a comparable entirely new facility, and (2) 

it is technologically and economically feasible to meet the applicable standards set forth in this 

part. It is unlikely that refurbishment, as generally understood, would involve costs exceeding 50 

percent of the cost of a new storage vessel and, thus, unlikely that refurbishing a storage vessel 

would be considered reconstruction.

Comment: One commenter (4230) requests clarification on why the cost per ton analysis was 

done on 6 tpy, but storage vessels under 10 tpy potential are exempted. Another commenter 

(4161) states that the discrepancy between the throughput thresholds (which are based on 
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emissions of 6 tpy) and the 10 tpy exemption in the definition of “storage vessel” leaves storage 

vessels between 6 and 10 tpy undefined. A third commenter (4240) presumes that the EPA did 

not intend to exempt tanks with emissions less than 10 tpy, and states that EPA must delete the 

“10 tpy” language from its definition section, as it conflicts with the lower emissions threshold it 

sets in the substantive storage vessel standard itself.

Another commenter (4159) supports the inclusion of the 10 tpy threshold in the proposed 

definition, believing that it provides a minimum level of throughput and emissions to ensure that 

any controls can meet a cost-effectiveness test and not result in unnecessary flaring and 

emissions from such flaring.

Response: In the proposed rule, the EPA did not intend to exempt storage vessels with potential 

VOC emissions of less than 10 tpy; this exemption was included in the proposed definition of 

“storage vessel” inadvertently. In the final rule, no emissions level is included in the definition. 

The applicability of the storage vessel emission reduction requirements of the final rule is 

determined based on the threshold of 6 tpy of uncontrolled VOC emissions, a level at which 

controls were determined to be cost effective.

Comment: One commenter (4230) requests specific guidance on exactly how the potential VOC 

emissions are to be calculated for this 10 tpy threshold for national consistency. 

Response: The commenter’s questions are generally no longer relevant as a result of the 

provisions of the final rule. The final rule clearly applies to each individual storage vessel; 

storage vessel emissions are not aggregated to determine applicability. Under the final rule, 

process vessels, such as surge control vessels, bottoms receivers and knockout vessels, are not 

considered storage vessels. Finally, the final rule determines applicability based on VOC 

emissions, not throughput.

Comment: One commenter (4266) states that the EPA proposed throughput thresholds pegged 

to 6 tpy of VOC emissions in the storage tank provisions of §60.5395(a), as well as a 10 tpy 

emissions threshold in the definition of a storage vessel at §60.5430. According to the 

commenter, these thresholds do not determine whether or not a given structure is a storage 

vessel, but rather they are criteria for determining whether a given storage vessel is subject to the 

control requirements of the rule. As such, the commenter believes that the more appropriate 

location for them in the rule is at §60.5395, rather than in the definitions, and requests that the 

EPA move the emissions threshold from the storage vessel definition at §60.5430 to the storage 

vessel standard at §60.5395, and specify a threshold of 12 tpy. 

Response: In the final rule, the definition of “storage vessel” does not include a VOC emissions 

threshold; as noted previously, this threshold was included in the proposed definition 
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inadvertently. The final rule includes an applicability threshold of 6 tpy, which is located in 

§60.5395.

Comment: Two commenters (4192, 4246) support the proposed §60.5395(b), which reads: 

“This standard does not apply to storage vessels already subject to and controlled in accordance 

with the requirements for storage vessels in 40 CFR § 63.766(b)(1) or (2) of this chapter.” 

Response: We agree with the commenter that storage vessels that are already subject to and 

controlled in accordance with the requirements for storage vessels in 40 CFR 63.766(b)(1) or (2) 

should not be subject to the requirements of subpart OOOO. Accordingly, we have maintained 

this exemption in the final rule, although it has been rephrased to refer to 40 CFR part 63, 

subpart HH.

Comment: One commenter (4263) states that the EPA should add overlap provisions for other 

Federal standards, for example subpart Kb, to the proposed §60.5395(b). 

Response: The EPA agrees with the commenter. Accordingly, §60.5395(d) of the final rule 

provides exemptions for 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.”

Comment: One commenter (4218) believes it is best to regulate storage tanks based on VOC 

emissions limits and not throughputs and therefore suggests that the storage vessel standards in 

§60.5395 include an exemption with an emissions threshold of 10 tpy of VOC (removing that 

threshold from the definition of “storage vessel”).

Response: As discussed elsewhere in this document, the applicability threshold for storage 

vessels in the final rule is 6 tpy of VOC emissions, rather than in terms of throughput as 

proposed. This threshold is located in §60.5395 of the final rule as requested by the commenter.

Comment: One commenter (4241) notes that proposed §60.5395 reads: “Storage vessels that 

meet either one or both of the throughput conditions specified in paragraphs (a)(1) or (a)(2) of 

this section are not subject to the standards of this section.” The commenter believes that the 

EPA intends that both conditions must be met to be excluded from the rule and suggests that 

“either one or” be stricken from the language of the rule.

Response: The proposed language cited by the commenter has been eliminated from the final 

rule. Applicability of the final rule to storage vessels is determined based on VOC emissions, and 

the same applicability level of 6 tpy applies to both oil and condensate storage vessels.
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Comment: Two commenters (4220, 4263) believe it is best to regulate storage tanks based on 

VOC emissions limits and not throughputs and contend that the EPA should move the emission 

thresholds from the definition of “storage vessel” in §60.5430 to the affected facility definition 

section §60.5365(e). One of the commenters (4263) also believes the EPA should add provisions 

for PTE determinations for storage tanks at upstream facilities with declining production. The 

commenter believes that the definition of "storage vessel" proposed by the EPA is inconsistent 

with the definition set out in relevant part 60 and part 63 standards, and that thresholds pertaining 

to the affected facility definition should be provided in §60.5365. The commenter notes that the 

EPA has acknowledged that an owner or operator may consider inherent limitations on 

production in PTE determinations for oil and gas production facilities, and adds that defining 

"maximum hydrocarbon liquid throughput" to be used for purposes of PTE determinations for 

storage vessels would remove uncertainty. 

Response: As discussed previously, the storage vessel applicability provisions of the final rule 

are based on VOC emissions rather than throughput, and the applicability threshold is included 

in §60.5395 where the control requirements are set out. We do not agree that the applicability 

threshold should be included in the definition of the storage vessel affected facility. Rather, all 

new, modified or reconstructed storage vessels are considered affected facilities, and the owner 

or operator is required to determine and report whether each new, modified or reconstructed 

storage vessel is subject to the control requirements of the rule. That is, the applicability 

threshold determines which storage vessel affected facilities are subject to the requirement to 

control emissions, not which storage vessels are affected facilities.

Regarding the comment that the proposed definition of “storage vessel” was inconsistent with 

the definitions in other related part 60 and 63 standards, we agree that certain revisions to the 

definition were necessary. Accordingly, we have revised the final definition to more clearly 

define “storage vessel” in a manner that is more consistent with the definitions in other related 

standards.

Comment: One commenter (4245) states that the proposed storage vessel emissions standards 

that would apply to all wells producing 1 bbl/day or more of condensate or 20 bbls/day or more 

of crude oil would have the effect of greatly expanding the number of oil and gas batteries 

needing emission control, which is not justified since State-level standards and regulation 

adequately define emission thresholds and control requirements for such facilities. The 

commenter asserts that this arbitrary threshold has not been demonstrated to be scientifically 

justified and will greatly increase operational costs throughout the industry. The commenter adds 

that existing State permit restrictions prescribe yearly emission limits, thus additional Federal 

oversight is unwarranted. The commenter recommends that the EPA continue to defer to State 

agencies with respect to oil-field emission quantification and regulation.
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Response: As previously discussed, whether the control requirements of the final rule apply to a 

storage vessel is based on VOC emissions rather than throughput, and the threshold for 

applicability has been set at a level which our analysis shows to be cost effective. On this basis, 

we believe that the final rule requires control for the appropriate population of storage vessels.

Regarding the comment that the EPA defer to State regulation of the oil and gas industry, we 

note that section 111 of the CAA requires the EPA to promulgate and periodically update an 

NSPS for each listed source category to require the application of BSER for that source category. 

During development of this updated NSPS for the oil and gas industry, we evaluated the baseline 

emissions from storage vessels in this source category, including State control requirements, and 

determined that the final rule will reduce VOC emissions in a cost effective manner. In cases 

where storage vessels are subject to both State requirements and the requirements of subpart 

OOOO, part 60 allows for any required notifications and reports to be consolidated provided the 

consolidated items meet all the requirements of the NSPS.

Comment: One commenter (4263) asserts that the term "condensate" is well understood in the 

industry consistent with the definition of the term already promulgated in part 63 and part 98; 

therefore, rather than inventing a new definition of a common term, the exemption thresholds in 

proposed §60.5395 should simply be based on the API gravity of the hydrocarbon liquid (crude 

oil or condensate). That is, the commenter suggests that the EPA replace the term "condensate" 

with "hydrocarbon liquid with an API gravity equal to or greater than 40 degrees" in paragraph 

(a)(1), and replace the term "crude oil" with "hydrocarbon liquid with an API gravity less than 40 

degrees" in paragraph (a)(2). In addition, the commenter advises that the EPA should revise the 

definition of "condensate" to reflect similar definitions in parts 60, 63 and 98. Another 

commenter (4193) advocates the removal of the definitions of “condensate” and “crude oil.”

Response: Under the terms of the final rule, these comments are no longer relevant. The final 

rule bases the applicability of the control requirements for all storage vessels on VOC emissions 

without regard to whether they are used to store crude oil or condensate. 

Comment: Three commenters (4177, 4220, 4266) believe that there should be exemptions for 

blowdown and emergency tanks, due to their infrequent use. One commenter (4266) states that 

the EPA’s capacity and vapor pressure thresholds are based on emissions that would be expected 

if these tanks were in continuous operation, but tanks such as blowdown tanks, emergency tanks, 

and dehydrator drip tanks are used only infrequently. The commenter contends that the EPA 

should specify a threshold for storage vessels in infrequent use, and specify a work practice for 

such tanks. According to the commenter, there is precedent for this in the Gasoline Distribution 

area source rule. The commenter adds that the EPA must allow for open-top blow down tanks 

because a well cannot be blown down to a closed top tank.
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One commenter (4258) suggests that coal bed methane (CBM) and other facilities with low VOC 

gas content (e.g., less than 10 percent) be specifically exempted from the tank requirements. 

One commenter (4177) states that there should be an exemption for weathered or stabilized crude 

oil storage tanks based on the lack of potential flash emissions from such tanks. The commenter 

adds that tanks storing stabilized crude may also be subject to the control requirements of NSPS 

subpart Kb and utilize a floating roof and seals as a control methodology, so this control option 

should be added if the exemption from subpart OOOO controls is not included.

Response: As previously discussed, the final rule bases the applicability of storage vessel control 

requirements on annual VOC emissions. If storage vessels of any of the types mentioned by the 

commenters are below the threshold of 6 tpy of VOC emissions, they are exempt from the 

control requirements of the final rule. If their emissions are equal to or greater than 6 tpy, they 

are subject to the control requirements. Our analysis shows that controls are cost effective at this 

level of emissions, without regard to the type of tank or the fluid being stored. Accordingly, we 

believe that other exemptions of the types suggested by the commenters are generally 

unnecessary. In addition, we note that the final rule contains an exemption for storage vessels 

that are subject to and controlled in accordance with subpart Kb. Concerning open-top blowdown 

tanks, these storage vessels would be subject to the control requirements if VOC emissions are 6 

tpy or greater. The final rule does not specify that the tanks have to be closed, only that VOC 

emissions must be reduced by 95 percent.

2.5.3.2 Throughput Cutoffs

Comment: Numerous commenters (4135, 4159, 4161, 4176, 4177, 4191, 4193, 4216, 4217, 

4218, 4219, 4220, 4225, 4228, 4231, 4233, 4240, 4241, 4244, 4246, 4251, 4252, 4256, 4263, 

4266, 4269, 4281, 4356) assert that the applicability for storage vessels should be based on VOC 

emissions, rather than liquid throughput as proposed. These commenters often state that the 

emission factors used by the EPA in developing the throughput thresholds were drawn from a 

very limited data set that did not take into account the variability in volatility of stored liquids 

and other parameters that affect emissions. Commenters indicate that the emission factor that the 

EPA used to develop the throughput thresholds are too high, resulting in thresholds that are so 

low that many storage vessels with low emissions would be required to install controls that are 

not cost effective.

Five of the commenters (4161, 4177, 4219, 4228, 4266) reexamined the study and data used by 

the EPA to develop the emission factor, and conclude that it was inappropriate for the EPA to 

use such data. Four commenters (4191, 4216, 4225, 4241) compare the EPA’s emission factor to 

the lower emission factors used by Colorado, which vary by geographic area, to show that 

storage vessels with low emissions would be regulated by the proposed rules. Three commenters 
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(4218, 4219, 4258) use case-specific information to show that storage vessel emissions are lower 

than estimated by the EPA.

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. We originally proposed the applicability threshold for 

storage vessel control requirements in terms of throughput because we believed that this would 

simplify applicability determinations for sources, particularly small sources. However, because 

emission factors vary widely, we now recognize that it is inappropriate to develop liquid 

throughput thresholds based on average emission factors. Accordingly, the final rule includes a 

VOC emissions threshold of 6 tpy for applicability of storage vessel controls.

Comment: Several commenters prefer that the storage vessel applicability metric be based on 

VOC emissions (3618, 4159, 4177, 4192, 4193, 4217, 4218, 4219, 4220, 4225, 4228, 4231, 

4240, 4241, 4251, 4252, 4256, 4264, 4266, 4273, 4176, 4281, 4191) and recommend specific 

thresholds ranging from 20 tpy to 1.5 tpy for crude oil tanks. The commenters’ rationales for 

these thresholds are based on such reasons as: matching state thresholds, maintaining costeffectiveness (12 tpy based on an independent analysis supported by several commenters), 

applying different levels in different areas depending on factors in each region, avoiding 

unnecessary flaring and associated emissions, and using low thresholds to maximize emission 

reductions.

Response: Based on the EPA’s analysis, we have selected an emissions threshold of 6 tpy VOC. 

We selected this threshold by evaluating cost effectiveness for storage vessels with emissions of 

3, 6, 12, and 30 tpy and determined that control for vessels with emissions of 6 tpy is cost 

effective. Based on an estimated annual average cost of $19,281 (including savings from 

recovered product), controlling storage vessels with emissions of 6 tpy will result in a cost 

effectiveness of about $3,400 per ton of VOC reduced. Further details of these calculations are in 

the docket.

Comment: One commenter (4356) states that if the EPA continues to rely on a throughput for 

applicability, the proposed level of 1 bbl/day for condensate storage vessels is not justified 

because it would be more stringent than the NSPS for refineries and chemical plants. The 

commenter also notes that the TCEQ has adopted requirements for a nonattainment area in Texas 

and proposed requirements for another that require 95 percent control of all storage vessels at a 

site when there is a throughput of 1,500 bbl/yr of condensate.

Response: As discussed previously, the final rule bases the applicability of storage vessel control 

requirements on annual VOC emissions, not liquid throughput.
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Comment: Four commenters (4177, 4220, 4266, 4281) favor VOC emissions as the applicability 

metric and add that the proposed rules need capacity and vapor pressure thresholds, in the same 

manner as all other EPA rules with storage vessel provisions. The commenters believe that the 

capacity and vapor pressure thresholds specified in NSPS subpart Kb should be considered for 

tanks that do not have the potential for flash emissions. 

Another commenter (4231) recommends that the standards apply only to storage tanks with a 

capacity greater than 500 bbl.

One commenter (4240) states that if the EPA is going to include an exemption for some storage 

vessels in the rule, it should further condition its exemption by limiting it to only small 

throughput tanks with low vapor pressure (in addition to lowering the threshold and applying it 

to tank batteries). Such an exemption would ensure that only tanks which do not contain 

significantly volatile substances are exempt. The commenter notes that such vapor pressure 

limitations are used in certain California air quality districts.

Response: The EPA disagrees that subpart OOOO needs capacity and vapor pressure thresholds. 

As discussed above, the applicability of storage vessel control requirements in the final rule is 

based on annual VOC emissions, and the threshold level of 6 tpy has been determined to be cost 

effective without regard to the type of vessel or fluid stored. In addition, the final rule provides 

exemptions for 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.

Comment: Eight commenters (4177, 4217, 4219, 4220, 4228, 4233, 4266, 4281) favor VOC 

emissions as the applicability metric and add that the emissions threshold should be a standard, 

rather than a trigger for once-in, always-in controls. The commenters note that initial production 

curves from wells typically are high and then significant decline occurs over time. Two 

commenters (4219, 4228) indicate that if the threshold was not met in a given future year, then 

the tank would not be subject to the rules during that year. Five commenters (4177, 4217, 4220, 

4266, 4281) state that removal of controls should be allowed when emissions decline.

One commenter (4220) states that the proposed rule would essentially eliminate the use of the 

WDEQ presumptive BACT minor source permitting program, whereas the EPA should instead 

be using the program as the model for its own rulemaking. The commenter believes that the 

WDEQ’s program allows for the wide variability in the dynamics of oil and gas production and 

provides a cost effective, common sense permitting program to lower emissions to equivalent 

standards desired by the EPA.
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One commenter (4177) adds that some fields have a 1-year decline rate of 80 percent or more, 

and control options must match actual conditions to be both effective and of reasonable cost. The 

commenter indicates that the EPA analysis for tank control technologies does not address this 

difficult design challenge. According to the commenter, under proposed control requirements, 

multiple sets of controls may be required to control the falling levels of emissions from a typical 

tank or tank battery, and the cost of installing multiple controls over the life of a tank was not 

included in the EPA documentation for this rule. By providing a low level emission rate where 

controls are no longer required, the commenter believes that the rule can maintain consistent and 

defensible cost effectiveness for tank control requirements. Similarly, another commenter (4217) 

states that without this sunset provision, the EPA’s cost-benefit analysis is significantly flawed as 

the production declines and the tank emissions approach a lower economic limit for production 

because the annual O&M cost will eventually approach or exceed the limits of viable production 

and profitability.

Another commenter (4228) indicates that removing the control device from storage tanks with 

emissions below the threshold could reduce pollutant emissions. The commenter points out that 

reduced VOC PTE is associated with lowered production rates and/or less volatile fluids, and as 

these parameters continue to decrease, there will eventually be insufficient gas emissions to 

maintain a stable flame in a flare or other combustor designed for higher production and gas 

emission levels. The commenter believes that this would result in poor combustion and an 

increase in pollution, including HAPs and other products of incomplete combustion. 

Alternatively, according to the commenter, supplemental fuel could be used but this would 

increase NOx emissions and operating costs.

Response: We do not agree that the applicability threshold for the storage vessel emission 

control requirements should be a standard rather than a one-time trigger. We understand that the 

production rate of the well may decrease over time, which may affect the level of emissions from 

the tank. However, future refracturing operations have the potential to restore the production rate 

of the well to near original levels, or at least to levels that may increase emissions to the 6 tpy 

threshold. Thus, we believe that once a storage vessel is shown to be capable of emitting at least 

6 tpy, the tank should remain controlled.

Additionally, we believe that the potential burden to both the facility and the regulatory agency 

of continually changing the status of the source is unreasonable and poses significant compliance 

issues.

Comment: One commenter (4256) indicates that under the API gravity threshold of 40 degrees 

of the proposed regulation, the majority, if not all, new production facilities (tank battery) in the 

Bakken would be considered condensate producing wells, requiring 95 percent controls for every 

new production facility producing more than 1 bbl/day. The commenter believes that the EPA’s 
125

proposal of a production rate threshold was intended to simplify the implementation of the rule 

for industry overall, but it unnecessarily and inadvertently has greatly increased the amount of 

facilities, including all new Bakken oil production facilities, that would require expensive 

controls. The commenter does not believe that the EPA intended to force operators to install 

costly controls at facilities from unconventional plays such as the Bakken if the production from 

the associated wells is as little as 1 bbl/day. 

Response: This comment is no longer relevant because the final rule bases the applicability of 

storage vessel control requirements on annual VOC emissions rather than liquid throughput. The 

EPA’s analysis shows that the final applicability threshold of 6 tpy is cost effective regardless of 

the type of vessel or fluid stored.

Comment: Five commenters (4135, 4228, 4241, 4258, 4266) who advocate using a VOC 

emissions applicability metric also recommend methods for determining VOC emissions. One 

commenter (4135) recommends that the EPA specify the methods to be used to determine 

emissions because there are many methods, and some are far less accurate than others. Another 

commenter (4241) suggests that basin-wide emission factors developed by some State or local 

agencies could be used to determine applicability or, alternatively, the data and simulations being 

developed under the Mandatory Reporting Rule for GHG could be used as compliance data for 

the NSPS which would simplify the data management for operators. 

One commenter (4266) states that appropriate methods of estimating flashing emissions include 

process simulation software and E&P TANK, while another commenter (4228) states that there 

are numerous tools for determining VOC PTE for a liquids hydrocarbons storage vessel, 

including the Vasquez-Beggs Equation (VBE) calculation methodology and other correlation 

equations, equation of state (EOS) calculation programs such as E&P TANK, gas oil ratio 

(GOR) and throughput determinations, and process simulators such as HYSIM, HYSYS, 

WINSIM, and PROSIM. The commenter recommends that the final rule allow operators to 

determine VOC PTE based on available data and tools provided the approach is documented.

One commenter (4258) states that “potential” is not defined in this subpart and the traditional 

definition of "potential" does not realistically apply to storage tanks and, therefore, this should be 

changed to "actual" emissions as calculated by E&P TANK 2.0 or another method accepted by

the Administrator (e.g., HYSIS) based on the first 30 days of production and appropriate decline 

factor (default decline factor of 0.6 if other supporting information is not provided).

Response: We disagree that the EPA should specify which methodologies must be used to 

calculate VOC emissions. Different methodologies may be more appropriate than others for 

certain situations, and it would be very difficult to determine each possible situation and 

determine the appropriate methodology for that situation. Additionally, such a prescriptive 
126

requirement would not allow as yet undeveloped methodologies to be used, or would require 

amending the rule whenever a new methodology was released. For these reasons, the final rule 

specifies that any generally accepted methodology may be used to estimate emissions.

Comment: Several commenters (3560/4258, 4192, 4219, 4228, 4241, 4246, 4266) object to the 

requirement in the proposed rule to use flow meters to determine the annual throughput of 

storage vessels. According to three of the commenters (4192, 4219, 4246), it is not practical to 

use a flow meter because flow measurement for individual tanks is costly and inaccurate, as the 

liquid is near-atmospheric conditions and flashing can occur across the flow measurement 

orifice. Two commenters (4192, 4246) add that they are concerned that the Administrator will 

not be able to issue approval to use alternative methods for determining throughput in a timely 

manner, as provided for in the proposed rule. These commenters recommend revised language 

that would allow the use of tank strapping and load tickets or condensate sales, which the 

commenters state are the usual methods of measuring throughput in the industry, with the option 

for metering at the discretion of the owner/operator. 

Another commenter (4241) similarly suggests that the EPA allow more common monitoring 

methods, such as revenue and accounting system, because the sales volume condensate and 

crude oil is carefully measured and recorded. One commenter (4228) suggests revised language 

that would allow the use of “standard oil and gas field methods including, but not limited to, 

strapping and tanker truck measurements.”

One commenter (4266) contends that the flow of condensate from a production separator to a 

storage vessel is intermittent and short duration, while every flow meter has a “latency period” 

that provides unreliable data for some period of time (ranging from a few seconds to several 

minutes depending on the technology) after flow begins. According to the commenter, it is 

common for either a turbine meter or a magnetic meter in dump service to report values that are 

5-10 times higher than sales volumes that are eventually reported to accounting systems. The 

commenter asserts that there is no technology that will allow a 1 bbl/day condensate stream or a 

20 bbl/day oil stream to accurately record flow volume into a storage tank. Accordingly, the 

commenter recommends that the preferred method of quantifying liquid hydrocarbons 

throughput in the regulation be changed to “based on Lease Automatic Custody Transfer 

(LACT) meter, haul records (run tickets), sales tickets, or other sales documentation to show the 

amount transferred to a truck or liquids pipeline.” Another commenter (4192) similarly states 

that the EPA should provide for the use of (LACT) meter, crude oil / condensate truck load out 

tickets or tank strappings or metering to determine whether a storage tank is exempt from the 

subpart OOOO standards.

Two commenters (3560,4258) recommend that the EPA accept manual tank gauging as an 

acceptable measurement for annualized daily average production rate. The commenters state that 
127

the requirement for flow meters is inconsistent with regulation on Federal land as the Bureau of 

Land Management requires operators to manually gauge crude oil/condensate. The commenters

add that flow meters will not be any more accurate than monthly tank gauging since water is 

periodically pulled from these tanks due to carryover from the separator; field operators 

manually make the adjustments for water pulled from the tank to the tank level so similar 

adjustments would also be required for flow meter readings. Furthermore, the commenters

express concern that flow meters would be subject to freezing during colder months from the 

water carryover.

Response: The final rule does not require the use of liquid throughput flow meters because the 

applicability of the storage vessel control requirements is determined based on annual VOC 

emissions, rather than liquid throughput as proposed. As discussed above and in section IX.E of 

the preamble to the final rule, we made this change in part because we are convinced that VOC 

emissions from stored fluids in the ONG industry are too variable to be regulated based on an 

average emission factor. Other factors in our decision to change the applicability metric include

the issues raised by these commenters.

The EPA agrees that the flow characteristics of the liquid flow to the tanks may be highly 

inconsistent and instead resemble a series of multiphase plugs separated by gas pockets. 

Additionally, as the liquid pressure decreases, it may tend to flash across a flow measurement 

orifice. These factors may cause inaccurate flow readings. In addition, a VOC emissions 

threshold eliminates issues raised by some commenters with the use of flow meters to monitor 

throughput. These included further technical issues with the ability to accurately measure 

throughput and where throughput should be measured, cost issues, and issues related to data 

acquisition at remote locations without electrical service.

Comment: One commenter (4161) notes that the proposed §60.5420(b)(6)(ii) requires the source 

to document that crude oil throughput is less than 21 bbl/day. The commenter believes that this is 

a typographical error because the proposed applicability threshold in §60.5395(a) is 20 bbl/day. 

This commenter and another (4192) make a similar comment about the proposed language in 

§60.5420(c)(5)(ii).

Response: This comment is no longer relevant because the final rule bases the applicability of 

the control requirements for storage vessels on annual VOC emissions rather than liquid 

throughput. Thus, the language in question is not included in the final rule.

2.5.4 Control Techniques

Comment: One commenter (4275) asserts that Wyoming requires 98 percent control of VOC 

and HAP from storage vessels with the potential for flash emissions. The commenter 
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recommends that the EPA adopt an equivalent level of control in the NSPS, which the 

commenter believes would carry out the law and secure additional health and environmental 

benefits.

Another commenter (4240), while agreeing that some combination of combustion devices and 

VRUs on storage tanks constitutes BSER for this class of facilities, asserts that the EPA must 

raise its control efficiency requirements and limit or eliminate the use of combustion devices. 

Citing available information, the commenter states that a control efficiency of 98 percent is 

achievable, noting that it is required in Wyoming, and that, therefore, the proposal falls below 

BSER. The commenter notes that VRUs recover material that can be used or sold, while flares 

create secondary emissions including NOx, SO2, PM and other emissions, and opines that the 

EPA must avoid these secondary impacts wherever feasible. The commenter asserts that under 

the statutory standard for new source emissions under CAA section 111(b), the EPA must ensure 

that VRU-level control efficiencies are achieved in all applications so long as that does not 

impose exorbitant costs on industry, and must do so by requiring all affected sources to achieve 

control efficiencies of 98 percent, with no secondary emissions of NOx, except where the 

operator can demonstrate to the EPA that it cannot install a VRU. In that case, the commenter 

indicates that the EPA could allow a 95 percent control efficiency (which can be met either by 

VRU or flare), with that exemption subject to review or challenge.

On the other hand, two commenters (4216, 4267) contend that it has not been adequately 

demonstrated that VRUs and flares can achieve 95 percent control. One of the commenters 

(4267) asserts that the emissions from oil and gas exploration and production are so small they 

cannot be measured so must be calculated. Based on this position, the commenter asserts that it is 

highly speculative that a 95-percent reduction is possible. The commenter states that all 

references to a 95-percent reduction in emissions must be stricken. The other commenter (4216) 

contends that the limited data base used by the EPA to assess storage vessel emissions (coming 

from a relatively narrow study in Texas) cannot generate the robust information needed to 

adequately demonstrate 95-percent control.

Response: The EPA disagrees with the commenters who contend that 98 percent control is 

technically achievable on a continuous basis. The data we have reviewed support a BSER level 

of 95 percent control and indicate that 98 percent control cannot be achieved continuously for all 

tanks. Therefore, 98 percent control cannot be considered BSER.

Likewise, we disagree with the commenters who allege that there is inadequate data to 

demonstrate that VRUs and flares can achieve 95 percent reduction. The data clearly support a 

BSER level of 95 percent control.
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Comment: One commenter (4161) recommends that the EPA allow for an alternative control 

technology that meets or exceeds the required control level, subject to the Administrator’s 

approval. The commenter does not wish to discourage the development of new technologies for 

reducing emissions from storage vessels.

Another commenter (4263) suggests that the EPA revise proposed §§60.5395 and 60.5415(e) to 

provide for the alternative of routing emissions to a fuel gas system or process. The commenter 

notes that the proposed rule already includes a definition of “routed to a process or route to a 

process” and that other standards such as the Refinery MACT subpart CC and UUU 

categorically exclude emission points that are routed to a fuel gas system.

Four commenters (4241, 4251, 4266, 4281) request that the EPA consider providing a floating 

roof control option in the final rules as an alternative to routing vapor to a control device. One of 

the commenters (4251) notes that her company uses internal floating roof tanks, which are 

designed to minimize emissions and control VOC emissions by 95 percent, but they are not 

compatible with a VRU. The commenter adds that another factor that the EPA did not include in 

its discussion of the feasibility of VRUs is corrosion, which can occur if air is drawn into the 

tanks by the VRU and can result in leaks and expensive repairs. Another of the commenters 

(4266) states that floating roof tanks are not viable for tanks with flash emissions or very small 

tanks, but may be suitable for larger production field tanks storing stabilized crude oil. This 

commenter suggests that the EPA specify that a storage vessel storing a VOL with maximum 

true vapor pressure of less than 11.1 psia may be equipped with a floating roof, and that the 

floating roof requirements be specified in the same manner as in Table 1 of NESHAP subpart 

BBBBBB. Another commenter (4281) likewise recommends that the floating roof option be 

made available for storing hydrocarbon liquids with maximum true vapor pressure of less than 

11.1 psia.

Response: Section 60.5395 of the final rule has been revised to specify that storage vessels with 

VOC emissions of 6 tpy or greater must control emissions by 95 percent, rather than prescribing 

a closed vent system and control device as in the proposed rule. Therefore, you may choose any 

control technology that achieves at least 95 percent control, including floating roofs. We note, 

however, that the owner or operator must still demonstrate initial and continuous compliance as 

directed in the final rule.

Comment: Four commenters (4209, 4219, 4246, 4266) believe that there will be a shortage of 

control equipment available to meet the proposed storage vessel requirements. Two of the 

commenters (4219, 4246) suggest the final rule allow 1 year after the effective date for 

compliance with the storage vessel provisions. 
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One commenter (4209) believes that this expected shortage will affect the 115,000 plus oil wells 

and many of the 65,000 gas wells (that produce liquids) located in Oklahoma. To reduce the 

burdens and cost impacts, the commenter requests that the EPA consider less costly methods 

such as work practices and standards that operators (especially smaller operators/businesses) 

could implement.

One commenter (4266) notes that the requirements in subpart OOOO for storage tank control 

devices cite the performance test requirements specified in §63.772(e) of subpart HH, which 

include a provision for the performance test to be conducted by the manufacturer as specified in 

§63.772(h). According to the commenter, it will require considerable lead time before such 

“manufacturer certified” control devices are readily available. The commenter requests that the 

effective date of the storage tank requirements under subpart OOOO be delayed for 3 years to 

allow time for the specified control devices to become available.

Response: The EPA disagrees that there will be a significant shortage of control equipment to 

meet the storage vessel requirements. We note that because it is an NSPS, subpart OOOO applies 

only to new, modified and reconstructed storage vessels, and not to the existing wells in 

Oklahoma or other States. Existing wells will be affected only to the extent that they are 

modified or reconstructed after August 23, 2011.

The final rule allows the operators of affected storage vessels at a well site with no other wells in 

production up to 30 days to determine the VOC emission rate and, if the storage vessels are 

subject to control, an additional 30 days to install the control system and bring it into operation. 

This approach was based on the approach currently used in Wyoming, and we believe that the 

Wyoming experience demonstrates that this provides adequate time for control systems to be 

acquired and installed.

We add that, while no longer citing the requirements of §63.772(e) of subpart HH, the final rule 

allows sources to demonstrate compliance through the use of a control device that has been 

certified by the manufacturer after performance testing. We agree that there may be some lag 

time before such devices are available, but we believe that there will be ample availability of 

controls that will meet the final rule. Until manufacturer-certified units are available, sources will 

simply have to demonstrate compliance through one of the other methods provided in the final 

rule.

2.5.4.1 Vapor Recovery Units

Comment: On commenter (4191) suggests that the EPA include a requirement for monitoring 

the downtime for VRUs. In addition, the commenter requests that the EPA clarify whether it 

considers a VRU subject to the testing requirements for non-condenser control devices (citing 76 

FR 52785).
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Response: VRU downtime would fall under startup, shutdown or malfunction. The final rule 

specifies that compliance must be achieved at all times, and that there is no exemption from the 

rule requirements during these periods. We do not see the need to include monitoring specific to 

VRUs other than what is already present in the final rule. Concerning the comment on VRU 

testing requirements, any control device that is not a condenser is subject to performance testing 

every five years.

Comment: One commenter (4192) states that a VRU that is part of a process should not be 

considered a control device, and therefore not subject to testing and monitoring.

Response: The EPA disagrees with the commenter. We consider a VRU to be a control device 

subject to all the relevant requirements of the final rule for control devices.

2.5.4.1.1 Emission reduction

Comment: Two commenters (4192, 4246) indicate that VRUs that recover product and return it 

to the process collect 100 percent of emissions when they are running and none of the vapors 

when they are not. The commenters note that proposed subpart OOOO would require a VRU to 

operate at 95 percent efficiency at all times, without any provision for downtime associated with 

maintenance. Thus, according to the commenters, each VRU maintenance event would require 

the operator to generate excessive emissions reports, document an NSPS deviation and prepare 

an affirmative defense. The commenters propose that industry should be required to comply with 

an annual overall efficiency of 95 percent, which the commenter believes would ensure a high 

level of VRU performance while permitting brief outages for maintenance and process upsets.

One commenter (4320) makes many of the same points about VRU operation and efficiency but 

concludes that the operator of a VRU would be required to install and operate a combustion 

control device as back-up for times when the VRU is down due to maintenance or malfunction, 

which would be very expensive. The commenter suggests that the EPA should encourage the use 

of VRUs over combustion control devices by providing credit to the operators of VRUs that their 

over-compliance warrants.

Another commenter (4218) also makes many of the same points, and expresses concern that the 

compliance provisions of subpart HH that are cited in subpart OOOO do not accommodate the 

type of VRUs that the commenter’s company uses which capture and compress storage tank 

vapors and route them back to the inlet of the gas processing plant. The commenter suggests 

revisions to the sections in subpart HH that are cited in subpart OOOO to address such VRUs.

One commenter (4230) has observed a different kind of VRU in operation (sometimes referred to 

as an “ejector” VRU) that recycles the storage vessel emissions back into the gas gathering line 
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with a closed-vent system, which achieves 100 percent control when in operation. However, the 

commenter notes that the prescribed percent reduction performance test requirement in subpart 

HH is problematic because it is based on upstream and downstream measurements. The 

commenter suggests that the EPA provide compliance demonstration procedures for such VRUs 

using the closed-vent system standards set forth in subpart HH §63.771(c), the no detectable 

emission test procedures set forth in §63.772 (c) and the monitoring and inspection requirements 

of §63.773 (c), which would alleviate the need for a percent emission reduction performance test. 

The commenter added that the VRU would need to be operated continuously.

Response: We do not believe that the owner or operator of a VRU must also install a back-up 

flare. While it is true that VRUs can be expected to experience some downtime for maintenance 

and malfunctions, VRUs when operating properly generally approach 100 percent efficiency. 

Since the rule requires a minimum of 95 percent efficiency, we believe this difference adequately 

compensates for any reduced efficiency that may occur during non-routine operations.

We reiterate that the final rule no longer cites to the requirements of subpart HH. Instead, we 

decided to remove from 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. 

2.5.4.1.2 Cost impacts and cost effectiveness

Comment: Six commenters (3560, 4258, 4219, 4228, 4266, 4320) assert that the EPA 

underestimated the control and monitoring costs for storage vessels. One commenter (4266) 

contends that the control cost of $18,983 presented in the TSD is inconsistent with the EPA Air 

Pollution Control Cost Manual. The commenter presents a cost analysis said to be based on the 

EPA Control Cost Manual methods which results in an annual cost of controls of $55,207. The 

commenter indicates that this cost is conservative in that it includes no costs for data 

management required by the proposed rule, and it does not adjust for inflation since calendar 

year 2000. 

Two commenters (3560,4258) present data compiled from flare manufactures that have provided 

flares for oil and gas storage tank use. According to the commenters, the cost of the flare with 

installation comes to $23,000 of initial costs plus $5,000 annual operating costs. The commenters 

state that for the scenarios included, these costs equate to $5,000-$14,750 per ton of VOC for 

capital costs and $1,087-$3,125 per ton of VOC for annualized operating costs.

Two commenters (4219, 4320) commented on the EPA’s cost estimate for VRUs. One 

commenter (4320) indicates that the EPA should include the cost of a back-up flare in VRU costs 

because it will be necessary during periods of VRU downtime for maintenance or malfunction, 

which is not uncommon in the gas production sector. Another commenter (4219) states that it is 
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incorrect to assume that the cost of a VRU is in all cases offset to some degree through recovery 

of product. The commenter notes that some companies that would be subject to these rules 

transport natural gas for others and are paid the same amount regardless of whether natural gas 

escapes to the atmosphere or is captured by a VRU and returned to the process system.

One commenter (4266) contends although the EPA consistently included the primary equipment 

required for the control option being considered, it often overlooked the cost of auxiliary 

equipment. According to the commenter, the EPA considered the cost of the control device 

(flare, combustor or VRU), but did not appear to include the closed vent system required to 

collect the vapors, assure condensed liquids do not “vapor lock” this very low pressure system, 

and separate any condensed liquids before it reaches the control device. 

The commenter (4266) also states that the EPA’s cost analysis appeared to include some costs 

for monitoring where required (i.e. storage vessels and LDAR), but did not appear to consider 

the remote, dispersed and unmanned nature of the facilities. Two commenters (4228, 4266) 

likewise indicate that the required data logging may not be feasible at remote, unmanned 

locations due to lack of electrical power for a continuous data systems and accessibility for 

manual data collection. Therefore, the commenters recommend that the final rule include 

provisions for remote locations that allow manual data collection on a schedule that matches an 

owner’s normal site visit schedule.

One commenter (4228) indicates that the proposed performance testing requirements for storage 

vessel combustion control devices are unnecessarily costly. The commenter’s company operates 

about 2,400 of these control devices in Colorado alone, and the commenter asserts that the added 

burden and cost associated with performance testing is not warranted or justified. In addition, the 

commenter believes that the large number of sources will overwhelm the industry testing 

capacity.

Response: We appreciate the detailed cost data provided by the commenters. After reviewing 

these data, including verifying the source and reasonableness of the data, we concluded that a 

revised cost analysis was warranted. 

Our original cost analysis was based solely on VRUs as a more conservative estimate since 

available data indicated VRUs have a higher annual cost than flares. However, we determined 

previously that both VRUs and flares can meet the BSER level of control and based national 

impacts on equal use of VRUs and flares. Thus, in our revised cost estimate, we averaged the 

cost of a VRU and a flare rather than using just the VRU costs. We used the commenter’s flare 

cost and our previous VRU cost (which was not disputed by the commenters). The resulting 

annual cost was less than $20,000. We then evaluated the cost effectiveness and determined that 

at a VOC emissions rate of 6 tpy, an acceptable cost effectiveness value of about $3,400/ton is 
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achieved (see discussion above for additional information concerning our decision to change 

from a throughput threshold to an emission rate threshold). Thus, in the final rule we have 

revised the threshold for storage vessels to 6 tpy, and storage vessels at or above this threshold 

will be required to control emissions.

The revised cost analysis includes all capital cost components of the control measures, including 

auxiliary equipment. However, we do not believe that the owner or operator of a VRU must also 

install a back-up flare, and we have not included those costs in VRU costs. While it is true that 

VRUs can be expected to experience some downtime for maintenance and malfunctions, VRUs 

when operating properly generally approach 100 percent efficiency. Since the rule requires a 

minimum of 95 percent efficiency, we believe this difference adequately compensates for any 

reduced efficiency that may occur during non-routine operations. 

The change in the final rule from a throughput threshold to an emission rate threshold has 

eliminated the need for liquid flow meters, along with the associated technical and cost issues 

related to data acquisition at remote locations without electrical service. The inclusion of an 

option to control emissions with an internal or external floating roof tank also can reduce testing, 

monitoring, recordkeeping and reporting costs for some tanks at remote facilities.

Regarding the costs associated with emissions tests for combustion control devices, we reiterate 

that the final rule no longer cites to the requirements of subpart HH. Instead, we decided to 

remove from 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. 

2.5.4.2 Flare

Comment: One commenter (3468) states that the rule should allow gas vented from crude oil 

storage vessels to be vented to a flare pit if there is not a market nearby, as was proposed for 

emissions from fractured gas wells.

Response: The EPA disagrees with the commenter. We believe that in such situations a flare 

achieving 95 percent control is a cost effective control option.

Comment: One commenter (4161) notes that the proposed definition of “flare” in §60.5430 

specifically excludes enclosed flares. The commenter believes that enclosed flares are 

preferential in some cases and should be allowed.

Response: The definition of flare specifically excludes enclosed devices to distinguish flares

from enclosed combustion devices such as oxidizers. However, this does not preclude the use of 
135

an enclosed flare as a control device to meet the emission limits of subpart OOOO. Any enclosed 

flare would have to meet all applicable monitoring, recordkeeping and reporting requirements.

Comment: Two commenters (4266, 4281) contend that the requirement for a flare to be 

operated with a flame present at all times is not appropriate in light of current technology.

Response: We are aware of the growing use of electronic spark ignition systems for flares. 

However, given the intermittent and inconsistent nature of emissions from tanks in this industry 

combined with the highly variable VOC concentration in the emissions, we do not believe a 

spark-ignited flare will achieve the same level of emission reduction as a flare with a continuous 

flame present. Therefore, we are not allowing electronic spark ignition systems in the final rule.

Comment: Two commenters (4192, 4246) note that the EPA conceded that a VRU cannot be 

used when electrical service sufficient to power the VRU is not available (76 FR 52763), and 

that the proposed regulatory text would require flares to comply with §60.18. However, 

according to the commenters, in order for a flare to meet §60.18 it may need a blower or steam 

during upsets. The commenters state that neither electricity for the blower nor clean water for the 

steam are usually present at a compressor station or a production facility. The commenters point 

out that an onsite diesel generator could be installed to provide electricity, but that would 

increase emissions of NOx, CO, and VOCs, and onsite generators have a hard time showing 

compliance with the 1-hour NO2 standard during the permitting process. As a result, the 

commenters believe that the reference to §60.18 would rule out flares as a compliance option at 

many storage vessels not located at natural gas processing plants. The commenters urge the EPA 

to exempt flares from subpart OOOO compliance requirements by maintaining the SSM 

exemption.

In addition, the commenters (4192, 4246) express concern that an enclosed flare also is not an 

option for the following reasons:

• States may not permit them. One of the commenter’s association’s member 

companies was not able to permit an enclosed flare in Texas.

• Manufacturers may not test them. This is particularly true if the test requirement 

requires testing with propylene vs. propane.

• Nearby property owners may not allow enclosed flares in Texas in the summer 

drought season, because of the fear of grass fires.

According to the commenters (4192, 4246), this would leave some operations with no acceptable 

compliance option and, for these reasons, the EPA should not require that flares comply with

section 60.18 during upsets. 
136

Another commenter (4219) similarly notes that for a flare to meet §60.18 standards, it may need 

to have a source of electricity (for a blower) or clean water (for steam), neither of which tend to 

be present at compressor stations. The commenter adds that tip velocity requirements are 

difficult or impossible to meet with respect to small tanks in remote locations. The commenter 

concludes that if §60.18 standards remained in the rule for flares, then flares would not be a 

compliance option for many storage vessels that are located at sites other than natural gas 

processing plants. The commenter adds that in some cases there are set-back requirements that 

complicate the siting of the flare or prevent installation of a flare altogether. In addition, the 

commenter points out that acquisition of land or right-of way may be needed if the site is not big 

enough for a flare and there are many other safety and logistical considerations that must be 

taken into account with regard to flare installation and operation, especially in dry or droughtstricken areas.

One commenter (4209) indicates that, in many instances, State and local laws/rules will not 

allow flaring; for example, burn bans prevent the use of flaring. The commenter believes that the 

EPA should include exceptions to flaring requirements to address state and local issues. In 

addition, the commenter notes that flaring is not always feasible due to the BTU content and 

adds that the EPA should allow for such exceptions.

Response: In Table 3 of the final rule, we now specify that §60.18 does not apply to flares; 

therefore, the comments concerning the requirements of §60.18 are no longer relevant. We agree 

with the commenters that there may be certain circumstances where flares cannot be used. 

However, other control technologies may be used for VOC emissions from storage vessels. In 

those cases, the owner or operator must choose an alternate emission control technology.

Comment: One commenter (4192) recommends that the EPA revise the requirement that flares 

comply with §60.18 to add “except that compliance with §60.18(f)(1) and (f)(4) shall not be 

required for flares that are intended to handle emergency releases.” The commenter states that 

such flares are designed to burn large quantities of gas during maintenance and emergencies, but 

during normal operations the amount of flow to the flare is often little more than what is required 

to maintain the pilot. The commenter contends that the §60.18(f)(1) requirement for Method 22 

during normal operations and the §60.18(f)(4) requirement for Method 2, 2A, 2C, or 2D, or a 

flow meter are a waste of time, money and effort for emergency flares because they always pass 

during normal operations

Response: This comment is no longer relevant, as the final rule no longer requires that flares 

comply with §60.18.
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2.5.4.2.1 Secondary Impacts

Comment: One commenter (4161) notes that many of the controls for VOC emissions are based 

on combustion, with the resultant formation of NOx which, if an area has an ozone issue and the 

ozone level is NOx-limited, will increase the ozone problem. The commenter asserts that the 

control strategy in the NSPS must allow an exemption to these controls if such an issue is 

demonstrated by the agency with jurisdiction.

Response: The final rule specifies 95 percent control of VOC emissions. Owners and operators 

may choose controls other than combustion devices in those situations where the use of 

combustions devices may be an issue.

Comment: One commenter (4356) is concerned about applicability to small tanks or locations 

where it is infeasible to install VRUs because a flare would be the most likely control device. 

The commenter contends that the use of flares in highly populated areas, which can also be 

nonattainment areas, is a health and safety concern, wastes energy, and could contribute to ozone 

precursor formation.

Response: As already stated, the owner or operator may choose any control technology that 

achieves 95 percent control. As for small tanks, the final rule specifies that controls are required 

only for tanks with VOC emissions of 6 tpy or greater. Many of the small tanks addressed by the 

commenter may not meet this threshold.

2.5.5. Other Comments

Comment: Several commenters (4192, 4217, 4219, 4231, 4240, 4241, 4246, 4266, 4320) request 

that the EPA provide all storage vessel NSPS requirements in subpart OOOO rather than 

referencing NESHAP subpart HH. The commenters indicate that this would improve readability 

and clarity and note that the cross-citation is confusing because the cited sections – and the 

sections that they, in turn, cite – are rooted in section 112 concepts and include references to 

HAP control requirements. One commenter (4320) states that the application of NESHAP 

provisions in this manner is not justified because they add a compliance burden not justified 

using the same analysis employed in the development of NESHAP standards. One commenter

(4241) believes that the continuous parameter monitoring and control device testing 

requirements associated with NESHAP HH, and incorporated by reference in the NSPS, are 

infeasible and excessively costly for remote production locations. One commenter (4241) points

out alleged problems with specific sections of subpart HH, which they believe are unjustifiably 

burdensome for the VOC emissions regulated under subpart OOOO. One commenter (4219) 

asserts that a VRU is properly characterized as a process unit, not a control device, and that the 

final rule should delete any provision that would impose part 63 requirements on VRUs.
138

Response: Based on our consideration of these comments, the EPA decided to remove from 

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. 

As noted previously, we continue to believe that a VRU is a control device and should not be 

characterized as a process unit. Nevertheless, the final rule does not apply subpart HH 

requirements to VRUs.

Comment: One commenter (4266) notes that the proposed subpart OOOO would impose a 95 

percent control requirement on affected storage vessels by incorporating by reference the 40 

CFR part 63, subpart HH NESHAP storage vessel control requirements. The commenter states 

that even if the same control standard of 95 percent reduction is selected and economically 

justified, the more stringent monitoring and performance testing requirements required by the 

CAA in section 112 for HAPs are not required in section 111 for criteria pollutants. 

Response: The commenter incorrectly assumes that section 111 requires less stringent 

monitoring, inspection, recordkeeping and reporting (MIRR) requirements than section 112. In 

promulgating a standard either under section 111 or 112 of the CAA, the EPA includes MIRR 

requirements that are adequate to ensure compliance with the standard. In this case, due to the 

same control, the EPA reasonably adopted in the NSPS the NESHAP subpart HH MIRR 

requirements that the EPA already determined to be adequate to assure compliance for such 

control. Even if the EPA had decided to start anew, there is no reason to believe that the MIRR 

requirements that would adequately assure compliance with the NSPS would be less stringent 

than the MIRR requirements in subpart HH. 

Comment: Two commenters (4192, 4246) support proposed §60.5395(b), which provides that 

storage vessels subject to subpart HH are exempt from subpart OOOO.

The commenters also recommend that the EPA extend this approach to establish storage vessel 

standards for minor HAP sources in NSPS subpart OOOO, and provide in NSPS subpart OOOO 

that storage vessels subject to those standards are exempt from subpart HH. The commenters 

also indicate that once storage vessel standards are established in NSPS subpart OOOO, tanks 

that are subject to the control standards in NSPS subpart OOOO should be exempt from the 

control standards in MACT subparts HH and HHH.

Response: We thank the commenters for their support of the exemption from subpart OOOO for 

storage vessels subject to subpart HH. 
139

We do not understand precisely what the commenters are suggesting with regard to establishing 

standards in subpart OOOO for minor HAP sources, but note that CAA section 111 does not 

provide authority for the EPA to regulate HAP emissions. 

Finally, while we have established in the final subpart OOOO that storage vessels that are subject 

to and controlled in accordance with subpart HH are not subject to the requirements of subpart 

OOOO, we do not believe that it is appropriate to provide the complementary exemption from 

subpart HH to storage vessels subject to subpart OOOO. In cases where storage vessels are 

subject to subpart HH, we believe that they should be required to meet all the requirements of 

that subpart. We do not believe that it is appropriate to set up a system that allows sources to 

choose whether to comply with an NSPS (subpart OOOO) or a NESHAP (subpart HH). 

Comment: Three commenters (4192, 4246, 4263) recommend that proposed §60.5410(e)(2) be 

revised to specify that the initial performance test be conducted by the later of 180 days after 

initial startup or the date of publication of the final rule in the Federal Register. Two of the 

commenters (4192, 4246) state that this revision is needed to provide owner/operators a 

reasonable and predictable period of time to install the necessary controls. These commenters 

believe that a 180-day compliance window following initial startup is reasonable for the 

following reasons:

• The publication date of the final rule is unknown.

• The requirements of the final rule are unknown.

• Delivery time frames for a VRU are, at a minimum, 12 weeks.

• Winter installations are difficult due to ground freezing.

• Industry has valid concerns that suppliers may not be able to meet demand for VRU 

systems upon promulgation of the final rule. Shortages of these systems will lead to 

issues meeting compliance deadlines.

• In addition to time delays associated with ordering control devices, there is dirt work, 

pads, electrical, plumbing, piping, etc to be designed, ordered, delivered and 

constructed.

• There may also be work associated with electricity delivery to some sites.

• Following completion of construction and installation, testing still needs to be 

performed.

Response: The final rule language (now §60.5410(e)(5)) does provide that the initial 

performance test must be conducted by the date of publication of the final rule in the Federal 

Register or 180 after initial startup, whichever is later. However, this does not postpone the date 

that compliance must be achieved until this date. The final rule requires that owners or operators 

install and operate controls at the time of startup at well sites with one or more other wells 

already in production. At well sites with no other wells in production, the owner or operator has 
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30 days to determine what emissions from the associated storage vessels will be, and an 

additional 30 days to install required controls.

Comment: Several commenters (4177, 4217, 4220, 4241, 4252, 4258, 4264, 4266, 4281) state 

that operators need time to evaluate the emissions or throughputs before the controls must be 

installed. Six of these commenters (4177, 4220, 4252, 4264, 4266, 4281) recommend that the 

EPA allow the first 30 days of production to be the applicability basis and require compliance 

within 60 days thereafter. Three of these commenters (4177, 4220, 4266) note that the Wyoming 

DEQ bases control on the first 30 days of production multiplied by a decline factor, then control 

must be installed 60 days later, and suggest that the Wyoming approach could be a model with 

adjustment made to the “decline factor” such that it is more representative of an individual basin 

or field’s average decline rate. One of the commenters (4252) adds that if the EPA fails to 

specify a reasonable compliance period, then storage vessels would potentially need to be 

equipped with controls at every new production site – just in case the production characteristics 

might trigger the control requirements – which would result in installing controls at many sites 

for which controls would eventually be shown to have been neither required nor cost effective. 

Another of the commenters (4241) states that the average production rate of a new well generally 

is not known until 60 days after first production or, in the case of a pad-wide tank battery, 60 

days after the final well is completed. On this basis, the commenter recommends a 90-day 

evaluation period (similar to state-wide Colorado Regulation 7 Section XVII.C.2 requirements) 

to determine which vessels will likely trigger the applicability thresholds. One of the commenters 

(4258) recommends that the EPA allow for an initial 90-180 day period during which the 

operator can more correctly evaluate each new storage vessel and well. Another commenter 

(4217) requests that the EPA allow 180 days after first production to comply with the standard, 

noting that 180 days would be allowed for a modified affected facility per §60.14(g). 

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 adopt the approach taken in the 

Wyoming rules for new sources. 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. We believe that the Wyoming experience 

illustrates that this will be sufficient time to size and obtain suitable controls. 
141

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. Thus, 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. 

Comment: One commenter (4266) recommends that the EPA include in the final rule a 

provision to allow time for an affected storage vessel that is initially below the exemption level 

to implement controls after exceeding the exemption level. The commenter indicates that the 

time should be sufficient for designing, ordering and installing the necessary equipment, and 

adds that although this type of scenario would not be a modification, the EPA could use a similar 

approach used in §60.14(g) and allow 180 days to come into compliance with all the applicable 

standards.

Response: As noted above, 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. We believe that the Wyoming experience illustrates that this will be 

sufficient time to size and obtain suitable controls. 

Comment: One commenter (4266) states that the compliance requirements for vapor combustors 

for controlling storage vessels are a part of the equipment design that is controlled by the 

equipment manufacturer, not the owner/operator, and that the EPA needs to allow sufficient time 

for the manufacturer to review the equipment design and label it as complying with the 

requirements of this rule. The commenter notes that the proposed performance test requirements 

for storage vessel control devices cite §63.772(e) of NESHAP subpart HH, which include a 

provision for the performance test to be conducted by the manufacturer as specified in 

§63.772(h). The commenter indicates that it will require considerable lead time before such 

“manufacturer certified” control devices are readily available. Accordingly, the commenter 

requests that the effective date of the storage tank requirements under subpart OOOO be delayed 

for 3 years to allow time for the specified control devices to become available.

Response: We agree that it will likely take some time beyond the promulgation date of the NSPS 

for combustor manufacturers to have control devices constructed, tested, documented and 

available for operators to install in efforts to comply with the storage vessel requirements of the 
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NSPS. Under the final rule, operators are not required to conduct individual performance tests on 

combustors installed in the field if the combustor manufacturer tests and documents for the 

owner or operator that the model achieves a control efficiency of 95.0 percent. The time required 

for testing and documentation is often longer than for a single model when manufacturers 

provide multiple models for varying applications based on capacity. We disagree with the 

commenter that a 3-year period would be required, and instead believe this testing and 

documentation program would require an “adjustment period” of one year for manufacturers to 

be ready to supply the operators with the correct equipment they need. At the end of this 

adjustment period, we believe owners and operators should have no problem securing control 

devices that are manufacturer-tested and have appropriate documentation for determining control 

efficiency. Accordingly, the final rule provides for a one-year phase-in period beginning on the 

date of publication of the final rule in the Federal Register before the 95.0 percent control 

requirement is effective.

Comment: One commenter (4231) requests that the definitions of condensate and crude oil 

provided by the EPA in the proposed subpart be removed.

Response: We disagree with the commenter. While these terms have been removed from the 

storage vessel definitions, the terms are used elsewhere in the rule and as such the terms should 

be defined.

Comment: Four commenters (4135, 4230, 4241, 4266) express concern with the proposed 

definition of “condensate.” The commenters suggest alternative definitions.

Response: We disagree that the definition of condensate needs to be revised, and have made no 

changes to the definition in the final rule.

Comment: One commenter (4230) believes that the definition for “API Gravity” should be 

made more specific because the literature appears to include variations as to how to calculate this 

value. 

Response: We disagree with the commenter. We believe the definition is general enough to 

encompass any variations in the system recommended by API.

Comment: One commenter (4266) recommends that a definition for “First Date of Production” 

be added to the final rule and provides suggested language.

Response: The EPA does not agree that the concept of the “date of first production” is needed, 

and we have not added a definition for the term. 
143

Comment: One commenter (4266), who prefers replacing the throughput applicability threshold 

with a VOC emissions threshold, also recommends that proposed §60.5395(a)(1) and (2) be 

clarified to state that the exemptions are based on calendar year annual averages, which would 

avoid surprises from fluctuating operations and minimize burdens by matching the time period 

used for emission estimating with other reporting where tank throughput data are needed.

Response: The final rule no longer uses throughput thresholds, so these comments are no longer 

relevant.

Comment: If the EPA retains the citations to subpart HH (which the commenters oppose), two 

commenters (4266, 4281) request that the EPA clearly allow that the performance test be 

conducted by the equipment manufacturer. One commenter (4266) provides alternative language 

for the initial performance test requirement of proposed §60.5410(e)(2) to clarify this.

Response: The EPA has not retained the citations to subpart HH, but we have included language 

in subpart OOOO providing procedures for control device manufacturers to test and certify their 

products.

Comment: One commenter (4219) suggests that, for the sake of clarity, the word "already" be 

struck from proposed §60.5395(b). The commenter believes that if a storage vessel is subject to 

and controlled in accordance with §63.766, then it should be exempt from proposed §60.5395(a) 

regardless of when the vessel came under such controls. According to the commenter, use of the 

word "already" only injects the possibility for confusion.

Response: We agree that this may create confusion and have made the suggested change in the 

final rule.

2.6 Equipment Leaks

Comment: Two commenters (3459, 4275) recommend that the new LDAR requirements apply 

to existing processing plants as well as to new plants. One commenter (4275) adds that improved 

leak detection methods are equally available to detect VOC leaks at existing plants and should be 

required, as demonstrated by Colorado’s rules to reduce VOCs at existing gas plants in ozone 

nonattainment areas.

Response: Section 111(b) of the CAA 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. Thus, the EPA does not have the authority under section 111(b) to extend the rule 

to existing sources, until the existing sources undergo a modification or reconstruction that 

triggers an NSPS standard.
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Comment: One commenter (4274) believes it is not cost effective to address equipment leaks at 

sites, gathering and boosting facilities, and transmission and storage facilities at this time. The 

commenter believes, however, that as technology continues to improve, there may be cost 

effective methods that can be introduced, which is important as the number of well sites 

increases, especially those near communities. The commenter recommends that the EPA monitor 

this situation, as shale plays develop and new cost effective technology becomes available.

Response: We evaluated various options for reducing VOC emissions from equipment leaks at 

sites, gathering and boosting facilities, and transmission and storage facilities, but found these 

options not to be cost effective. Therefore, we were unable to prescribe a monitoring program to 

reduce VOC emissions from these sources at this time.

2.6.1 Leak Definition

Comment: Two commenters (4192, 4246) state that the EPA should specify that equipment is 

considered not in VOC service if the VOC content is not expected to exceed 10 percent by 

weight during normal operation. The commenters believe this is necessary to accommodate brief 

periods during upset conditions when the lines may contain heavier components than normal, 

such as in residue gas lines. The commenters add that if the EPA removes the SSM exemption, 

the rule should clearly provide that residue lines remain exempt from the provisions of subpart 

OOOO as long as they normally contain less than 10 percent VOC by weight. The commenters

also recommend that engineering judgment be allowed to estimate VOC content for any stream, 

whether the equipment is in VOC service or out of VOC service. The commenters state there is 

no reason to refer to “in wet gas service” because “in VOC service” should define all affected 

components. The commenters state that removing the term “in wet gas service” from 

§60.5365(f)(1) and §60.5400 would streamline and simplify this regulation. 

One commenter (4266) states that the proposed leak provisions of §60.5430 would apply to all 

components regardless of the quantity of VOC present, in contrast to “in VOC service” which is 

based on the VOC content of the material handled. The commenter believes that, just as the EPA 

concluded in establishing the criteria for a component in VOC service that it is not cost effective 

to monitor components containing less than 10 percent VOC, this same logic should apply to 

components handling wet gas that contains less than 10 percent VOC. The commenter states that 

for wet gas components in the 1-10 percent VOC concentration range, the cost effectiveness is 

between 20 and 2 times the EPA’s estimates, depending on the VOC concentration of each 

particular stream. Thus, the commenter states, it is not cost effective (and not BSER) to apply the 

proposed equipment leak requirements to such components, and the definition of “in wet gas 

service” should be deleted and the “in VOC service” criterion should be applied to all 

components in the source category. 
145

The commenter (4266) adds that, if the EPA intends to continue regulation of lower VOC 

content streams at natural gas processing plants, the definition of “in wet gas service” should be 

revised to include the field gas before extraction step that contains more than X percent VOC by 

weight (recommends X be equal to or greater than 5). The commenter believes this revised 

definition will still result in a mandate of controls that are not cost-effective, but the impact 

would be lessened because inert gas streams from enhanced recovery systems, coal-bed methane, 

and dry shale gas streams that contain little to no VOC would no longer require monitoring.

Response: It is the EPA’s intent that subpart OOOO regulates VOC emissions. We do not agree 

that an “in VOC service” exemption is warranted. We have made selected revisions to the rule to 

account for specific segments of the source category in which the VOC content of the natural gas 

handled by the processes in those segments is consistently and reliably nearly zero. Thus, 

pneumatic controllers and compressors in the transmission and storage and distribution segments 

will not be subject to the final rule.

We believe this more focused approach provides better certainty that emission sources with 

appreciable VOC emissions will be subject to the rule. A threshold based on “in VOC service,” 

on the other hand, introduces the possibility that an emission source with a high volume 

throughput (and the possibility of having appreciable emissions) but does not meet the definition 

of “in VOC service” could escape control.

As discussed elsewhere in this document, however, we note that we revised §60.5365(f) and 

§60.5400 to exclude compressors. 

Comment: One commenter (4240) believes that the most basic elements of an LDAR program 

are the definition of a leak, frequency of monitoring, and timeline in which leaks are repaired. 

The commenter states that the Bay Area Air Quality Management District (BAAQMD) has 

demonstrated that stricter regulation is feasible. The commenter (4240) states that, in addition to 

having a lower leak threshold, the BAAQMD rule is stricter than the subparts VV and VVa rules 

because it requires monitoring for methane leaks. The commenter states that this oversight may 

potentially diminish the effectiveness of leak detection at a specified threshold. The commenter

recommends the EPA specify that leak-detection equipment be sensitive to methane and adopt 

BAAQMD’s lower threshold or explain why these steps are infeasible for natural gas processing 

plants. 

Response: With respect to methane emitted from the oil and gas sector, in the preamble to the 

proposed rule, the EPA states that it 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 
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further reduction in subpart OOOO. The VOC requirements in this rule would also achieve 

substantial reduction in methane emissions as a co-benefit. However, the EPA does not have 

sufficient information at this time to assess whether the category continues to emit significant 

amount of methane even with the expanded VOC controls and what measures are appropriate for 

reducing the remaining methane emission. For these reasons, the EPA is continuing its 

assessment of methane emissions, including gathering and reviewing additional information, to 

evaluate appropriate actions. 

Absent convincing data demonstrating that lower emissions can be achieved through the 

BAAQMD requirements, we are not revising our analysis at this time.

Comment: One commenter (4246) believes that §60.5421 should be revised to 10,000 ppm not 

500 ppm, as the commenter believes leaks should be defined as 10,000 ppm or greater. The

commenter recommends deleting §60.5401(b)(2), the PRD requirement for 5,000 ppm 

equipment leak threshold. One commenter (4266) is unclear whether the alternate leak definition 

for PRDs in §60.5401(b)(2) is a typographical error, as it states, “If an instrument reading of 

5,000 ppm or greater is measured, a leak is detected.” The commenter contrasts this with 

§60.5421(b)(2)(iv), where the language suggests a leak definition of 500 ppm. The commenter 

(4246) also believes that §60.5421 should be revised to “10,000 ppm” not “500 ppm”, as the 

commenter believes leaks should be defined as 10,000 ppm or greater. The commenter adds that 

the proposed regulatory text is internally inconsistent at proposed 40 CFR §60.5421(b)(2)(iv) 

which requires recording values “above 500 ppm” for pressure relief devices, however, proposed 

40 CFR §60.5401(b)(2) defines a leak as 5,000 ppm. One commenter (4191) recommends that 

the EPA explain the exception to the leak definition threshold of 500 ppm, which allows that 

threshold to be increased to 5,000 ppm. One commenter (4192) recommends that a leak should 

be defined as 10,000 ppm or greater for pressure relief devices. The commenter also notes that 

the proposed regulatory text is internally inconsistent as proposed §60.5421(b)(2)(iv) requires 

recording values “above 500 ppm” for pressure relief devices, however, proposed §60.5401(b)(2) 

states that a leak is defined as 5,000 ppm. The commenter requests clarification.

Response: As stated in the preamble to the proposed rule, the EPA reviewed several sources to 

determine BSER for each type of equipment. To develop control options, the EPA examined 

requirements found in various State and local rules, applicable Federal regulations such as the 

HON, the MON, the Generic MACT, and the CAR, data from NEIC inspections, and emissions 

data from industry representatives. The Agency considered industries subject to the abovereferenced standards as a basis for examining the appropriateness of applying requirements at the 

NESHAP levels in the NSPS. Section 111(b)(1)(B) of the CAA allows the Agency to consider 

the emission limitations and percent reductions achieved in practice that are beyond the current 

regulations when revising NSPS. Once the EPA identified options and leak definitions for 

various equipment, each option was evaluated in conjunction with technical feasibility, costs, 
147

and emissions reductions to determine BSER for each type of equipment. Based on this analysis, 

we determined that the leak definition should be defined as 500 ppm.

The commenter is correct that an “instrument reading of 5,000 ppm” is a typographical error.

The correct leak definition for pressure relief devices is an instrument reading of 500 ppm or 

greater. Section 60.5421(b)(2)(iv) simply requires you to keep a record of any repair attempt 

after which the instrument reading is 500 ppm or greater. This change will make the requirement 

in 40 CFR §60.5421(b)(2)(iv) consistent with §60.5401(b)(2).

Comment: Four commenters (4159, 4220, 4273, 4266) state that lowering the leak definition 

from 10,000 ppm to 2,000 ppm for pumps is expected to be very costly. The commenters state 

that it would likely require different seal material for pumps and necessitate extending the 

compliance time to the next scheduled turnaround to allow time for planning the equipment 

upgrade that would be required. The commenters also state that increasing the stringency of the 

leak definition for valves and pumps might not lead to actual emission reductions. The 

commenters state that if those components cannot be repaired to be under the defined leaking 

threshold while on-line (as is expected for multiple components) those components will be 

placed on the repair list for the next scheduled process unit shutdown. The commenters indicate 

that the unintended consequence will be an increase of the number of components on the repair 

list, an extension of the duration of required maintenance time, and higher industry costs due to 

lost operations without clear environmental benefits. One commenter (4266) adds that the EPA 

did not include pumps in its model plants for natural gas processing facilities and thus is not 

justifying the extra burden or demonstrating any environmental benefit and must demonstrate the 

need for such a LDAR program for pumps and demonstrate this is BSER. 

Response: The cost analysis has included costs for materials and labor to replace packing and 

seals from components. We believe that the replacement of packing or seals is considered to be 

part of the normal maintenance of a facility. The repair of components not only eliminates 

emissions from that equipment, it also helps maintain the physical integrity of the facility, 

thereby reducing the likelihood of leaks elsewhere on the line.

Comment: One commenter (4184) supports tightening the definition of leak from 10,000 ppm to 

500 ppm for VOCs based on a reference calibration gas. However, the commenter states that the 

EPA concluded that while processing plants would incur only an incremental cost of an 

enhanced detection monitoring program, production sites associated with a wellhead, gathering 

stations, and storage would incur substantial cost of initiating a new leak detection program. The 

commenter believes that a prescribed monitoring program is necessary to define what constitutes 

a “significant” leak at these other source categories to enable states with delegated programs to 

implement the regulatory requirement to mitigate significant leaks that might be associated with 

these specific source operations. 
148

Response: We evaluated a number of different options for reducing VOC emissions from 

equipment leaks for the production, gathering and boosting, and transmission and storage 

segments, but found these options not to be cost effective. Therefore, we were unable to 

prescribe a monitoring program to reduce VOC emissions from these sources.

Comment: Several commenters (4192, 4214, 4219, 4220, 4233, 4246, 4252, 4254, 4266) state 

that 10,000 ppm should be the leak definition for all equipment because the justification for

achieving 10,000 ppm in the original 1984 subpart KKK preamble is still valid and the cost for 

compliance below 500 ppm is much higher than that at 10,000 ppm. One commenter (4219) adds

that connectors should be monitored by only visual, audible and olfactory methods. The 

commenter states that the proposed standard will place a burden on industry. Two commenters 

(4185, 4219) add that while the synthetic organic chemical industry operates under a 500 ppm 

leak definition threshold, the emissions associated with that industry tend to be more toxic than 

the VOC emissions in the natural gas industry. One commenter (4193) believes the leak 

threshold for natural gas processing plants should be 5,000 ppm rather than 500 ppm. Another

commenter (4252) believes that the proposed leak definition for valves would be burdensome 

without achieving the VOC reduction as claimed by the EPA.

Response: The EPA agrees that lowering the leak definition for a component will increase the 

cost of compliance; however the final rule does not include any leak definitions below 500 ppm. 

The EPA believes that the 500 ppm VOC leak definitions used by the synthetic organic chemical 

industry to reduce toxic emissions are also appropriate for the natural gas industry. Nearly all of 

the toxic emissions generated from equipment leaks by the synthetic chemical industry are also 

VOC and hence would be detectable using the Method 21 monitoring device. Discussions of the 

BSER determination are presented in the preamble to the proposed amendments (76 FR 52738) 

and in the TSD. The analysis of the LDAR programs show that subpart VVa LDAR is cost 

effective for natural gas processing plants and was determined to be BSER.

2.6.2 Leaker Emission Factors and Emission Estimation Methodology

Comment: One commenter (4266) states that the baseline VOC emissions the EPA used in 

Table 8-12 of the TSD are in error because they represent emissions from an uncontrolled 

facility. Four commenters (4159, 4185, 4220, 4273) state that the proposed revisions are highly 

burdensome and are not cost-effective for reducing VOC emissions from valves and connectors 

and reducing the leak definition to 500 ppm will have no meaningful environmental benefit. Five

commenters (4159, 4185, 4220, 4266, 4273) also state that on the cost side, reducing the leak 

definition in this manner will dramatically increase the costs of the rule and should not be 

adopted. Three commenters (4159, 4220, 4273) indicate that the percentage of valves that leak 

above 10,000 ppm is extremely low, ranging between 0.1 - 8.8 percent, but these leaking valves 
149

contribute 82 - 99.7 percent of the total mass emissions from facility valves when using the 

Leak/No-Leak method from the EPA’s 1995 protocol for estimating emission. Further, four

commenters (4159, 4220, 4266, 4273) believe that the approach used by the EPA in the TSD for 

this proposed rule is flawed in that the model calculates emissions using an average emissions 

factor, which typically overestimates emissions by 20 - 40 percent when compared to the 

Leak/No-Leak method, and by even more if compared to the emissions correlation approach. 

The commenters state that, thus, the TSD derives an estimated VOC emission control 

effectiveness of 94 percent, which is not realistic even if the baseline was that for an 

uncontrolled facility. One commenter (4266) believes a more realistic value, based on applying 

the CE to the EPA’s uncontrolled emissions estimate, would be in the range of 4.3 to 5.7 tons/yr, 

per facility, and this should be used as the baseline from which to calculate the incremental 

impact of the proposed regulations. Three commenters (4159, 4220, 4273) recommend that the 

EPA must conduct an “incremental cost” analysis and only take “credit” for repairs that would 

not occur at the 10,000 ppm level but would occur at the 500 ppm level and must also take credit 

only for the time period during which the leak would stay below 10,000 ppm. 

One commenter (4266) believes the EPA overestimated valve control-effectiveness for its model 

plant and the natural gas processing plant model in its TSD to analyze the impact of these new 

leak definitions for the LDAR program is flawed. The commenter (4266) states that the 

calculations of baseline emissions for the model plant significantly overestimate these emissions 

since the method used relies on component counts and average emission factors by component 

type, which are, at best, representative of uncontrolled facilities. The commenter (4266) adds that 

since subpart KKK was promulgated in 1985, a significant proportion of the existing natural gas 

plants that would become subject to subpart OOOO through modification will already be 

complying with subpart KKK, and all new natural gas plants would have to comply with subpart 

KKK if subpart OOOO was not in place. Thus, the basis for evaluating subpart OOOO impacts, 

the commenter (4266) states, must be compliance with subpart KKK, not an uncontrolled 

emissions scenario as was used in the EPA’s TSD analysis that supports the proposed rule.

Response: We believe that the commenter is referring to Table 8-11 of the TSD which lists the 

nationwide baseline emissions for new sources and not Table 8-12. 

The EPA is governed by the CAA in setting national standards that adequately reflect the 

emissions level for new sources nationwide. The evaluation of the costs and emission reductions 

were based on the incremental cost of going from a subpart VV to a subpart VVa LDAR 

program. Based on our analysis, we found that an additional 13.5 tons per year of VOC 

emissions could be reduced by requiring a subpart VVa LDAR program at an additional cost of 

$45,000, in comparison to the subpart VV LDAR program. We also evaluated the incremental 

costs using emission and cost data from the “Analysis of Emission Reduction Techniques for 

Equipment Leaks,” which is located in the docket. Using the latest cost and emission 
150

information, we found the cost effectiveness to be comparable to the cost effectiveness 

calculated in the TSD. Therefore, we believe the results show that the subpart VVa is cost 

effective and reflects the emission level that can be achieved for new sources. 

As the commenter noted, we calculated emissions and emissions reductions using the average 

emission factor approach. The other emission estimation approaches (e.g., screening ranges 

approach formerly known as the leak/no-leak approach) were developed to allow facilities to 

estimate emissions using screening data from the facility. The commenter provided no data that 

shows that the emission factor method overestimates emissions from equipment leaks; therefore, 

we believe that the emission factor approach provides a reasonable estimate of emissions from 

equipment leaks. 

The VOC control effectiveness was calculated using the “Approach for Estimating LDAR 

Control Effectiveness” in the Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-

017). This approach uses the leak definition, the initial leak frequency, and the final leak 

frequency. The control effectiveness of an LDAR program can be estimated based on the 

average leak rate before the LDAR program is implemented and the average leak rate after the 

LDAR program is in place. We believe this approach provides the best method for determining 

the control effectiveness of a LDAR program.

In calculating the cost effectiveness of the LDAR options, the costs and emissions were based on 

the incremental change between the subpart VV and subpart VVa LDAR programs. The subpart 

VVa costs and emission reductions only account for the additional costs for repair that occur 

from leaks between 500 and 10,000 ppm for valves. The subpart VVa costs also include the costs 

and emission reductions for applying a 500 ppm connector leak detection program.

Comment: One commenter (4266) states that their data for three natural gas processing units 

where the actual ppm concentration values monitored are recorded indicate that the proposed 

changes to the LDAR program for natural gas processing plants that will redefine leaking valves 

as those leaking above 500 ppm will not lead to any substantial VOC emissions reductions. The 

commenter believes that lowering the leak definition to 500 ppm might reduce VOC emissions 

by less than 0.6 tons/year but this is much lower than the 10.9 tons/yr postulated by the EPA for 

the TSD model plant. Therefore, the commenter concludes that the proposed revised LDAR 

program for valves will be burdensome without achieving the VOC control claimed and, 

considering its poor cost effectiveness, does not represent BSER for natural gas plant equipment 

leaks, as required by the CAA for NSPS.

Response: We revisited the equipment leak costs and emission reductions for natural gas 

processing plants using data collected to support the development of the uniform standards for 

equipment leaks rule (40 CFR part 65, subpart J) that the EPA proposed on February 24, 2012. 
151

Using these data, we estimated the VOC reductions from going from a subpart VV to a subpart 

VVa LDAR program for a gas processing plant to be 4.56 tons per year at a cost effectiveness of 

$2,693 per ton of VOC removed. We believe the subpart VVa requirements are cost effective 

and represent BSER for equipment leaks at natural gas processing plants.

2.6.3 Control Techniques

Comment: One commenter (4357) states that periodic, routine measurement of emissions using 

mobile CRDS or other remote sensing systems will quantify pollutant emissions and provide 

real-time feedback for corrective action. The commenter (4357) believes this will achieve the 

objective of the proposed regulation to measure, document, and ultimately reduce fugitive 

emissions from upstream oil and gas processes.

Response: Cavity Ring-Down Spectroscopy (CRDS) analyzers are used to measure methane 

plumes in the air, map them, and then alert users and repair teams upon leak detection in realtime. This system would have more difficulty measuring VOC emissions from processing plants, 

because this system would require spectra for each of the VOC pollutants that are being 

measured. In addition, the analyzers require laser systems and high reflectivity mirrors which 

would make this system orders of magnitude more expensive than other alternative spectroscopic 

techniques. Therefore, we do not believe this system is an appropriate option for measuring 

equipment leak VOC emissions from natural gas processing plants. 

Comment: One commenter (4240) states that the EPA must require "repeat offenders" to be 

replaced. The commenter notes that the South Coast Air Quality Management District and 

Ventural County Air Pollution Control District each have rules under which components that 

have been subject to repair more than, e.g., 5 times within a year, be replaced with 

BACT/BARCT or be vented to an approved air pollution control device. One commenter (4375) 

urges the EPA to require equipment with an unsuccessfully repaired leak to be shut down until 

the leak is fully repaired. The commenter believes it unacceptable to allow a company to 

continue operating if a repair is "unsuccessful" because the company attempting to repair the 

leak is not incentivized to fix it rapidly.

Response: We do not have the data, nor did the commenter provide us any, to evaluate whether, 

and at which point, it becomes cost effective to replace a component that has been leaking as 

opposed to repairing it. We are therefore not requiring in this final rule that “repeat offenders” be 

replaced.
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2.6.3.1 Subpart VVa LDAR Program

2.6.3.1.1 Applicability

Comment: One commenter (4162) states that the EPA has proposed to adopt 40 CFR 60, 

subpart VVa, but did consider the option of making changes in standards for individual 

components. The commenter states that subpart VVa is beneficial as it provides a lower amount 

(ppm) for defining a leak, but these new emission sources have never been subject to Federal 

standards, and each of the components should be considered individually before a rule is 

established.

Response: We evaluated costs and emission reductions from both the individual component and 

LDAR programs during the development of the proposed standards. Based on these results, we 

determined that the subpart VVa LDAR program adequately reflected the emissions level for 

new sources nationwide. Many processing plants have already implemented a subpart VV LDAR 

program as part of the requirements for complying with NSPS requirements of subpart KKK.

Comment: One commenter (4240) states that while the EPA proposes to require all new gas 

processing plants to comply with the enhanced leak detection standards of subpart VVa, existing 

plants will continue to be bound by the more relaxed standards of subpart VV. The commenter 

states that the EPA estimates there are 577 existing plants operating in the U.S. today. The 

commenter states that applying the annual emission reductions from implementing a subpart 

VVa LDAR program to individual gas plants estimated in Table 8-13 of the TSD, extending the 

subpart VVa requirements to existing sources would result in an additional reduction of 7,790 

tons of VOCs from the atmosphere. The commenter indicates that the EPA must apply this more 

effective and less expensive, standard to existing processing plants immediately. The commenter 

asserts that no technical or logistical efforts appear to require a long phase-in period, though 

some need to hire or train sufficient workers may delay phase-in somewhat. The commenter 

states that even assuming some phase-in period, operators and the public can benefit from 

enhanced leak control as soon as the EPA extends these standards to existing sources.

Response: Section 111(b) of the CAA 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. Thus, the EPA does not have the authority under section 111(b) to extend the rule 

to existing sources. Due to the section 111(a) modification and reconstruction provisions, 

however, existing sources may become subject to the rule when modified or reconstructed.
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2.6.3.1.2 Cost impacts and cost effectiveness

Comment: One commenter (4266) states the EPA did not account for the additional cost to 

repair valves and connectors at natural gas processing plant if a leak is defined as 500 ppm. The 

commenter believes that the additional annual costs for repairing valves and connectors to a 

more stringent leak definition of less than 500 ppm are significant. For a natural gas processing 

plant, similar to the model plant in the TSD, the commenter estimates the incremental repair 

costs to range from $60,500 to $121,000 with an average of $90,750. The commenter believes 

that these costs must also be accounted for in the EPA’s BSER analysis prior to promulgating the 

new LDAR requirements.

Response: We disagree with the commenter that the repair costs for the subpart VVa standard 

were not accounted for in the cost analysis. Labor costs, material costs, and repair time were all 

included in the costs analysis that showed that the subpart VVa LDAR program was cost 

effective for natural gas processing plants.

Comment: Four commenters (4159, 4220, 4266, 4273) state that the EPA appears to be 

understating the costs of dropping the threshold regarding connectors in that the EPA assumes a 

cost of $1.50 per monitoring event. The commenters state that this does not reflect the true cost 

of monitoring connectors. The commenters add that connectors cost more to monitor per 

component than valves for a number of reasons: the time required to monitor a connector is 

longer because the entire circumference of the connector must be traversed; connectors often are 

in hard-to-reach locations; and some connectors require that a lift be rented to access them. In 

addition, the commenters state that connectors, by their nature, tend to be spread out and hard to 

find, particularly when monitoring events may be 4 years apart. The commenters state that it is 

likely that each time connectors are monitored it is being done for the first time by that operator. 

The commenters (4159, 4220, 4266, 4273) believe that recordkeeping will also be more costly 

and burdensome for connectors than for valves because valve additions or deletions are typically 

predetermined and approved by operations management, but connectors are not typically shown 

on process & instrumentation drawings which can lead to discovery after the fact by monitoring 

personnel. The commenters believe that this regulatory requirement for connectors would expose 

facilities to potential violations with no corresponding environmental benefit. The commenters 

state that to maintain a high level of compliance with such a requirement adds administrative 

burden and costs that are not reflected in the EPA’s cost estimates. The commenters recommend 

that the EPA should reconsider the proposed leak definition in view of the technical and 

logistical infeasibility of online valve repair to below 500 ppm within the 15-day repair period. 

The commenters state that many of the leakers would require delay of repair, and thus the 

expected reductions would not be realized. One commenter (4192) states the EPA should 

confirm that, for purposes of this subpart, it is not necessary to tag each connector. The 
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commenter believes that, as allowed in Applicability Determination Control Number: NR89, an 

alternative marking system of assigning each connector an identification number corresponding 

to the nearest piece of physically-tagged equipment, and recording that identification number in a 

log, should be acceptable.

One commenter (4266) states that they have collected limited data from three natural gas 

processing facilities that voluntarily monitor and record screening values for connectors. The 

commenter states that, as expected, connectors do not exhibit significant VOC emissions, and do 

not typically register concentrations over 10,000 ppm when monitored with VOC sniffers. The 

commenter also states that for the process units analyzed, the number of connectors range from 

1,463 to 11,272, and the corresponding emissions range from 0.076 to 1.77 tpy of VOCs. The 

commenter adds that for those process units 27 – 57 percent of the connectors are found to be in 

the screening value range of 500 and 10,000 ppm. The commenter states that when these data are 

normalized for a facility with an equivalent number of connectors as in the model plant, 

potentially reducible emissions from connectors are 0.87 tons VOC/year. Therefore, according to 

the commenter, a value of 0.87 tpy of VOC emission reduction is a more realistic value than the 

EPA’s 1.57 tpy estimate to judge the effectiveness of the proposed connector program. The 

commenter believes that this value and a more realistic CE than the 95.9 percent the EPA 

assumed should be used to calculate the cost effectiveness of the proposed connectors program. 

One commenter (4192) states that, for connectors, the EPA should keep the subpart VV standard 

of detecting potential leaks by means of AVO or any other detection method. Two commenters 

(4192, 4246) believe that the connector monitoring cost should be $2.50/connector as was 

assumed for the refining sector, as there is no reason to believe that connector monitoring costs 

should be lower for natural gas processing plants. The commenter also believes that the EPA 

should apply the original subpart KKK assumption that there are 4.25 connectors for each valve 

at an average natural gas processing plant, and recalculate the cost analysis of connector 

monitoring accordingly. The commenter states that applying correct assumptions regarding 

monitoring costs and the quantity of connectors would nearly double the cost per ton associated 

with connector monitoring. The commenter recommends that a new provision, 40 CFR 

§60.5401(j), be added that reads: “Connectors are exempt from 40 CFR §60.482-11a. Instead, all 

connectors are subject to 40 CFR §60.482-8a.” 

Two commenters (4192, 4246) believe the EPA should assume a connector monitoring cost of 

$2.50/connector, as the EPA has previously assumed for the refining sector. The commenters 

also ask the EPA to increase the assumed number of connectors in gas plants to at least the 

original NSPS subpart KKK estimate of 4.25 connectors to 1 valve and recalculate the cost 

analysis of connector monitoring accordingly. The commenters expect this will nearly double the 

costs per ton associated with connector monitoring. The commenter (4266) believes the EPA 
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oversimplified cost assumptions and failed to consider such factors as high turnover of 

personnel, remoteness of some locations, and added administrative burden. 

One commenter (4193) urges the EPA to eliminate connectors from the list of monitored 

equipment. The commenter believes the EPA should keep the subpart VV standard for 

connectors of “evidence of a potential leak is found by visual, audible, olfactory, or any other 

detection method.” One commenter (4218) recommends that subpart OOOO instead require that 

gas/vapor connectors be monitored through AVO, similar to liquid connectors. The commenter 

states that those connectors discovered through OVA inspections can be monitored by Method 

21 to confirm a leak, or assumed to be leaking by the owner. The commenter asserts that, at that 

point, leaking connectors should be required to meet the work practice standards for repairs in 

proposed §60.5401(b)(3).

Response: The cost for monitoring connectors was based on cost data from the SOCMI and 

refinery facilities. Additional connector cost data was reviewed during the comment period that 

lists a cost of $2.50 for monitoring connectors based on information provided by a monitoring 

repair contractor. Substituting this newer connector monitoring cost into the incremental cost 

calculation increases the VOC cost effectiveness from $3,352 to $3,434, which we believe is still 

cost effective.

We disagree with the commenter that administrative costs were not considered in the cost 

estimate. The cost estimates provides 300 hours annually for administrative and reporting labor 

for implementing the LDAR program. In addition, the cost estimate provides 340 hours for 

training and planning for the LDAR program. We believe these hours will provide sufficient 

time to implement the LDAR program and locate all the connectors at the facility. The 

requirements in §60.486a requires identification of all equipment, including connectors, that are 

being monitored. The EPA believes the identification of these components is needed to ensure 

compliance with the final regulations and allow inspectors to monitor ongoing compliance at the 

facility. We believe the inclusion of connectors in the LDAR program provides significant VOC 

reduction and is cost effective. With respect to the applicability determination, the final rule 

requires that all connectors be tagged, but a facility can work with their respective regulatory 

agency to determine what connector identification method is acceptable.

We reviewed the data provided by the commenter regarding the VOC emission reductions 

corresponding to voluntary connector monitoring. However, we are unable to verify the claims 

because the commenter did not submit the referenced data. The small sampling does show that 

significant VOC reductions can be achieved through a connector monitoring program. The EPA 

did recalculate the connector monitoring emission reductions using emissions data and 

methodology used to develop the Uniform Standards rule and found that the connector 

monitoring in the subpart VVa regulations would reduce VOC by 2.74 tons per year.
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We disagree with the commenter regarding the infeasibility of valve repair to below 500 ppm 

within the 15-day repair period. Leaks from valves are typically repaired by replacing the 

packing or seals in the valve stem, and is considered to be part of the normal maintenance of a 

facility. The repair of leaking valves not only eliminates emissions from that equipment, it also 

helps maintain the physical integrity of the facility, thereby reducing the likelihood of leaks 

elsewhere on the line.

2.6.3.1.3 Less frequent monitoring of valves and connectors

Comment: One commenter (4266) requests the EPA reconsider its proposed alteration of the 

equipment leaks program for natural gas processing plants. If the EPA demonstrates that tighter 

VOC emission control is justified, the commenter offers an alternative program. First, the 

commenter states, set up an LDAR program that requires on-going quarterly monitoring for 

valves (no skip periods allowed), retaining the current subpart KKK leak definition of 10,000 

ppm and associated repair intervals. Next, the commenter adds, for initial compliance purposes, 

valve monitoring would be undertaken monthly during the first quarter of becoming subject to 

this program, then quarterly. The commenter states that new and repaired components would be 

monitored on the quarterly basis. Third, the commenter states, facilities would be required to 

establish internal programs to identify valves that leak above 10,000 ppm during three of the four 

quarters in a year. The commenter states that these valves would be placed on a ‘chronic leakers’ 

list and would be designated for refurbishment and/or replacement during the next process unit 

shutdown. Fourth, the commenter recommends no new LDAR program for connectors. The 

commenter recommends that connectors in gas/vapor service and in light liquid service be 

subject to the monitoring and leak definition provisions in §60.482-8a. Two commenters (4246, 

4266) oppose the proposed 500 ppm threshold for pumps. One commenter (4246) states the EPA 

should exclude reciprocating pumps in light liquid service that cannot meet the leak standard 

without recasting of the distance piece or replacement of the pump. The commenter states it is 

extremely difficult to meet the 10,000 ppm emission standard with existing positive 

displacement pumps and they stand little or no chance of achieving the proposed 500 ppm 

threshold. One commenter (4266) states the EPA should retain the 10,000 ppm leak definition 

for pumps or consider a 5,000 ppm leak definition. 

Response: We appreciate the commenter’s suggestion, but believe that the subpart VVa LDAR 

requirement is BSER for natural gas processing plants. The standards set in the new subpart are 

based on what the EPA has determined to be BSER for a national standard. This standard will 

not conflict with other CAA programs and not cause violations in following other parts.
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2.6.3.2 LDAR with Optical Gas Imaging

Comment: The EPA received varied opinions regarding use of the optical gas imaging (OGI) 

detection systems. 

One commenter (4170) states 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 supports the use of auditory, visual and olfactory inspections, at a 

minimum, to minimize the fugitive emissions from equipment leaks. Two commenters (4178, 

4356) assert that EPA 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. 

Three commenters (4246, 4266, 4320) state that implementing an OGI-only alternative work 

practice (AWP) is consistent with the 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 EPA 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 EPA Method 21 as part of initial compliance. The EPA also received a request from one 

commenter (4266) 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, one commenter (4237) suggests that the EPA use optical imaging 

as a pilot program to better estimate its cost effectiveness, and another commenter (4170)

suggests that the EPA base the cost effectiveness of LDAR on all VOC pollutants, as well as 

GHG emissions such as methane.

One commenter (4240) states that the use of optical scanning devices, pressure relief valves, 

monitoring devices and other technical advances can complement existing programs. However, 

the commenter believes that the suite of existing options have not demonstrated the ability to 

provide the level of emission reductions as can be obtained from well-designed and implemented 

LDAR programs. The commenter recommends that these options be considered in addition to 

and not in lieu of existing programs. The commenter opines that the LDAR program must 
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incorporate elements beyond thresholds and schedules. The commenter states that an alternate 

compliance option and allowable level of designated “difficult to monitor” valves must be 

reviewed in light of the performance of best performing LDAR programs. The commenter 

suggests that the EPA limit the exemptions for devices that are difficult or unsafe to monitor or 

repair by providing that when such devices are replaced, they must be replaced with leakless 

designs, as this should be cost-effective. The commenter adds that because the NSPS only 

applies to newly installed components, advanced technology components must be required at the 

time of initial installation for those components that, if they leaked, would require a plant 

shutdown to repair. The commenter states the EPA must also explore whether optical scanning 

provides a way to monitor devices that would be difficult or unsafe to monitor using traditional 

monitoring techniques.

Response: As explained in the preamble to the proposed rule, the option of using optical gas 

imaging alone to detect leaks instead of the traditional LDAR program (e.g. Method 21 

monitoring) was considered but was not determined to be BSER for any of the oil and gas

segments. The cost effectiveness of the OGI only LDAR program could not be calculated 

because currently there is no methodology for estimating VOC emission reductions with OGI 

alone. Because the EPA must consider cost in determining BSER and setting appropriate NSPS 

standards, the EPA cannot first require OGI alone as a pilot program and then determine later its 

cost effectiveness, as one commenter suggests. Although the EPA may consider the cost 

effectiveness of reducing other pollutants from this option (assuming that can be determined), 

such analysis cannot replace a cost effectiveness determination based on VOC, which the EPA 

must evaluate in order to determine whether OGI only is a cost effective measure for reducing 

VOC emission from equipment leaks and therefore qualifies as a BSER. 

We also received comments asking that we allow an OGI-only option as an alternative work 

practice (AWP), as in the GHG Reporting Rule, 40 CFR part 98, subpart W. Although we have 

determined that OGI-only is an appropriate AWP for the Reporting Rule, we did not propose 

such an option for subpart OOOO as an alternative to the Method 21-based LDAR requirements. 

We need additional time and information to evaluate whether such an alternative option is 

appropriate for this NSPS, in addition to the AWP of periodic monitoring for leaks using OGI 

accompanied by an annual Method 21 survey currently allowed under 40 CFR 60.18(g) and (h). 

We plan to continue this evaluation and are therefore not taking action on this suggestion at this 

point. With respect to the comment on the use of other sensory inspections, the EPA notes that 

subpart OOOO, which basically adopts the requirements of subpart VVa, already requires 

sensory monitoring where specific leak definitions and monitoring frequencies are not specified 

(e.g. §60.482-8a – standards for pumps, valves, and connectors in heavy liquid service and PRD 

in light liquid or heavy liquid service).
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With respect to the comments on the 10 percent AWP sensitivity test and video recording, the 

comments relate to requirements in the current and/or previous NSPS General Provisions at 

§60.18(g) and (h). The EPA did not propose to revise these General Provisions, which apply to 

many other source categories. The EPA is therefore not addressing these comments in this final 

rule.

2.6.4 Other Comments

Comment: Two commenters (4192, 4246) state that existing “process units” not formerly 

subject to a NSPS LDAR requirement should be allowed 180 days to make the transition if 

subject to the new subpart OOOO LDAR requirements, as is allowed in NSPS subpart KKK.

Response: For an existing source to become subject to the provisions of subpart OOOO, it 

would have to meet the reconstruction or modification requirements in the General Provisions. 

These requirements state that “reconstruction” means the replacement of components of an 

existing facility to such an extent that the fixed capital cost of the new components exceeds 50 

percent of the fixed capital cost that would be required to construct a comparable entirely new 

facility. A gas processing plant that is being reconstructed would have the time needed to put in 

place an LDAR program during the reconstruction efforts to be in compliance with the LDAR 

requirements upon startup of the reconstruction source.

Comment: One commenter (4240) states that since the development of subpart VV and subpart 

KKK standards, much has been learned about what it takes to have an effective leak detection 

program. The commenter states that investigations by the EPA Regional and National 

Enforcement Investigations Center personnel detected massive fraud in the conduct of LDAR 

inspections and in the reporting of results. The commenter states the most significant violations 

were LDAR rules violations where refiners, and independent contractors hired by refiners, 

routinely underreported (by up to a factor of 10) the number of leaking valves. The commenter 

believes this demonstrates a need for detailed independent oversight of LDAR activities, as does 

the recent Pelican refinery criminal prosecution. The commenter states that in the absence of a 

sustained Federal focus on this issue and recognizing the likely lack of State resources in the near 

future, MACT should include some form of independent auditing of LDAR programs. The 

commenter states the EPA could require an independent audit of sources with a large number of 

components, perhaps once every 5 years. The commenter states that enforcement action-induced 

negotiations with refinery operators led to consent decrees that substantially improved the real 

world effectiveness of those programs and the development of Best Practice Guidelines. The 

commenter adds that various States and regional entities have adopted LDAR programs. The 

commenter further states that many of these consent decrees and State regulations are more 

stringent than the subpart VVa regulation the EPA proposes to adopt for processing plants, yet 

the EPA’s BSER review did not examine these activities and practices. The commenter believes 
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the EPA must either adopt elements of these more stringent programs as BSER or explain why 

these elements are infeasible.

Response: We disagree with the commenter and believe that the recordkeeping requirements in 

subpart VVa will provide assurance that the facility is in compliance with the LDAR 

requirements.

Comment: One commenter (4375) is concerned about the proposal to allow the Administrator to 

judge acceptance of an alternative means of emission limitations under §60.5402. The 

commenter states the criteria the Administrator uses in making such an allowance in not clear, 

suggesting a less than objective standard. The commenter states there is nothing in this section

requiring the Administrator to make a decision based on emission limitation data. The 

commenter states this section should focus on a data-driven decision that requires no discretion 

and rests upon tested means and a formulaic set of criteria that affirmatively prove an alternative 

means of emission limitation will be in place, which will result in at least the same amount of 

emissions reductions. 

Response: We disagree with the commenter. The General Provisions to 40 CFR part 60 provides 

the Administrator of the EPA the authority to approve an alternative means of emission 

limitation specified by the subparts. 

Comment: One commenter (4263) states that the EPA should revise the definition of "natural 

gas processing plant" in 40 CFR part 60 subparts KKK and part 63 subpart HH to clarify the 

meaning of the term, as acknowledged by the EPA in numerous applicability determination 

memos. The commenter states that the EPA should amend §60.631 as follows: “Natural gas 

processing plant (gas plant) means any processing site engaged in the forced extraction of natural 

gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or 

both. Forced extraction processes include for example cryogenic Joule-Thomson, refrigerated 

absorption and cryogenic Joule-Thomson and expander. Facilities that remove liquids from field 

gas by means other than a forced process (e.g., gravity or natural condensation) are not natural 

gas processing plants. Facilities that are engaged in fuel gas conditioning or dew point 

suppression that do not generate natural gas liquid “product” are not natural gas processing 

plants.”

Commenter (4263) adds that in developing subpart KKK, the EPA clarified its intended meaning 

of the term "natural gas processing plant" to include only those facilities engaged in the forced 

extraction of NGL from field gas and/or fractionation of mixed NGL into natural gas products, as 

these facilities are commonly understood within the industry. According to the commenter, the 

Background Information Document for both the proposed and final standards clarified the EPA's 

intent, but the definition in the rule remained somewhat ambiguous. Since the 1983 rulemaking, 
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the commenter states that State regulatory authorities and the gas processing industry sector have 

been compelled to seek EPA guidance on the interpretation of the definition. The commenter 

notes that the EPA has issued several determinations clarifying its intent and meaning of the term 

within NSPS and MACT. To avoid the need for future applicability determination requests, the 

commenter recommends that the EPA should add that clarification be added to the definition in 

each relevant standard, consistent with EPA guidance.

One commenter (4266) is concerned that under the current definition in the proposed §60.5430, 

many very small remote sites without stable power supply would be defined as a natural gas 

processing plant, and thus subject to the LDAR requirements of the proposed rule. The 

commenter believes it is both technically and economically infeasible for such sites to comply 

with any LDAR requirements, especially the very stringent subpart VVa requirements. The 

commenter requests that the EPA address this issue by modifying the definition of natural gas 

processing plant by inserting the word “forced” before “extraction of natural gas liquids...”; and 

adding a new definition of “forced extraction of natural gas liquids” that is essentially adopted 

from the GHG MRR. 

One commenter (4292) recommends that the definition of natural gas processing plant be revised 

to exclude dew point depression or Joule-Thompson valves installed for the purpose of meeting 

pipeline specifications. The commenter states that these devices are typically installed at 

production sites or sometimes at a compressor station. The commenter further explains that the 

infrastructure and remote location of these small stations would not support the additional 

requirements imposed by subpart OOOO for pneumatic controllers and LDAR.

Response: In the proposed standards, a "natural gas processing plant" (gas plant) is defined as 

"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." The definition was intended to 

exclude facilities that remove liquids from field gas by means other than a forced process (e.g., 

gravity or natural condensation). The EPA has had extensive discussions with industry and trade 

associations during the development of this rule related to the definitions of field natural gas and 

production wells. Based on this information, the EPA has revised the definition in the final rule 

to state that a Joule-Thompson valve, a dew point depression valve or an isolated or standalone 

Joule-Thompson skid is not considered a natural gas processing plant. We do not believe that the 

definition for a natural gas processing plant needs to be modified by inserting the word “forced.” 

A review of the GHG MRR definitions did not include this term, nor was the definition of a 

natural gas processing plant included. The proposed definition is intended to only include 

facilities that are engaged in the extraction of natural gas liquids from field gas, fractionation of 

mixed natural gas liquids to natural gas products, or both, and believe the subpart VVa 

equipment leak requirements are appropriate.
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Comment: One commenter (4266) states that proposed §63.769(b) exempts ancillary equipment 

and compressors subject to part 63 subpart H and part 60 subpart KKK from the proposed 

§63.769(c) equipment leak requirements. The commenter believes this exemption should also 

apply to equipment and compressors that are subject to the new subpart OOOO, since otherwise 

duplicative and sometimes conflicting requirements would apply. 

Response: We agree with the commenter and have revised §60.5365(f) to clarify our original 

intent that compressors not be included in the equipment leak provisions because leaks from rod 

packing are addressed in the rod packing replacement requirements of §60.5385.

Comment: One commenter (4178) states the rule should require that the regulated industry 

annotate the difference between existing/new compressors and equipment in the Master 

Equipment Lists and other records to be clear about which components are subject to which 

standards (subpart KKK or subpart OOOO). The commenter states it is likely that existing 

onshore natural gas plants in areas of rapid growth in natural gas production will expand their 

facilities by adding new process units which will require capital expenditures and thus qualify as 

new construction of compressors and equipment (as defined in §60.5430). The commenter 

believes this would create a situation wherein part of the processing plant would be subject to 

subpart KKK standards (existing) while the rest of the plant would be subject to subpart OOOO 

standards (new), thus creating significant inefficiencies and potential inaccuracies in determining 

compliance. The commenter states this burden would fall on the shoulders of both the regulatory 

agency and the regulated entity. 

Response: We believe the burden falls on the facility to properly identify which piece of 

equipment is associated with the proper subpart to show compliance. The final rule contains 

recordkeeping and reporting requirements that require the facility to identify equipment using a 

unique equipment identification number for both subpart KKK and OOOO and should be 

reflected in their semiannual reports. 

Comment: One commenter (4191) states that, while the EPA has indicated that reciprocating 

compressors have fugitive emissions that cannot be captured, they have two examples of 

facilities that collect emissions from leaking rod packing, venting the emissions to the 

atmosphere from a common point. The commenter will provide further data on these facilities at 

the EPA’s request.

Response: Rod packing leaks from reciprocating compressors are not included in the LDAR 

program in the final rule and is addressed in the subpart OOOO reciprocating compressor 

requirements. These requirements call for the periodic replacement of rod packing to reduce 

fugitive emissions from reciprocating engine rod packing. 
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Comment: One commenter (4192) states the current difficult-to-monitor (DTM) definition as 

cited in subpart VV §60.482-7(h)(1) allows the owner or operator to exempt quarterly 

monitoring of a valve if it can be demonstrated that the valve cannot be monitored without 

elevating monitoring personnel more than 2 meters above a support surface. The commenter 

believes the EPA needs to provide further clarification and revisions to the definition to include 

areas classified as confined space and hazardous working environments that require 

supplemental breathing air for entry and monitoring. Two commenters (4192, 4246) recommend 

that a new provision, 40 CFR §5401(m), be added stating that “For purposes of this subpart and 

40 CFR §60.482-7a(h)(2)(ii), up to 5.0 percentof valves may be designated as difficult-tomonitor.” 

According to the commenter (4192), the BID for subpart KKK states that the 3 percent difficult 

to monitor (DTM) standard is based a refinery maintenance study (Docket Item II-A-11). The 

commenters believe it is inappropriate to apply limits derived from a refinery maintenance study 

to valves associated with gas plants, because the number of valves common to a refinery is 

substantially different than the number of valves in a natural gas processing plant. The 

commenters state that a process unit that has 100 valves would only allowed to designate 3 

valves as DTM, though 5-6 valves may meet the definition. The commenters state that refineries 

find the 3 percent DTM limit less constrictive due to the large quantity of valves present at any 

given facility. The commenters add that the configuration of natural gas processing plants lends 

itself to more DTM situations as refinery piping usually contains liquids, and valves are either 

close to the ground or in pipe racks with elevated walkways, whereas gas plant piping usually

contains gas, and valves are often elevated. 

Response: We disagree that revision is necessary regarding DTM conditions as we have 

finalized standards in §60.5416(e) and (f) that allow provisions that would cover the situations 

described by the commenter. We also disagree with the commenter that the percent of valves that 

can be designated as DTM is inappropriate for natural gas processing plants. The commenter did 

not provide any data to support their assertion that this provision is inappropriate.

Comment: One commenter (4191) recommends that the EPA clarify its intention for the 

monitoring requirements of a pressure release device at a non-fractionating plant, monitored only 

by non-plant personnel. The commenter states it appears the proposed rule allows operators to 

monitor a pressure relief device with a pressure release on the next on-site visit, 

(§60.5401(b)(4)(i)) which is likely to be no sooner than the next quarterly visit, while also 

requiring monitoring within 30 days (§60.5401(b)(4)(ii)) of the pressure release.

Response: Section 60.5401(b)(4)(ii) states that you cannot continue to operate your pressure 

release device more than 30 days after a pressure release has occurred without monitoring if the 

PRD is located at a non-fractioning plant that is monitored only by non-plant personnel. If a 
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pressure release has not occurred within these parameters, the requirements of §60.5401(b)(1) 

apply.

Comment: One commenter (4191) suggests that the EPA explain the reason that sampling 

connection systems are being exempted from the leak standards for such systems in §60.482-5a 

(§60.5401(c)).

Response: The EPA found that when collecting gas samples, the space (tubing or pipe) between 

the valves on the sample container and in the closed-loop system will contain process gas. This 

trapped gas does not have to be collected or captured because it is not a purged process fluid. It 

may be released to the atmosphere when the sample container is disconnected. The standards in 

§60.482-5a of subpart VVa explicitly exempt gases remaining between the sample container and 

closed-loop system valves from control requirements. 

The EPA decided not to explicitly exempt gas sampling activities from the sampling connection 

system requirements because the Agency does not have evidence that such sampling never 

involves purging. Furthermore, §60.482-5a(c) already exempts sampling systems without purges 

from the sampling connection system requirements. 

Comment: Concerning alternative work practices (§60.5400(b)), one commenter (4192) 

recommends that the EPA add a new exemption, codified as §60.5401(n), that reads: “The 

alternative work practices, as specified in §60.487(d) can be made when eligible without 

notification to the Administrator.” The commenter also recommends adding a new paragraph (i) 

to NSPS subpart KKK, 40 CFR §60.633, as follows: 40 CFR § 60.633(i) An owner or operator 

may use the following provision instead of § 60.487(d): “An owner or operator who elects to 

comply with the provisions of §§60.483–1 or 60.483–2 is not required to notify the 

Administrator of the alternative standard selected before implementing either of the provisions.” 

The commenter believes that the requirement to notify the Administrator of the alternative 

standard selected 90 days before implementing either of these provisions is very difficult for 

owners and operators to track and implement, and yields no benefit. The commenter believes that 

eliminating the advance notice requirement for use of these alternative standards would help 

streamline the LDAR program without increasing emissions from subpart KKK regulated 

facilities.

Response: We believe that alternative standards need to be approved by the Administrator and 

the General Provisions to 40 CFR part 60 provides the Administrator of the EPA the authority to 

approve an alternative means of emission limitation specified by the subparts.

Comment: Two commenters (4192, 4246) state that, if affected facilities under subpart OOOO 

are required to comply with 40 CFR §60.8, then the EPA should clarify what constitutes a 
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performance test and under what circumstances affected facilities would be required to complete 

a performance test. The commenters would also like clarification that the EPA does not interpret 

the initial LDAR monitoring as an initial performance test subject to 40 CFR §60.8. 

Response: The final rule lists those affected facilities that must conduct performance tests as 

required under §60.8. Specific conditions under which these performance tests must be 

conducted and the test methods that must be used are listed for each affected facility type. 

Although LDAR monitoring is generally performed using Method 21, a performance test, we do 

not intend for LDAR monitoring to be subject to the performance test requirements of §60.8. 

You are still subject to the reporting and recordkeeping requirements of §§60.486a and 60.487a, 

respectively, as applicable. 

Comment: One commenter (4192) recommends that a new provision, 40 CFR §60.5401(l), be 

added that reads: “An owner or operator is exempt from the requirement in §60.485a(b)(2) to 

calculate the average algebraic difference between the three meter readings and the most recent 

calibration value and divide this algebraic difference by the initial calibration value and multiply 

by 100 to express the calibration drift as a percentage. Additionally, the commenter requests that 

the requirement to record the instrument reading for each scale used as specified in 

§60.486a(e)(7) be changed to §60.486a(e)(8).” The commenter states it is their understanding 

that the EPA recognizes that the referenced language is not pertinent and will be removed in a 

forthcoming proposal for subparts VV/VVa/GGG/GGGa. Rather than wait until this proposal is 

developed, the commenter suggests that the EPA make it clear in subparts KKK and OOOO that 

this language is inapplicable. In addition, the regulatory citation in §60.485a(b)(2) should be 

“§60.486a(e)(8)” instead of “§60.486a(e)(7).” 

Response: We acknowledge that the citation to §60.486a(e)(7) within §60.485a(b)(2) is an error. 

Therefore, we have included an exemption for §60.485a(b)(2) in the final rule to correct this 

citation to read, “§60.486a(e)(8).” In addition to correcting the citation, we have made technical 

edits to the rule language for calibration drift assessments for clarification purposes.

Comment: One commenter (4192) recommends that the EPA keep the subpart VV standard of 

“evidence of a potential leak is found by visual, audible, olfactory, or any other detection 

method.”

Response: The subpart VVa requirements allow the use of sensory monitoring for components 

followed by a Method 21 check. In some cases for no detectable emissions, sensory monitoring 

is allowed for pumps, valves in heavy liquid service, or pumps in light liquid service. 

Comment: One commenter (4192) requests confirmation from the EPA that a valve on a 

quarterly monitoring schedule per subpart VV that is placed temporarily out-of-service (that is, 
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the valve is completely blown down and drained of process fluid, and therefore no longer “in 

VOC service”) may resume a quarterly monitoring schedule when it is returned to service, 

provided it was not leaking prior to being removed from service. 

Response: The commenter is correct in the determination that a valve on a quarterly monitoring 

schedule per subpart VV that is placed temporarily out-of-service may resume a quarterly 

monitoring schedule when it is returned to service, provided it was not leaking prior to being 

removed from service.

Comment: One commenter (4208) believes the EPA should consider requiring the use of leak 

detection equipment that can detect methane leaks (such as a flame ionization detector calibrated 

to methane) to ensure that leaks – whether of HAPs like benzene, criteria pollutants such as 

sulfur dioxide, or hydrocarbons – would be quickly and accurately detected.

Response: Subpart OOOO is a VOC rule which includes HAPs like benzene and some 

hydrocarbons but does not include SO2 or methane. 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. The VOC requirements in this 

rule would also achieve substantial reduction in methane emissions. However, the EPA does not 

have sufficient information at this time to assess whether the category continues to emit 

significant amount of methane even with the expanded VOC controls and what measures are 

appropriate for reducing the remaining methane emissions. For these reasons, the EPA is 

continuing its assessment of methane emissions, including gathering and reviewing additional 

information, to evaluate appropriate actions. 

Comment: Three commenters (4192, 4208, 4246) state that the affected facility defined in 

proposed §60.5365(f)(4) should not include “field gas gathering system.” One of the commenters

adds that by including the gathering system in the affected facility, the equipment potentially 

extends outside the gas processing plant through all the field gas gathering system along with all 

the compressor stations. The commenter believes this will make defining the boundary of each 

gas processing plant difficult and could impose significant costs by requiring leak detection 

monitoring at remote locations spread over very large areas. 

Response: We have not made any changes since proposal to the requirements for affected 

facilities at onshore natural gas processing plants for the final rule. The gas processing plant may 

include other equipment that are affected sources under subpart OOOO, but the equipment leak 

requirements of the gas processing plant are not intended to be extended through all the field gas 

flow system along with all the compressor stations.
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Comment: One commenter (4240) states that the EPA must ensure the integrity of the LDAR 

program by including safeguards in its rules, including requiring a professional engineer to sign 

off on all LDAR reports. The commenter recommends that the EPA also explore requiring 

periodic independent audits of LDAR programs, at least for larger processing plants.

Response: We disagree with the commenter and believe that the recordkeeping and reporting 

requirements associated with the subpart OOOO equipment leak provisions will ensure the 

integrity of the LDAR program. 

Comment: One commenter (4240) states the definition of “gas processing plant process unit” 

should be expanded to include all common gas processing processes. The commenter believes 

there may be confusion over what constitutes a “process unit” given the affected facility 

language of §60.5365(f)(1)-(2) and the definition of “gas processing plant process unit” at 

§60.5430.

Response: We disagree with the commenter and believe that the applicability requirements and 

definitions are appropriate for gas processing plants. The EPA has had extensive discussions 

with industry and trade associations during the development of this rule related to the definition 

of gas processing plant unit and believe we have developed a definition that provides a clear 

definition of the gas processing plant unit.

Comment: One commenter (4240) believes the EPA may be overstating the cost of LDAR 

programs for non-processing-plant facilities, and must at least reconcile its current cost estimates 

with those in the EPA's 2009 Methane to Markets report. The commenter states that the Methane 

to Markets presentation identified drastically lower LDAR costs per device monitored. At a 

minimum, the commenter believes that the EPA must evaluate whether monitoring is BSER for 

specific components, and justify its decision not to apply it.

Response: The TSD for the proposed NSPS examined costs of LDAR programs for individual 

components as well both processing and non-processing facilities. Based on the results of this 

analysis, it was determined that the subpart VVa LDAR program was BSER for natural gas 

processing plants. During the comment period, we used data and methodology from the Uniform 

Standards rulemaking to reanalyze the LDAR programs for individual components and oil and 

gas facilities. The results from this analysis were comparable to the results found during the 

proposed rule analysis. Therefore, we did not revise the equipment leak requirements in subpart 

OOOO. Please see docket item EPA-HQ-OAR-2010-0505-0045 for more details.

Comment: One commenter (4266) requests that EPA clarify the applicable provisions for 

compressors located at an onshore natural gas processing plant. The commenter states

that the inclusion of compressors in affected facility descriptions in §60.5365(b) and (c) 
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and also in §60.5365(f) causes confusion as to the applicable requirements under NSPS 

subpart OOOO. Comparing chapter 6 of the TSD (which included compressors in natural 

gas processing plants in the options under §60.5380 and §60.5385) with chapter 8 of the 

TSD (which on page 8-21 stated that compressors are not regulated in the LDAR option 

and are regulated separately), the commenter concludes that the EPA intended to regulate 

affected compressors under §60.5380 and §60.5385 and not under the LDAR 

requirements for natural gas processing plants. One commenter (4263) states that 

equipment (as defined in §60.5430) not located at the onshore natural gas processing 

plant site should be excluded from the rule entirely, not just from certain sections and 

paragraphs. The commenter believes that listing individual sections in the rule that apply 

to equipment located at a natural gas processing plant in VOC service or wet gas service 

implies that some sections or paragraphs of the rule could apply to such equipment. 

Response: The commenter is correct in their assertion that the EPA “intended to regulate 

affected compressors under §60.5380 and §60.5385 and not under the LDAR requirements for 

natural gas processing plants.” To make this clear, in the final rule we have revised §60.5365(f) 

by describing an affected facility to be the group of all equipment, except compressors, within a 

process unit. 

Comment: One commenter (4266) recommends that the EPA add an additional delay of repair 

provision for on-line repairs utilizing specialized methods. The commenter states such repairs 

may be technically feasible, but are not logistically or economically feasible to be performed 

repeatedly to below 500 ppm within very narrow time windows. The commenter believes these 

facilities should be allowed a maximum of 90 days to complete these specialized repair attempts. 

The commenter adds that allowing more time reduces the cost burden and minimizes travelassociated emissions by enabling the repair of multiple components during fewer contractor site 

visits. The commenter notes that, according to §60.482–9(a) of subpart VV, delay of repair is 

allowed if repair is technically infeasible without a process unit shutdown, and §60.482–9(c) of 

subpart VV allows delay of repair of valves if emissions associated with immediate repair would 

exceed continued emissions from the leak. 

Response: The equipment leak requirements in §60.5401(b)(3)(i) allow the delay of repair when 

a leak is detected using the criteria in §60.482-9a, which are the same exemptions noted by the 

commenter.

Comment: One commenter (4266) states there is an apparent typographical error in 

§60.5401(d), which reverses the small non-fractionating plant exemption in subpart KKK. The 

commenter states that subpart KKK exempts any non-fractionating plant that does not have the 

design capacity to process 10 million scf/day or more of field gas.
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Response: The commenter is correct and the requirement in §60.5401(d) should exempt any 

non-fractionating plant that does not have the design capacity to process 10 million scf/day or 

more of field gas.

Comment: One commenter (4266) notes that §60.5401(d) exempts certain components at small 

non-fractionating gas plants from the routine monitoring requirements of §§60.482-2a(a)(1), 

60.482-7a(a), and 60.5401(b)(1), and §60.5401(e) exempts those located in the Alaskan North 

Slope. The commenter recommends also exempting these components from the reporting 

requirements.

Response: We believe that the same reporting requirements for facilities located in the Alaskan 

North Slope in subpart KKK are appropriate for facilities located in the Alaskan North Slope in 

subpart OOOO.

Comment: One commenter (4263) states the EPA should add a reference to the definition of 

"capital expenditure" in subpart VVa or add a definition to §60.5430(f)(3) for “Addition or 

replacement of equipment.” The commenter believes that without the definition, the use of the 

term "capital expenditure" leads to the conclusion that any addition of a valve, for example, 

would be a modification. Another commenter (4266) states that LDAR process units often use 

the concept of "capital expenditure" to prevent the addition of a few minor components from 

triggering modification and believes that the EPA needs to clarify the meaning of "capital 

expenditure" for the purposes of subpart OOOO.

Response: The General Provision at 40 CFR 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). Therefore, we do not believe that the 

regulatory definition of “capital expenditure” needs to be clarified for LDAR process units.

2.7 Innovative Compliance Approaches

2.7.1 Registration of Wells and Advance Notice of Completions

2.7.1.1 Length of Advance Notifications Required

Comment: One commenter (4274) is not certain that the 30-day advance notice of hydraulic 

fracturing is realistic. The commenter states that, in their experience living within the Marcellus 

Shale area, while notifications are provided, the activity does not always materialize. The 

commenter states that the Commonwealth is considering legislation on several notifications from 

the operators to the state regulatory agency and asks if the operator would have to contact both 

agencies. The commenter believes it would be more reasonable for the State to send this 
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information electronically to the EPA. According to the commenter, the State regulatory agency

will utilize this information in many ways, including scheduling field staff for corresponding 

inspections. Presently, the commenter states that they do not have any requirement for hydraulic 

fracturing notification, it is done at the local level. The commenter supports the EPA’s role as not 

all States have such a provision. The commenter believes there is a need for coordination with 

States to avoid duplication of efforts. The commenter recommends that the EPA consider this 

information and move forward with a modified provision of the proposal.

One commenter (4472) believes that the proposed 30-day notice requirement will result in 

substantial delay in completion of natural gas wells in Texas and unanticipated costs due to the 

high competition for specialized hydraulic fracturing services, equipment and personnel, as well 

as REC equipment and personnel. The commenter estimates that of the nearly 11,000 well 

permits issued in 2010 within Texas approximately 85 percent of those were hydraulically 

fractured. The commenter believes owners and operators must have the flexibility to contract for 

services as soon as equipment and personnel become available.

Response: To lessen the burden of the 30-day notification requirement for well completions, we 

are now requiring a single, bulk monthly notification, which will include future estimated dates 

of anticipated well completions during that month. This notification will be followed by an

advance notice (via email if desired) to the state or delegated authority no sooner than 3 days and 

no later than 2 days prior to the actual commencement of each completion. The EPA is not 

limiting the monthly bulk report to a written format. The rule language is flexible so that 

electronic communication notification is allowed. We agree with the commenter that it is 

important for the EPA and States to coordinate their efforts as much as possible.

2.7.2 Third Party Verification

2.7.2.1 Potential Use for NSPS

Comment: One commenter (4240) states that, due to potential for conflict of interest, private 

verifiers must not displace government review and enforcement of NSPS requirements. The 

commenter opposes use of third-party verifiers absent a more definite proposal. The commenter 

states that if third party verifiers are used as a “clearinghouse,” any such clearinghouse should be 

fully available online, provide the public with full access to the collected data, and not substitute 

for government verification. The commenter disagrees with the EPA’s suggestion that with such 

a clearinghouse “notifications of well completions could be submitted with an advance period 

much less than 30 days that could make a 2-day follow-up notification unnecessary.” The 

commenter states the EPA has not explained how the clearinghouse would obviate the need for 

such advanced notification. The commenter believes that though notification through a 

clearinghouse might be more efficient than other methods, the role of advanced notification is to 
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enable states and the EPA to inspect well completions as they occur, and significant advanced 

notice is likely to facilitate scheduling of such inspections. The commenter does not believe an 

online clearinghouse would solve this scheduling problem. 

The commenter (4240) states that if the use of third party verifiers to inspect facilities in the field 

is limited to collection of unarguably objective data, such as the type of compressor installed, the 

commenter does not object. The commenter adds that they oppose using third party verifiers in 

any role until the EPA offers a more detailed proposal for public comment. The commenter 

states that “third party verification paid for by industry” presents a potential conflict of interest 

that can compromise the verification’s validity. The commenter suggests that if third party 

verifiers are used, any information they collect should be fully available to the public, 

comparable to information collected by the EPA. 

One commenter (4240) states that the EPA’s third party verification plans have not provided a 

coherent explanation as to the role these verifiers would play. The commenter believes that 

without a clear picture as to their roles, it is impossible to comment on the appropriateness of 

their use and objects to adoption of a third party verification system at this time. Another

commenter (4472) states that the same factors that make compliance assurance difficult and 

burdensome for State and the EPA permitting staff (such as geographically dispersed and remote 

locations) will make the use of third party verification costly to the regulated industry. The 

commenter also strongly disagrees with any EPA approved third party verifiers, believing this 

would likely result in added delays in drilling and production activities, with a resultant decrease 

in production.

Response: For the proposed rule, the EPA solicited comment on all aspects concerning the use 

of third party verification to assure compliance. Though the EPA believes that there are certain 

functions that third party verifiers could perform, we have decided not to move forward with the 

use of third party verification at this time until we can more fully explore the logistics of 

organizing and overseeing such a program for the oil and gas industry.

2.7.3 Provisions for Encouraging Innovative Technology

Comment: Two commenters (4192, 4246) believe that the EPA should exempt owners and 

operators from MACT subpart HH by reducing HAP emissions below an enforceable limit. The 

commenters believe this would be an innovative compliance approach and a win/win for both the 

EPA and industry. One commenter (4274) states that due to the controversy surrounding 

hydraulic fracturing, it would be beneficial to have as much transparency as possible to provide 

the public with straightforward information as shale extraction becomes a larger portion of our 

nation’s energy policy. The commenter states that citizens need to have information they can 

trust, to feel safe and comfortable with the measures used to extract these resources and 
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recommends that the EPA move forward with provisions for innovative compliance. One 

commenter (4356) requests clarification on whether innovative technology and compliance 

determinations will be delegated to States. The commenter also requests that the EPA encourage 

the use of new technologies that focus on recovery instead of destruction techniques that may 

result in collateral emissions and exacerbate existing nonattainment conditions. 

One commenter (4357) states the EPA should encourage innovative approaches to emissions 

monitoring and compliance with underlying regulations by creating incentives for sources to 

employ these new methods and technologies. The commenter suggests incentives such as 

including less reporting, simpler recordkeeping, and fewer on-site inspections. The commenter 

believes the final regulation must include “carrots” for the regulated entities to choose the newer, 

continuous, facility-wide monitoring needed to achieve continuous compliance and timely 

corrective actions when needed. Another commenter (4222) supports a regulatory framework 

that efficiently and economically reduces unwanted VOC emissions from oil and gas production. 

The commenter believes regulations should allow for innovative methods for emissions capture 

and flexible emissions disposal/use alternatives. 

One commenter (3454) describes an alternate method of containing and combusting methane and 

VOC emissions with very high efficiency that is currently in use. The commenter explains it 

involves introducing the normally vented VOC emissions, (without recompression), into the air 

intake of a carbureted reciprocating internal combustion engine (RICE) using natural gas fuel to 

combust VOC emissions as engine fuel. The commenter states the combustion efficiency of 

these engines is in excess of 99.5 percent for the combustion process. In addition, the commenter 

states these engines are equipped with non-selective catalytic converters, or oxidation catalysts, 

that are very effective in removing any remaining VOCs in the engine exhaust. 

One commenter (4375) supports a specific program to test new and innovative technologies in 

the oil and gas industry. The commenter states that innovation and experimentation comes with 

potential increases in pollution and environmental harm as technologies are explored and tested. 

The commenter states the program should establish criteria by which operators are allowed to 

test new technologies. The commenter states that the EPA should consider such factors as (1) 

company resources; (2) number/seriousness of environmental violations; (3) membership in 

Natural Gas STAR program; and (4) potential benefit of the new/innovative technology 

proposed. One commenter (4209) believes that to encourage innovative technology the EPA 

should not regulate the testing of new technologies or innovative exploration and production 

methods or techniques to minimize product loss and reduce environmental impacts as these 

isolated tests will have minimal impacts on human health and the environment and will not 

produce significant emissions warranting regulation.
173

One commenter (4228) supports provisions for encouraging innovative technology, including 

approaches that may be suitable for allowing temporary field testing of technology in 

development, and which may provide more efficient and cost-effective emission controls. The 

commenter states that an innovative technology demonstration project requires sufficient 

duration to adjust and evaluate technology parameters, and the project cannot be held to rule 

standards as it evaluates the operating envelope. The commenter recommends a minimum 6-

month duration for a demonstration project. In addition, the commenter states that exemption 

from rule standards is needed if the project is not successful or if standards are exceeded during 

parameter evaluations, malfunctions, or other events. The commenter adds that a potential barrier 

to the practical implementation of a demonstration project is timely Administrator approval for 

the project and exemption from rule standards during the demonstration. The commenter 

recommends inclusion of a provision that the EPA must respond to a request to conduct an 

innovative technology project within 30 days, and if a response is not provided within 30 days 

then the project is automatically approved.

Response: We thank the commenters for their comments and suggestions regarding innovative 

compliance approaches. While we considered these comments and suggestions, they have not 

been adopted for the final rule for various reasons. Some of these suggestions, however, may be 

useful for sources to consider in complying with the rule. We will continue to monitor and 

evaluate the use of innovative compliance options and new technologies.

2.7.4 Applicability of Title V Permitting Requirements to Non-major Sources

Comment: One commenter (4192) states that the EPA incorrectly asserts that compliance with 

the new subpart OOOO should reduce the number of NSR permits industry will have to obtain. 

The commenter states that a permit is required before construction can commence in their state 

and that subpart OOOO would lead to a very large increase in such permits, as industry would 

require an air permit before performing a routine operation such as completing a well or 

installing a pneumatic controller. One commenter (4209) states the proposed rule will require 

most if not all operators to obtain a state-issued minor source air permit for all or a significant 

number of wells in Oklahoma. The commenter states that the cost and burdens on operators as 

well as state air regulatory agencies are unnecessary and excessive. The commenter requests the 

EPA state in the final rule that NSPS/NESHAP applicability alone should not trigger minor 

source permitting requirements. 

One commenter (4214) states that in West Virginia if a minor source is subject to a substantive 

requirement of an emission control rule, such as a NSPS or NESHAP, then it must obtain a 

minor NSR permit even if it is otherwise exempt from permitting. The commenter states that, 

similarly, in some states, permitting agencies require a permit if a source is subject to a NSPS 

and/or NESHAP performance or work practice standard, even if such source is otherwise exempt 
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from permitting. One commenter (4230) disagrees with the EPA’s estimated reduction in the 

number of minor NSR permits. The commenter states their agency does not permit wellhead 

operations associated with REC activities and anticipates this will be a significant burden to its 

minor NSR permitting program and its Enforcement and Compliance Section to conduct 

inspections of these oil and gas operations. The commenter states their SIP-approved minor NSR 

permitting program rule requires permits for any substantive requirement and the controls 

required for wellheads, condensate storage vessels, and crude oil storage vessels in the EPA's 

proposed rule would be considered substantive.

One commenter (4176) is concerned about the direct impacts on governing agencies that would 

be responsible for implementing and administering these proposed regulations. The commenter 

believes state-specific impacts of a broadly applicable, indiscriminate national program should 

be evaluated to ensure the final rule does not preempt state implementation and compliance 

management of the same source categories. 

One commenter (4266) offers that many States have developed minor source NSR permitting 

programs that go far beyond the requirements of the Prevention of Significant Deterioration 

(PSD), New Source Review (NSR), or title V operating permitting programs. The commenter 

recognizes that the EPA has already stated that the proposed regulation will not trigger title V 

permitting requirements but recommends that the EPA expand this to include a recommendation 

in the preamble that NSPS/NESHAP applicability alone should not trigger minor source NSR 

permitting requirements. Two additional commenters (4209, 4228) reiterated this request. One 

commenter (4266) states that such a statement will not bind the States, but it will be helpful in 

addressing this issue with the States.

Response: We have made no changes to the proposed rule regarding our position on title V and 

other permitting applicability to major and minor sources. As stated in the preamble to the 

proposed rule, this rule does not change the federal requirements for determining whether oil and 

gas sources are major sources for purposes of nonattainment major NSR, PSD, CAA title V, or 

HAP major sources pursuant to CAA section 112. If an owner or operator is not currently 

required to get a major NSR or title V permit for oil and gas sources, including well completions, 

it would not be required to get a major NSR or title V permit as a result of these proposed 

standards. The requirements of the EPA-approved state and local major source permitting 

programs are not affected by this rulemaking. That is, state and local agencies with EPAapproved programs will still make case-by-case major source determinations for purposes of 

major NSR and title V, relying on the regulatory criteria, as explained in the McCarthy Memo21. 

 

21 “Memorandum from Gina McCarthy, Assistant Administrator, to Regional Administrators, Withdrawal of 

Source Determinations for Oil and Gas Industries (September 22, 2009). Available at 

http://www.epa.gov/region07/air/nsr/nsrmemos/oilgaswithdrawal.pdf
175

Consistent with the McCarthy Memo, whether or not a permitting authority should aggregate two 

or more pollutant-emitting activities into a single major stationary source for purposes of NSR 

and title V remains a case-by-case decision in which permitting authorities retain the authority to 

consider the factors relevant to the specific circumstances of the permitted activities. In addition, 

the proposed standards would not change the requirements for determining whether oil and gas 

sources are subject to minor NSR. 

Nor do the new standards affect existing EPA-approved state and local minor NSR rules, or the 

policies and practices implementing those rules. As noted, many state and local agencies have 

already adopted minor NSR permitting programs that provide for control of emissions from 

relatively small emission sources, including various pieces of equipment used in oil and gas 

fields. State and local agencies would be able to continue to use any EPA-approved General 

Permits, Permits by Rule, and other similar streamlining mechanisms to permit oil and gas 

sources such as wells. 

Regarding EO 13563, 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.

Regarding state permitting burden, as noted above, the final rule exempts area source affected 

facilities from title V permitting.

Comment: Several commenters (4192, 4209, 4214, 4219, 4220, 4228, 4320, 4230, 4261, 4263) 

support the title V exemption. The commenters believe the proposed rule will create increased 

burden with state permitting activity. One commenter (3477) urges the EPA to maintain its 

position in the final rule concerning applicability of other federal requirements. One commenter 

(3528) notes that the EPA previously stated that the rule would exempt well completions and 

other processes subject to NSPS from title V applicability if they are not major sources. A 

number of commenters (4159, 4184, 4236, 4261, 4273) support the EPA’s proposal not to 

impose title V permitting on non-major sources, as they believe this will be extremely costly and 

yield no environmental benefit. One commenter (4159) states that the EPA should exempt well 

completions from title V permitting requirements.

One commenter (4159) states that the EPA should exempt well completions from title V 

permitting requirements. One commenter (4222) states the definition in §60.5430 of "well site" 

in the proposed rule would result in a significant impact and add burden on the permitting 

agency, due to the need to identify all affected equipment and permit all newly-affected sources. 

 
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The commenter states that, under the proposed rule, every time a drill site is reworked, it would 

become an affected facility and title V permitted facilities would then have to add newly affected 

facilities to their title V permits every time.

Several commenters (4237, 4240, 4257) object to the proposed title V exemption. One 

commenter (4240) states that rather than treating the statutory exemption as a narrow limitation 

on a rule of general applicability adopted by Congress, the EPA seems to assume that the 

exemption is available as a matter of right, unless some added benefit can be demonstrated. The 

commenter states that the EPA has incorrectly interpreted the exemption as permitting it to 

balance the enforcement and environmental benefits of title V against the costs to the facility 

operator. The commenter states the EPA has understated the benefits of the title V program and 

overstated the burden on facility operators. 

One commenter (4237) states that title V exemptions should be revoked for non-major sources 

that fail to adequately follow the NSPS monitoring procedure. The commenter believes that 

though title V reporting requirements are somewhat burdensome, they may prove useful if the 

monitoring, recordkeeping and reporting obligations under the NSPS are not adequately met. 

One commenter (4257) states that the EPA improperly exempts new and modified oil and gas 

activities in the production sector from the requirement to obtain a title V permit. The commenter 

adds that the EPA needs to strengthen the proposed compliance mechanisms that apply in lieu of 

the compliance mechanisms required under title V. 

Response: Section 502(a) of the CAA states, in relevant part, that:

* * * [t]he Administrator may, in the Administrator's discretion and consistent with the 

applicable provisions of this chapter, promulgate regulations to exempt one or more source 

categories (in whole or in part) from the requirements of this subsection if the Administrator 

finds that compliance with such requirements is impracticable, infeasible, or unnecessarily 

burdensome on such categories, except that the Administrator may not exempt any major source 

from such regulations. See 42 U.S.C. section 7661a(a).

The statute plainly vests the Administrator with discretion to determine when it is appropriate to 

exempt non-major (e.g., area) sources of air pollution from the requirements of title V. In 

December 2005, in a national rulemaking, the EPA interpreted the term "unnecessarily 

burdensome" in CAA section 502 and developed a four-factor balancing test for determining, on 

case-by-case basis, whether title V is unnecessarily burdensome for a given source category, 

such that an exemption from title V is appropriate. See 70 FR 75320, December 19, 2005 

("Exemption Rule"). In addition to interpreting the term "unnecessarily burdensome" and 

developing the four-factor balancing test in the Exemption Rule, the EPA applied the test to 
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certain area source categories.22

The four factors that the EPA identified in the Exemption Rule for determining whether title V is 

unnecessarily burdensome on a given source category include: (1) Whether title V would result

in significant improvements to the compliance requirements, including monitoring, 

recordkeeping, and reporting, that are proposed for a source category (70 FR 75323); (2) whether 

title V permitting would impose significant burdens on the source category and whether the 

burdens would be aggravated by any difficulty the sources may have in obtaining assistance from 

permitting agencies (70 FR 75324); (3) whether the costs of title V permitting for the source 

category would be justified, taking into consideration any potential gains in compliance likely to 

occur for such sources (70 FR 75325); and (4) whether there are implementation and 

enforcement programs in place that are sufficient to assure compliance with the relevant 

standards without relying on title V permits (70 FR 75326).

In its comment opposing the EPA’s proposed title V exemption for the oil and gas NSPS nonmajor sources, a commenter challenges the EPA’s interpretation of the term "unnecessarily 

burdensome" in CAA section 502. Specifically, the commenter objects to the interpretation 

because they assert it permits the EPA “to balance the enforcement and environmental benefits 

of title V against the costs to the facility operator and completely ignores the role title V fees 

play in funding state enforcement programs.” 

To be clear, the EPA did not re-open its interpretation of the term "unnecessarily burdensome" in 

CAA section 502 in the August 23, 2011 proposed rule. Rather, we applied the four-factor 

balancing test articulated in the Exemption Rule to the NSPS non-major sources for which we 

proposed title V exemption. Had we sought to re-open our interpretation of the term 

"unnecessarily burdensome" in CAA section 502 and modify it from what was articulated in the 

Exemption Rule, we would have stated so in the August 23, 2010 proposed rule and solicited 

comments on a revised interpretation, which we did not do. Accordingly, we reject the 

commenter's attempt to re-examine our interpretation of the term "unnecessarily burdensome" 

under CAA section 502, as that issue falls outside the purview of this rulemaking.23

 

22 In the Exemption Rule, in addition to determining whether compliance with title V requirements would be 

unnecessarily burdensome for a given source category, we considered, consistent with the guidance provided by the 

legislative history of section 502(a), whether exempting the source category would adversely affect public health, 

welfare or the environment. See 72 FR 15254-15255, March 25, 2005. As discussed in the preamble to the proposed 

rule, after conducting the four-factor balancing test and determining that title V requirements would be 

unnecessarily burdensome on the oil and gas NSPS non-major sources, we examined whether the exemption from 

title V would adversely affect public health, welfare and the environment, and proposed that it would not.

23 If the commenter objected to our interpretation of the term "unnecessarily burdensome" in the Exemption Rule, it 

should have commented on, and challenged, that rule. Any challenge to the Exemption Rule is now time barred by 

CAA section 307(b). Although we received comments on the title V Exemption Rule during that rulemaking 

process, no one sought judicial review of that rule.
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Moreover, the addition of title V fees would not improve compliance requirements themselves. 

Even assuming, arguendo, the addition of title V fees would appropriately be considered under 

the EPA’s four factors, the EPA does not believe any potential improvement in compliance from 

title V fees would change the EPA’s assessment that, on balance, the factors weigh in favor of 

finding that title V is unnecessarily burdensome for these NSPS non-major sources. 

Furthermore, the EPA disagrees with the comment that “EPA’s application of the four factors in 

this instance would seem to allow it to exempt all sources.” As mentioned above, the EPA 

considers on a case-by-case basis in individual rulemaking whether to provide a title V 

exemption for a given source category. In the August 23, 2011 proposed rule, the EPA 

considered the extent to which one or more of the four factors supports title V exemption for the 

NSPS non-major sources and then we assessed whether those factors, considered together, 

demonstrate that compliance with title V requirements would be unnecessarily burdensome for 

these sources, consistent with section 502(a) of the CAA. As described in detail in the preamble 

to the proposed oil and gas rule, we considered a number of source-specific factors in 

determining whether to provide the exemption. In particular, we explained that, because well 

completions occur over a short period (generally 3 to 10 days) and the requirements for 

pneumatics can be met by simply installing the equipment that meets the emission limit, the type 

of monitoring and reporting generally required under title V may not significantly improve 

compliance with the NSPS. 76 FR 52752-52753.

In addition, we noted that many of the NSPS non-major sources may be small entities that may 

lack technical resources, and we expressed concern with their ability to get assistance from 

permitting authorities who may not have time to help due to the increases in permitting 

applications based on our estimates of the number of affected facilities subject to this NSPS. A 

number of commenters who support our proposed title V exemption similarly express concern 

with the burdens on the small entities as well as burdens on permitting authorities. After 

evaluating specific information regarding oil and gas NSPS non-major sources, such as the 

information described above, and based on the factors established in the exemption rule, we 

proposed that title V would be unnecessary burdensome for these non-major sources. 

The commenter appears to suggest that the EPA overstated the title V compliance cost by 

considering the estimated average title V permitting cost of $65,700 per source for a 5-year 

period.24 We first note that this was but one of several factors we considered in evaluating the 

 

24 The record concerning the 2007 and subsequent ICR-related actions for part 70 and 71 is publicly available under 

EPA docket numbers EPA-HQ-OAR-2004-0015 for part 70 and EPA-HQ-OAR-2004-0016 for part 71 on 

http://www.regulations.gov. Also, the supporting information for OMB-approved ICRs is publicly available on 

OMB’s public website: http://www.reginfo.gov/public/do/PRAMain.
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burden of title V permitting on oil and gas NSPS non-major sources. We also considered the 

number of sources estimated to have to obtain title V permits as a result of this rule, the need of 

small sources needing assistance and the ability to obtain such assistance. Furthermore, although 

the estimate is not specific to these oil and gas sources, it reflects the costs associated with 

certain activities under part 70 or part 71 rules that would be required for any source subject to 

title V permitting, and the title V cost estimates have been reviewed and approved by OMB in a 

separate action after public comment. It is therefore appropriate for the EPA to consider this cost 

in evaluating the burden of title V permitting on oil and gas NSPS non –major sources. On the 

contrary, we believe that the commenter underestimated the title V cost burden based on the 

minimum permit fee estimate for 2012 that is provided on the EPA website. The EPA noted that 

this estimates reflects the “minimum” permit fee because it is a simple emission-based estimate 

that does not reflect other charges that a state permitting authority may include in a permit fee. 

For instance, the minimum fee estimate would be an inaccurate representation of State title V 

programs that require non-emissions-based fees or a combination of emissions-based and nonemissions-based fees (such as application fees, service-based fees, etc., or a combination 

thereof). Also, even if a permitting authority uses emission- based fees, such as the presumptive 

minimum fee, the permitting authority typically requires facilities to include in the fee 

calculation many air pollutants, including those not covered by the rule triggering the title V 

requirement (in this case the oil and gas rule). The air pollutants generally required to be include 

in the fee calculation under a presumptive fee include: (1) Nitrogen oxides or any volatile 

organic compounds; (2) Any pollutant for which a NAAQS has been promulgated; (3) Any 

pollutant that is subject to a section 111 standard; (4) Any Class I or II substance subject to a 

standard promulgated under or established by title VI of the Act; or (5) Any pollutant subject to 

a section 112 standard or other requirement under section 112, including sections 112(g), (j), 

and (r) of the Act. (See §70.9(b)(2) and the definitions of "Regulated pollutant” and “Regulated 

pollutant (for presumptive fee calculation)" in §70.9.) For the reasons stated above, we do not 

believe that the minimum permit fee is an appropriate indicator of the title V cost burden. 

With respect to the comment on general permits, the EPA notes that general and standard permits 

are subject to the same permit content requirements, including recordkeeping, reporting, and 

monitoring requirements, under §§ 70.6 and 71.6. Therefore we expect that sources would have 

similar compliance costs under either type of permit, and that permitting authorities would have 

adequate oversight to assure compliance with either type of permit with respect to these oil and 

gas nonmajor NSPS sources. In light of the above, we conclude that title V is unnecessarily 

burdensome for NSPS compliance for the oil and gas non-major sources, whether they have a 

general or standard permit. However, we note that under section 504(d) of the CAA, issuing 

general permits to sources subject to title V is an option for State and local agencies; an EPA 

decision not to exempt these sources does not provide a means of ensuring that they would then 

receive general permits. 

 
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Lastly, we decline a commenter’s suggestion to require revocation of the title V exemption for 

non-major sources that fail to adequately follow the NSPS monitoring procedures. We have no 

reason to suspect non-compliance, considering many of the requirements reflect cost-saving 

measures that are already being implemented by the industry. Should this become an issue in the 

future, we would then need to evaluate the extent of noncompliance and whether and how it can 

be addressed through title V. Therefore, it is speculative and premature to anticipate future 

noncompliance and to address it in this rule with a title V exemption revocation provision.

2.7.5 Other Comments

Comment: One commenter (4221) states that the EPA must recognize that control of air 

pollution from the oil and gas sector, at least in the western U.S., is likely to involve the actions -

some regulatory some not - of several other Federal agencies. The commenter states that the 

preamble to the final rule should make it clear that the EPA recognizes this multi-agency 

network that will be in place to limit air pollution emissions from the oil and gas sector, and 

which must operate cooperatively if maximum emission reductions are to be achieved. The 

commenter adds there are additional means that Federal land management agencies may employ 

to reduce emissions from the oil and gas sector. The first of these, according to the commenter, is 

a requirement for project proponents to install a liquids gathering system (collection point) for 

large oil and gas fields. The commenter states this should be discussed or at least recognized in 

the preamble to the final rule. A second means, according to the commenter, is to regulate the 

pace of development in a field. 

Response: The EPA recognizes the importance of and promotes multi-agency cooperation in 

support of solutions to key environmental concerns.

Comment: One commenter (4257) states that the EPA’s proposal lacks the requisite safeguards 

needed to assure compliance. The commenter states that a rigorous self-certification requirement 

placing compliance responsibility on those in the best position to assure compliance, combined 

with stiff penalties for knowing false material statements, is necessary. The commenter states 

that a robust self-certification mechanism is necessary to assure compliance with the proposed 

standards due to the remote location and sheer number of affected sources; regulatory agencies 

will not be able to physically inspect or audit records from the thousands of new and modified 

facilities subject to the proposed standard each year. According to the commenter, a selfcertification requirement will not replace the need for annual reporting, but will reduce 

regulatory agencies’ need to rely solely on physical inspections or audits, thus reducing agency 

time, expense and burden. The commenter states this certification should include a certification 

of truth, accuracy and completeness. The commenter points to the regulations implementing title 

V as an example of a rigorous self-certification requirement. For accountability, the commenter 
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adds, this should include a certification by senior company officials. The commenter adds that 

these self-certification reports must be available to the public, as is similarly required under the 

CAA.

Response: We undertook a thorough analysis of the monitoring, recordkeeping and reporting 

requirements in the proposed rule. Based on that analysis, we have included in the final rule 

those provisions we believe necessary to assure regulatory agencies and the public that 

compliance is being achieved. We agree 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.

Comment: One commenter (4257) states that another way to provide the public with real-time, 

transparent information on facilities’ compliance with critical air quality standards is to leverage 

social media. The commenter notes that the EPA already uses several different forms of social 

media and technology applications, and the commenter encourages the Agency to consider how 

these social media tools may be helpful in facilitating robust, public disclosure of oil and gas 

well completions and re-completions. The commenter suggests the use of social media websites, 

smart phone applications, and QR codes. The commenter states that these and other social media 

tools may be particularly useful for rapidly disseminating data that the EPA will receive on gas 

well completion and recompletion activity. The commenter encourages the Agency to explore 

how these tools may be useful in promoting public transparency and accountability.

Response: We thank the commenter for their suggestions and will consider these options. As 

noted by the commenter, the EPA already utilizes social media tools to increase the potential for 

better understanding regarding environmental conditions and potential solutions.

2.8 Startup, Shutdown and Malfunction Provisions

Comment: One commenter (4104) asserts that the EPA’s proposed approach does not comport 

with the CAA and risks depriving industry of their due process rights. Two commenters (4104, 

4219) state that the CAA requires that the EPA establish emission limits that are “achievable” 

through the application of BSER. The commenters assert that the limitations based on BSER 

must be achievable by the technology that the EPA has designated as BSER. The commenters 

opine that the EPA may accomplish the goal of meeting BSER in one of two ways to address 

periods of SSM: 

• First, it may set emission standards sufficiently high so that all facilities using BSER 

can achieve the standard at all times, including during SSM periods.
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• Alternatively, the EPA may set emission standards at some more rigorous level, and 

then provide an exemption for the other 1-2 percent of the time when even wellmanaged BSER technology will not be able to comply. 

The commenters (4104, 4219) believe that the EPA’s failure to provide such an exemption 

violates the CAA language and industries’ constitutional rights to due process, by subjecting the 

affected industries to penalties, and even incarceration, for (i) failing to comply with an 

unattainable standard; and (ii) engaging in conduct that the CAA expressly makes legal. 

One commenter (4104) provides the following case law to support their position. See Portland 

Cement Assoc. v. Ruckelshaus, 486 F.2d 375, 402 (D.C. Cir. 1973) (“the [Clean Air Act] 

expressly requires, for the standards [the Administrator] promulgates, that technology be 

achievable”); Marathon Oil Co. v. EPA, 564 Fed.2d 1253, 1272-73 (9th Cir. 1977) (remanding 

permits to the EPA because they required permittees to meet the standards 100 percent of the 

time but the permittees could only be expected to achieve the standards 97.5 percent to 99

percent of the time with the best practicable control technology currently available); FMC Corp. 

v. Train, 539 F.2d 973, 986 (4th Cir 1976) (remanding effluent limitations to the EPA because a 

properly operating treatment facility could be in violation of those limitations on a few 

occasions). The commenter asserts that a law that requires an individual to do the impossible 

leaves an individual no choice but to violate the law; because individuals must be given the 

opportunity to conform their conduct to the law, such a law violates due process. See Grayned v. 

City of Rockford, 408 U.S. 104, 108 (1972) (vague laws violate due process in part because they 

fail to provide individuals a choice of whether to obey); Portland Cement Ass’n v. Ruckelshaus, 

468 F.2d 375, 398 n.91 (D.C. Cir. 1973) (“Companies must be on notice as to what will 

constitute a violation.”); United States v. Dalton, 960 F.2d 121. 122-23 (10th Cir. 1992) 

(individual cannot be convicted for having unregistered machine gun when there is no available 

mechanism for registering machine guns). Furthermore, according to the commenter, subjecting 

affected sources to sanctions for doing that which the CAA expressly makes legal – continuing 

to operate their facilities using properly-managed BSER-level controls – would also violate due 

process. “To punish a person because he has done what the law plainly allows him to do is a due 

process violation of the most basic sort.” United States v. Goodwin, 457 U.S. 368, 372 (1982) 

(internal quotations omitted).

One commenter (4219) requests that the EPA either set the emission limits at levels that can be 

met even during periods of SSM, or allow for an exemption to cover situations in which properly 

operated equipment failed to meet those limits during periods of SSM.

One commenter (4228) asserts that the affirmative defense provisions in the proposed rule 

should be deleted and appropriate exemptions from rule standards should be added that account 

for operating periods when even well managed BSER control technology would not provide 

compliance. 
183

Response: The EPA disagrees with commenters that state that the EPA’s proposed approach of 

not providing an exemption for the 1-2 percent of the time when even well-managed BSER 

technology will not be able to comply does not comport with the CAA and deprives industry of 

their due process rights. Neither the statute nor the case law support this position and the Sierra 

Club decision on this very issue makes commenters’ arguments highly suspect. Under section 

112, 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”); Sierra Club v. EPA, 551 F.3d 1019, 1021 (D.C. Cir. 2008) 

(emissions limitations under CAA section 112 must both continuously apply and meet section 

112’s minimum stringency requirements, even during periods of SSM). Under section 111, EPA 

must promulgate a “standard of performance” which also requires a continuous system of 

emissions reduction. See 42 U.S.C. §§ 7411(a)(1), (7), 7602(l) (defining “standard of 

performance” to mean “a requirement of continuous emission reduction, including any 

requirement relating to the operation or maintenance of a source to assure continuous emission 

reduction.”). Thus, the EPA is required to ensure that section 111 emissions standards (in 

addition to 112 standards) are continuous.

With respect to periods of startup and shutdown, the EPA agrees that in some circumstances 

separate standards for such periods may be appropriate. However as explained in the preamble of 

the proposed rule, “the EPA has taken into account startup and shutdown periods and expects 

that sources will be able to meet emission limits during such periods. We believe that operations 

and emissions do not differ from normal operations during these periods such that it warrants a 

separate standard.” 76 FR 52738, 52787 (Aug. 23, 2011) The control devices employed in most 

cases are vapor recovery units (VRU) or enclosed combustion devices. The startup or shutdown 

of the process unit, which is the source of the emissions, should not affect the performance of the 

control device, and therefore does not require a separate standard for startup and shutdown 

events. Further, startup and shutdown of the control device should not be an issue. For a VRU 

the devices will perform at the necessary level immediately upon startup. Enclosed combustion 

devices are typically units that receive gas from the process units and combust the gas 

immediately when it contacts the pilot flame. Such control devices are either on (i.e., the pilot is 

lit) or off. In the case where a catalytic thermal oxidizer is used as the enclosed combustion 

device, we believe the 24-hr averaging time is sufficient to allow compliance with the standards 

and we have addressed this in more detail elsewhere in this document. Thus, we do not believe 

that different standards are required for periods of startup or shutdown. In addition, no 

commenter provided enough specificity in their comments or emissions data that established the 

need for an alternate standard during startup and shutdown. 

For malfunctions, the EPA recognizes that even equipment that is properly designed and 

maintained can sometimes fail and that such failure can cause a violation of an emission 
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standard. Therefore, the EPA is finalizing an affirmative defense to civil penalties for violations 

of emission standards that are caused by malfunctions as we have in other recent section 111, 

section 112 and section 129 rules in an attempt to balance the 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 affirmative defense for malfunction events meets 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 Association 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 undermine 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 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. United States 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 1011, 1057-58 (D.C. Cir. 1978) 

(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.

The EPA does not agree that failure to provide an exemption violates due process. The 

commenter cites to cases addressing vague laws, yet does not explain or even argue that the 

standards are vague. Further, as the EPA explains above, the EPA’s approach to malfunction 

events is consistent with Portland Cement. United States v. Dalton addressed an argument that 

compliance was a legal impossibility and is thus distinguishable from the commenter’s argument 

that it may be technologically infeasible to comply with standards at certain times. The EPA’s 

approach for handling such circumstances is explained at length in the preamble and elsewhere 

in this response to comment document and is reasonable. In any enforcement action, sources that 
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truly could not have complied with the standard despite best efforts will have an opportunity to 

assert an affirmative defense to penalties, and such opportunity provides due process. In addition, 

if penalty assessment occurs, the EPA and courts consider good faith efforts to comply in 

assessing penalties under section 113(e) of the CAA.

Comment: One commenter (4266) states that EPA’s proposal fails to provide record evidence as 

to how it has “taken into account startup and shutdown periods.” The commenter states that the 

EPA’s assertion that it has taken into account startup and shutdown periods is therefore 

unsupported and fundamentally arbitrary. According to the commenter, the EPA further 

undermines its position by asserting that “any comments that contend that sources cannot meet 

the proposed standard during startup and shutdown periods should provide data and other 

specifics supporting their claim.” The commenter asserts that the EPA unambiguously has the 

obligation to support its proposed standards with substantial evidence and must include in the 

proposed rule “the factual data on which the proposed rule is based.” CAA § 307(d)(3)(A). 

Response: As noted in the proposal preamble, we took into account startup and shutdown 

periods. 76 FR 52738, 52787 (Aug. 23, 2011) We believe that the expected startup and shutdown 

emissions established for the NSPS are not likely to cause a violation of the standards because of 

the processes regulated, the emission control methods typically employed and the format of the 

proposed standards. 

For storage vessels VOC emissions are generally controlled by a VRU or enclosed combustion 

device. The startup or shutdown of the process unit, which is the source of the emissions, should 

not affect the performance of the control device, and therefore does not require a separate 

standard for startup and shutdown events. Further, startup and shutdown of the control device 

should not be an issue. For a VRU the devices will perform at the necessary level immediately 

upon startup. Enclosed combustion devices are typically units that receive gas from the process 

units and combust the gas immediately when it contacts the pilot flame. Such control devices are 

either on (i.e., the pilot is lit) or off. In the case where a catalytic thermal oxidizer is used as the 

enclosed combustion device, we believe the 24-hr averaging time is sufficient to allow 

compliance with the standards. Thus, we do not believe that different standards are required for 

periods of startup or shutdown. In addition, no commenter provided enough specificity in their 

comments or emissions data that established the need for an alternate standard during startup and 

shutdown.

The EPA has no evidence that suggests that emissions are higher during startup or shutdown that 

would indicate a need for an alternate standard for these periods and the commenter provided no 

data or basis to show that sources cannot comply with the standards as proposed. Thus, we set 

standards based on available information as contemplated by section 111. 
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Comment: One commenter (4242) supports the EPA’s requirement for natural gas processing 

plants to comply with the proposed NSPS at all times. The commenter (4242) reports that a 

significant percentage of emissions from natural gas processing plants occur during SSM events. 

This commenter provides the results of an analysis they conducted of emission events and 

emissions inventory data in Texas and states their analysis indicates that SSM emissions have the 

potential to exceed the total amount of compliance emissions reported to the state’s inventory for 

the same year. The commenter provides the following examples:

• The Goldsmith Gas plant in Ector County reported 999.98 tons of sulfur dioxide to 

the emissions inventory for 2009. This report is supposed to reflect total emissions 

from all causes (i.e., from both normal operations and SSM events) for the entire 

year. But the Goldsmith plant separately reported just of 1,000 tons of SO2 emissions 

from multiple SSM episodes in 2009, according to a separate “emission events” data 

base maintained by TCEQ.

• The East Vealmoor Gas plant reported over 500 tons of SO2 emissions from multiple 

SSM events in 2009; but only 22 tons to the Emissions Inventory.

• The Big Lake Gas Plant reported 380 tons of SO2 emissions from SSM events so far 

in 2011, or more than the total annual emissions it reported to the EI in 2008.

Eight commenters (4104, 4174, 4192, 4218, 4245, 4246, 4266, 4273) opine that the EPA should 

maintain the SSM exemption in subpart OOOO. 

One commenter (4219) asserts that the EPA has not provided adequate justification for not 

providing an SSM exemption in the current rule. 

Another commenter (4218) states that the EPA has not explained what is different about the oil 

and gas sector that justifies not including the general SSM exemption that most other industries 

have under the NSPS. 

Four commenters (4104, 4192, 4266, 4273) state that the EPA is not legally required to not 

include the SSM exemption in subpart OOOO and that the Sierra Club v. EPA decision applies 

only to MACT standards.

One commenter (4104) states that the Court’s decision in Sierra Club v. EPA was in large part 

based on the more limited flexibility granted to the EPA under section 112 than had been 

provided under section 111. See 551 F.3d at 1022. The commenter also asserts that, under the 

part 63 General Provisions, the EPA generally exempted facilities from complying with MACT 

standards during SSM events; during these periods, facilities were instead required to comply 

with the general duty to operate using “good air pollution control practices.” 40 CFR. §§63.6(e)-

(h). According to the commenter, the Court held that the CAA requires “continuous section 112-
187

compliant standards”; the “general duty” that applied during SSM events did not qualify as either 

a section 112(d)-compliant MACT standard or a section 112(h)-compliant alternate standard. 551 

F.3d at 1028-29. Accordingly, the commenter believes that the Court voided the EPA’s reliance 

on the “general duty” under §63.6(e) to control emissions during SSM events. 

The commenter (4273) asserts that the EPA states that it is “reasonable to interpret CAA section 

111 as not requiring the EPA to account for malfunctions in setting emission standards” but 

provides no basis for this conclusion, merely citing to the definition of “standard of 

performance” and referencing only the EPA’s determination that the system of emission 

reduction be adequately demonstrated. 76 Fed. Reg. 52,766. The commenter states that the case 

law that the EPA included in the proposal preamble was applicable to section 112 and not section 

111 standards and no one has successfully challenged the longstanding NSPS SSM provisions.

One commenter (4192) states that the NSPS provisions of the CAA could reasonably be 

interpreted to allow an exemption for SSM.

Two commenters (4192, 4246) recommend the following revision to the proposed NSPS 

amendments:

40 CFR 60.5370(b) currently reads: 

The provisions for exemption from compliance during periods of startup, shutdown, and 

malfunction provided in 40 CFR 60.8(c) do not apply to this subpart.

40 CFR 60.5370(b) recommended edit: 

The provisions for exemption from compliance during periods of startup, shutdown, and 

malfunction provided in 40 CFR 60.8(c) do apply to this subpart.

Response: The EPA appreciates the support of the commenter that agrees with the EPA’s 

proposal that natural gas processing plants comply with the NSPS at all times.

As for commenters that believe that Sierra Club v. EPA only applies to section 112 standards, we 

disagree. The EPA believes the reasoning in the D.C. Circuit’s decision in Sierra Club v. EPA

applies equally to section 111. The EPA’s proposed approach to SSM periods has been used 

consistently in CAA section 112, CAA section 111, and CAA section 129 rulemaking actions 

since the D.C. Circuit’s decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008) vacated 

the SSM exemption contained in CFR 63.6(f)(1) and 40 CFR 63.6(h)(1). (See, e.g., National 

Emission Standards for Hazardous Air Pollutants From the Portland Cement Manufacturing 

Industry and Standards of Performance for Portland Cement Plants, 75 FR 54970 (September 9,

2010); Standards of Performance for New Stationary Sources and Emission Guidelines for 

Existing Sources: Sewage Sludge Incineration Units; Final Rule, 76 FR 15372 (March 21, 2011); 

National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-fired Electric 
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Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric 

Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional 

Steam Generating Units; Final Rule,77 FR 9304 (February 16, 2012).

In response to the commenter that states that the court vacated the SSM provisions because they 

were based on the “general duty” clause rather than a continuously applicable section 112 

standard, the EPA agrees that the court found that the “general duty” was not a 112-compliant 

standard. The EPA does not claim that the Sierra Club case constrains its authority to prescribe 

different standards for periods of startup and shutdown or for periods of malfunction. However, 

as explained in the preamble to the proposed and final rules, the EPA has determined that CAA 

section 112 does not require that emissions that occur during periods of malfunction be factored 

into development of CAA section 112 standards. The EPA’s rationale for this view is explained 

in detail in the preambles as well. 

As for the commenter that states that the NSPS provisions of the CAA could reasonably be 

interpreted to allow an exemption for SSM, we disagree. The commenter did not provide 

justification for their position and the EPA believes that the Sierra Club v. EPA decision equally 

applies to section 111 and section 112 standards and there is nothing in the NSPS provisions of 

the CAA that would lead the EPA to treat SSM events differently. 

We also disagree with the commenter that recommends that the EPA leave the regulation of 

SSM emissions to the respective State agencies. States may seek to have equivalent or more 

stringent requirements apply in lieu of the Federal requirements but the EPA maintains its 

authority to set the minimum requirements that need to be enforced nationally. Therefore, for the 

reasons provided above, we have maintained the proposed §60.5370(b) regulatory text stating 

that the “provisions for exemption from compliance during periods of startup, shutdown, and 

malfunction provided in §60.8(c) do not apply...” in the final rule.

Comment: One commenter (4266) states that, under an NSPS, the EPA is obliged to show that 

covering SSM periods within the NSPS is cost effective. The commenter asserts that the CAA 

does not contain any provision that allows the EPA to ignore cost-effectiveness when setting 

NSPS and SSM events are no different. The commenter further states that the EPA has failed to 

estimate and take into account the added costs associated with a rule that requires compliance 

during malfunctions (i.e., the costs of installing redundant equipment or the business interruption 

costs of shutting down). According to the commenter, if the EPA continues to impose the NSPS 

at all times (including during SSM periods), the EPA must identify SSM events, the controls 

required to maintain the emission standard and justify the cost impact of including the emission 

standard during the SSM event.
189

Another commenter (4242) believes that any cost/benefit analysis should take into account the 

ripple effects of SSM events at gas plants. For example, according to the commenter, a single 

“emission event” at the Goldsmith Gas Plant caused a total of 195 tons of SO2 to be released at 

tank batteries connected to the plant. (The commenter refers to Exhibit 3 of their comment letter 

for documentation of the subject event.) The commenter believes that it is critical for the EPA to 

properly evaluate the benefits of technology in their cost/benefit analysis that can reduce the 

frequency of and severity of SSM events that trigger shutdowns and flaring at satellite units.

Response: The EPA disagrees with both commenters. The EPA’s rationale for its approach to 

SSM events is discussed in the preamble to the proposed rule and this final action. As explained 

in the preamble, the EPA has determined that section 111(a)(1) of the CAA provides that NSPS 

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 non-air quality health and environmental impact and energy requirements) the Administrator 

determines has been adequately demonstrated.” This level of control is commonly referred to as 

best demonstrated technology (BDT) or the best system of emission reduction (BSER). Costs are 

also considered in evaluating the NSPS. The EPA generally compares control options and 

estimated costs and emission impacts of multiple, specific emission standard options under 

consideration. As part of this analysis, the EPA considers numerous factors relating to the 

potential cost of the regulation, including industry organization and market structure; control 

options available to reduce emissions of the regulated pollutant(s); and costs of these controls. 

The commenters do not provide evidence that the NSPS fails to meet this statutory requirement. 

Additionally, commenters have not shown how the EPA is obligated, under the statute, to 

specifically account for SSM events when setting an NSPS, including any statutory mandate that 

the EPA specifically account for the cost-effectiveness or benefits of technology in their 

cost/benefit analyses of SSM events when setting NSPS. 

CAA section 111 does not require that emissions that occur during periods of malfunction be 

factored into development of CAA section 111 standards. This equates to the commenter asking 

that the EPA determine the likelihood, frequency, duration, and nature of a failure at the facility 

when setting the standard, and then estimating and considering the cost impacts of that failure 

when setting the NSPS. Such an approach is not required under section 111. 

As for startup and shutdown periods, as discussed previously in this section, for storage vessels, 

VOC emissions are generally controlled by a VRU or enclosed combustion device. The startup 

or shutdown of the process unit, which is the source of the emissions, should not affect the 

performance of the control device, and therefore does not require a separate standard for startup 

and shutdown events. Further, startup and shutdown of the control device should not be an issue. 

For a VRU the devices will perform at the necessary level immediately upon startup. Enclosed 

combustion devices are typically units that receive gas from the process units and combust the 
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gas immediately when it contacts the pilot flame. Such control devices are either on (i.e., the 

pilot is lit) or off. In the case where a catalytic thermal oxidizer is used as the enclosed 

combustion device, we believe the 24-hr averaging time is sufficient to allow compliance with 

the standards and we have addressed this in more detail elsewhere in this document. Thus, we do 

not believe that different standards are required for periods of startup or shutdown. In addition, 

no commenter provided enough specificity in their comments or emissions data that established 

the need for an alternate standard during startup and shutdown.

Ultimately the decision of how to comply with the applicable standards, and plan for 

contingencies, lies with the source owner and operator.

Comment: One commenter (3469) recommends that the EPA follow the SSM approach that is 

used in the final NESHAP for Major Sources: Industrial, Commercial, and Institutional Boilers 

and Process Heaters (ICI Boiler MACT); namely, that work practice standards apply during 

periods of startup and shutdown to minimize air pollution emissions, while malfunctions would 

not be considered a distinct operating mode. The commenter states that, in the ICI Boiler rule, 

the EPA determined that it is not technically feasible to monitor these periods of startup and 

shutdown and therefore established separate work practice standards for periods of startup and 

shutdown. Additionally, the commenter states that, in the ICI Boiler rule, the EPA requires 

operators to follow manufacturers' specifications for minimizing periods of startup and 

shutdown. Specifically, §63.7530(h) requires that owners/operators of covered ICI boilers 

"minimize the unit's startup and shutdown periods following the manufacturer's recommended 

procedures, if available. The commenter provides that, if manufacturer's recommended 

procedures are not available, the recommended procedures for a unit of similar design for which 

manufacturer's recommended procedures are available must be followed. The commenter reports 

that a signed statement in the Notification of Compliance Status report would be included that 

indicates startups and shutdowns were conducted according to the manufacturer's recommended 

procedures or procedures specified for a unit of similar design if manufacturer's recommended 

procedures are not available." The commenter believes a similar approach, which requires an 

affected piece of equipment to minimize periods of startup and shutdown and associated 

emissions is appropriate for oil and gas equipment.

Response: The EPA, based upon a comprehensive review of the emission units affected by this 

NSPS, has determined that there is no demonstrated need for alternate standards during startup 

and shutdown and expects that sources will be able to meet the emission limits during such 

periods. In comparison, in the major source ICI Boiler rule, the EPA determined that it was not 

practicable to apply measurement methodology due to technological and economic limitations 

during periods of startup and shutdown and, therefore, established separate work practice 

standards for these periods. The operation of boilers falling under the major source ICI Boiler 

rule is not analogous to that of storage vessels within the oil and natural gas NSPS. Boilers are 
191

designed to combust various fuels and in doing so they destroy organic HAP and VOC. In fact, 

boilers are commonly used as control devices to reduce organic HAP and VOC. In contrast, 

storage vessels do not reduce VOC, they merely emit VOC, and, in most cases, an add-on control 

device is required to meet the VOC emission standard under the oil and natural gas NSPS. The 

control devices employed in most cases are VRU or enclosed combustion devices. The startup or 

shutdown concern is not with the process unit (i.e., storage vessels) but with the control device. 

VRUs will perform at the necessary level when operating and we are not aware of any periods 

that can be classified as startup or shutdown for these devices. Enclosed combustion devices are 

typically units that receive gas from the process units and combust the gas immediately when it 

contacts the pilot flame. Such devices are either on (i.e., the pilot is lit) or off. In the case where a 

catalytic thermal oxidizer is used as the enclosed combustion device, we believe the 24-hr 

averaging time is sufficient to allow compliance with the standards and we have addressed this in 

more detail elsewhere in this document. There should not be any periods of non-operation for 

any of these control devices where the limits cannot be met that we consider being startup or 

shutdown activities. In addition, no commenter provided enough specificity in their comments or 

emission data that established the need for an alternate standard during startup and shutdown.

Comment: Four commenters (4159, 4220, 4266, 4273) assert that the EPA has not shown that 

emission standards are achievable during malfunction periods. 

Three commenters (4159, 4266, 4273) report that the support for the EPA’s proposed rules does 

not contain data on emissions during malfunctions and has not shown that the standards can be 

achieved during such periods. 

Four commenters (4159, 4220, 4266, 4273) do not agree with the EPA’s decision to apply a 

standard for normal operating periods to periods of malfunctions because it would find it difficult 

to develop a standard for such events. One commenter (4192) opines that it is impractical to 

impose a performance standard on malfunctioning equipment.

Two commenters (4192, 4246) state that certain control devices (such as flares) are not capable 

of meeting NSPS during upsets or malfunctions, and could not be feasibly modified to do so. The 

commenters report that most existing flares subject to 40 CFR part 60, subpart OOOO that are 

compliant with either 40 CFR 60.18 or State construction permit requirements will not be able to 

meet the new standard during upsets when a new tank is added to the site. One commenter 

(4266) acknowledges (as the EPA has) that it is not feasible to develop an emission standard that 

governs malfunction periods. The commenter provides that section 112(h) of the CAA allows the 

EPA to set work practice standards for situations where “it is not feasible in the judgment of the 

Administrator to prescribe or enforce an emission standard . . .” The commenter states that 

malfunctions fit within the situations described in the definition of “not feasible to prescribe or 

enforce an emission standard” as any situation where “the application of measurement 
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methodology to a particular class of sources is not practicable due to technological and economic 

limitations.” Consequently, the commenter recommends that the EPA set work practice 

requirements to address periods of malfunction. The commenter believes that the steps set forth 

in §60.5415(h)(1)(i)-(ix) would constitute an appropriate work practice standard for 

malfunctions, in which case (according to the commenter) the notifications specified in 

§60.5415(h)(2) should be replaced by a semi-annual reporting requirement. 

Commenter 4266 disputes the EPA’s case law support and provides their own case law support 

for why the EPA is both authorized and obligated to account for periods of malfunction when 

setting part 60 standards. The commenter states that the EPA begins its analysis by asserting that 

it “has determined that malfunctions should not be viewed as a distinct operating mode and, 

therefore, any emissions that occur at such times do not need to be factored into development of 

CAA section 111 standards.” 76 Fed. Reg. at 72766. According to the commenter, in support of 

this assertion, the EPA first cites Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) 

for the proposition that “nothing in CAA section 111 or in case law requires that the EPA 

anticipate and account for the innumerable types of potential malfunction events in setting 

emission standards.” 76 FR at 52766.

The commenter (4266) believes that Weyerhaeuser is inapposite – it is a Clean Water Act case 

that has no bearing on the EPA’s authorities and responsibilities under CAA section 111. 

According to the commenter, more directly relevant cases – those decided under section 111 

itself – tell a very different story. The commenter states that, as explained in the SSM Coalition’s 

comments (Attachment D to their comment letter), the courts have long recognized that a 

“technology based standard discards its fundamental premise when it ignores the limits inherent 

in technology.” NRDC v. EPA, 859 F.2d 156, 208 (D.C. Cir. 1988). For example, according to 

the commenter, the D.C. Circuit recognized, in Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 

375, 398 (D.C. Cir. 1973), a decision reviewing standards under CAA section 111, that “‘startup’ and ‘upset’ conditions due to plant or emission device malfunction, is an inescapable aspect 

of industrial life and that allowance must be made for such factors in the standards that are 

promulgated.” Id. at 399. Similarly, the commenter opines that, in Essex Chem. Corp. v. 

Ruckelshaus, 486 F.2d 427, 432 (D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974), another 

section 111 case, the court held that SSM provisions are “necessary to preserve the 

reasonableness of the standards as a whole.” Id. at 433. The commenter states that, in National 

Lime Ass’n v. EPA, 627 F.2d 416 (D.C. Cir. 1980), another case reviewing emission standards 

promulgated under CAA section 111, the court held CAA technology-based standards must be 

capable of being met “under most adverse circumstances which can reasonably be expected to 

recur,” such as during periods of SSM. 627 F.2d at 431 n.46. Thus, according to the commenter, 

the relevant case law makes clear that the EPA is authorized and obligated to account for periods 

of malfunction when setting part 60 standards. 
193

Nevertheless, the commenter (4266) argues that the EPA presses on by arguing that “it is 

reasonable to interpret CAA section 111 as not requiring the EPA to account for malfunctions in 

setting emissions standards” because “[t]he ‘‘application of the best system of emission 

reduction’’ is more appropriately understood to include operating units in such a way as to avoid 

malfunctions.” 76 FR at 52766. The commenter opines that this rationale makes no sense 

because the EPA effectively is defining BDT as an affected facility that does not malfunction. 

The commenter asserts that the EPA has asserted no record basis for such a determination and 

could not if it tried because malfunctions are inevitable, notwithstanding best efforts. In any 

event, the commenter believes that the EPA has failed to estimate and take account of the added 

costs associated with a rule that requires compliance during malfunctions (i.e., the costs of 

installing redundant equipment or the business interruption costs of shutting down). 

According to the commenter (4266), the EPA lastly asserts that “even if malfunctions were 

considered a distinct operating mode, we believe it would be impracticable to take malfunctions 

into account in setting CAA section 111 standards for affected facilities” because “it would be 

difficult to set a standard that takes into account the myriad different types of malfunctions that 

can occur across all sources in the category.” Id. The commenter argues that four decades of 

operating under the existing part 60 malfunction provision belie this claim. The commenter 

opines that a work practice requiring best efforts to minimize emissions during malfunction 

events consistent with the application of good air pollution control practices is a tried and true 

way to “account for the myriad different types of malfunctions that can occur.” According to the 

commenter, the EPA’s failure to explain why such an approach cannot continue to be 

successfully applied represents a critical flaw in its conclusion that standards cannot and should 

not be developed for malfunction events.

Response: For malfunctions, the EPA is finalizing the proposed affirmative defense language for 

exceedances of the standards that are caused by malfunctions with minor revisions discussed 

elsewhere in this section. As the EPA explained in the preamble to the proposed rule and final 

rule, the EPA recognizes that even equipment that is properly designed and maintained can fail 

and that such failure can cause an exceedance of the relevant emission standard. The EPA is 

including an affirmative defense in the final rule as we have in other recent section 111, 112 and 

section 129 rules so as to balance the tension, inherent in many types of air regulation, to ensure 

adequate compliance while simultaneously recognizing that despite the most diligent of efforts, 

emission limits may be exceeded under circumstances beyond the control of the source. Under 

section 112, 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”); Sierra Club v. EPA, 551 F.3d 1019, 

1021 (D.C. Cir. 2008) (emissions limitations under CAA section 112 must both continuously 

apply and meet section 112’s minimum stringency requirements, even during periods of SSM).

Under section 111, EPA must promulgate a “standard of performance” which also requires a 
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continuous system of emissions reduction. See 42 U.S.C. §§ 7411(a)(1), (7), 7602(l) (defining 

“standard of performance” to mean “a requirement of continuous emission reduction, including 

any requirement relating to the operation or maintenance of a source to assure continuous 

emission reduction.”). Thus, the EPA is required to ensure that section 111 and 112 emissions 

limitations are continuous. The affirmative defense for malfunction events meets this 

requirement by ensuring that even where there is a malfunction, the emission limitation is still 

enforceable through injunctive relief. While “continuous” limitations, on the one hand, are 

required, there is also case law indicating that in some 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 Association 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 calls 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 excess emissions 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 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. United States 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 1011, 1057-58 (D.C. Cir. 1978) (holding that an 

informal approach is adequate). The affirmative defense provisions give the EPA the flexibility 

to both ensure that its emission limitations 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. 

As noted above and discussed in the preamble, the relevance of the cases such as Portland 

Cement is called into question in light of subsequent case law and the 1977 amendments to the 

Clean Air Act’s definition of emission standard requiring that such standards be continuous. In 

any event, even if those cases are relevant, as also explained in the preamble to the final rule, the 

EPA‘s overall approach to malfunction events in this rule, including the promulgation of an 

affirmative defense, is consistent with the approach set forth in EPA‘s 1972 proposed rules cited 

favorably in Portland Cement in that both EPA’s approach today and in 1972 ―impart a 

construction of "reasonableness" to the standards as a whole and adopts a more flexible system 

of regulation than can be had by a system devoid of "give." Portland Cement at 399. Portland 

Cement criticized the EPA regulations that contained no specific provisions to address 

malfunctions and the EPA‘s assertion that malfunctions would be dealt with by the informal 
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exercise of discretion in the Agency‘s enforcement activities. Those decisions did not require 

exemptions or less stringent standards for malfunction events as the commenter suggests. The 

EPA‘s approach to malfunctions goes further than reliance on the informal exercise of 

enforcement discretion in that it includes regulatory provisions establishing an affirmative 

defense to civil penalties for exceedances of emission limits that are caused by malfunctions. 

The EPA acknowledges that certain control devices (such as flares) may not be capable of 

meeting the NSPS during upsets or malfunctions, and may not be feasibly modified to do so. 

However, the EPA believes that the standards adopted are flexible enough to allow at least some 

variability without causing a violation of the standard. In cases where a violation has occurred, 

an owner or operator of a source may choose to assert an affirmative defense. 

Comment: One commenter (4192) reports that, in Table 3, §60.11 “compliance with standards 

and maintenance requirements” is shown as not applicable to this subpart. The commenter 

requests that the EPA modify Table 3 of the rule to make §60.11(c) applicable to subpart OOOO. 

According to the commenter, the NSPS subpart A contains an exemption for opacity during 

upsets in §60.11(c), that states: “The opacity standards set forth in this part shall apply at all 

times except during periods of startup, shutdown, malfunction, and as otherwise provided in the 

applicable standard.” The commenter states that many flares that are currently in use are not 

capable of meeting opacity standards during upsets. The commenter opines that, with the 

elimination of the SSM exemption, each opacity exceedance during plant or station upsets and 

malfunctions will need to be reported and will require an affirmative defense. The commenter 

states that, without an exemption, there will be a need for new paperwork that they lack the 

resources to complete.

Response: Flares are subject to applicable standards at all times the source is operating and 

therefore the exception in §60.11(c) to meeting the opacity standards other than periods of SSM 

cannot be provided. Under the subpart OOOO standards, flares are to be designed for and 

operated with no visible emissions, except for periods not to exceed a total of 2 minutes during 

any hour. Owners and operators should have procedures in place to shut down operations or to 

re-route emissions during an upset to minimize the potential for a violation of the standard. If 

procedures fail, it is then up to an owner or operator to decide whether they should prepare and 

submit a report to assert an affirmative defense.

2.8.1 Affirmative Defense Provisions for Malfunctions

Comment: Three commenters (4240, 4375, 4415) oppose the EPA’s proposal to promulgate an 

“affirmative defense” to penalties due to a malfunction because it would create a new loophole in 

the standards and is unlawful. Two of the commenters (4375, 4415) opine that if the EPA does 

not eliminate the affirmative defense from the rule, adverse health impacts could result and that 
196

the EPA should be protecting vulnerable residents in regions with natural gas, and not providing 

a shield for industry.

One commenter (4240) asserts that the EPA unlawfully proposes to promulgate an “affirmative 

defense” to penalties due to a malfunction. See 76 FR at 52,787-88 (proposing §§63.761-62, §§ 

63.1271-72). The commenter opines that this would create a new loophole in the standards and is 

unlawful. The commenter states that the statute makes clear how the courts are to assess civil 

penalties, whether a case is brought by the EPA or a citizen. 42 U.S.C. § 7413(e). The 

commenter opines that Congress plainly intended citizens to be able to enforce emission 

standards under the CAA using the full range of civil enforcement mechanisms available to the 

government, and, in the HAP context, subject only to the limitation that government not be 

“diligently prosecuting” its own civil enforcement action, CAA §304(b)(1)(B), 42 U.S.C. § 

7604(b)(1)(B). Specifically, the commenter states that the affirmative defense that the EPA 

proposes to allow in case of malfunctions goes directly against congressional intent in two ways. 

First, according to the commenter, Congress expressed a clear intent as to how judges should 

determine the size of civil penalties whenever they are sought and thus Congress flatly barred the 

EPA from limiting when civil penalties can be assessed. See Chevron, U.S.A., Inc. v. Natural 

Res. Def. Council, Inc., 467 U.S. 837, 842-43 (1984). The commenter believes that the EPA acts 

outside of its delegated authority to limit civil penalties available in citizen suits or its own 

enforcement actions in its proposal. Second, the commenter asserts that the proposal will 

impermissibly chill citizen participation, and the ability to win an effective, deterrent remedy, in 

CAA enforcement actions.

The commenter (4240) argues that the CAA grants the EPA minimal discretion that only applies 

to administrative penalties, allowing the EPA to “compromise, modify, or remit, with or without 

conditions, any administrative penalty which may be imposed under [subsection 113(d)].” 42 

U.S.C. § 7413(d)(2)(B) (emphasis added). However, according to the commenter, there is no 

similar grant of authority to the EPA to compromise, modify or limit civil penalties that a court 

may impose under section 113(e) or section 304. Section 304(a), 42 U.S.C. § 7604(a), grants 

courts the sole authority “to apply any appropriate civil penalties” in citizen suits. According to 

the commenter, the explicit reference to the EPA’s ability to modify penalties in one subsection 

and its absence in the other subsection of the same provision can only be understood as an 

intentional decision by Congress that the EPA may not contravene by rule.

The commenter (4240) believes that an affirmative defense would likely be used on a routine 

basis by polluters seeking to avoid penalties, just as the malfunction exemption was. Thus, the 

commenter believes that the affirmative defense also runs counter to two clearly expressed 

intentions of Congress: (1) the burden it places on citizens makes it less likely that they will 

enforce the CAA, see, e.g., Pennsylvania v. Del. Valley Citizens’ Council for Clean Air, 478 U.S. 

546, 560 (1986); and (2) several of the factors at issue in the affirmative defense undercut 
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Congress’s intent that citizen suit enforcement should avoid re-delving into “technological or 

other considerations.” NRDC v. Train, 510 F.2d 692, 724 (D.C. Cir. 1974). According to the 

commenter, both result from the technical burden the EPA imposes on citizens with the 

affirmative defense, and both render the defense impermissible.

The commenter (4240) argues that the EPA has failed to demonstrate any need or rational 

justification for an affirmative defense to penalties to be written into the regulations and cause 

the harm that will result. According to the commenter, the EPA has discretion to decide what 

cases to prosecute, to consider settlements, and to request civil penalties in a case-by-case 

manner, as long as it acts consistent with the CAA to protect clean air as its top priority, see 42 

U.S.C. § 7401.

The commenter (4240) states that, if the EPA had the authority to promulgate any type of 

affirmative defense penalties for malfunctions, the statute requires that they also promulgate the 

following:

• A specific amount of compensatory penalties must apply to each reported 

malfunction (consistent with the CAA). 

• The EPA must modify the regulations so that the affirmative defense cannot be used 

by a specific facility or company more than once within a set period of time, such as 

10 years.

• The EPA must promulgate specific public reporting and notification requirements for 

malfunctions, or any emission exceedance that occurs of which an operator is aware. 

Response: The EPA’s view is that the affirmative defense is consistent with CAA sections 

113(e) and 304. Section 304 gives district court’s jurisdiction “to apply appropriate civil 

penalties.” Section 113(e)(1) identifies the factors that the Administrator or a court shall take into 

consideration in determining the amount of a penalty to be assessed only after it has been 

determined that a penalty is appropriate. The affirmative defense regulatory provision is not 

relevant to the amount of any penalty to be assessed under section 113(e) because if a court 

determines that the affirmative defense elements have been established, then a penalty is not 

appropriate and penalty assessment pursuant to the section 113(e)(1) factors does not occur.

In exercising its authority under section 112 to establish emission standards (at a level that meets 

the stringency requirements of section 112), the EPA necessarily defines conduct that constitutes 

a violation. The EPA’s view is that the affirmative defense is part of the emission standard and 

defines two categories of violation. If there is a violation of the emission standard and the source 

demonstrates that all the elements of the affirmative defense are met, only injunctive relief is 

available. All other violations of the emission standard are subject to injunctive relief and 

penalties. The CAA does not require that all violations be treated equally. Further, a citizen suit 
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claim under section 304 allows citizens to commence a civil action against any person alleged to 

be in violation of “an emission standard or limitation under this chapter.” The CAA, however, 

allows the EPA to establish such “enforceable emission limitations.” Thus, the citizen suit 

provision clearly contemplates enforcement of the standards that are defined by the EPA. As a 

result, where the EPA defines its emissions limitations and enforcement measures to allow a 

source the opportunity to prove its entitlement to a lesser degree of violation (not subject to 

penalties) in narrow, specified circumstances, as the EPA did here, penalties are not 

“appropriate” under section 304.

The EPA’s view is that an affirmative defense to civil penalties for exceedances of applicable 

emission standards during periods of malfunction appropriately balances competing concerns. 

On the one hand, citizen enforcers are concerned about additional complications in their 

enforcement actions. On the other hand, industrial sources are concerned about being penalized 

for violations caused by malfunctions that could not have prevented and were otherwise 

appropriately handled (as reflected in the affirmative defense criteria). The EPA has utilized its 

Section 301(a)(1) authority to issue regulations necessary to carry out the Act in a manner that 

appropriately balances these competing concerns.

The EPA disagrees that the affirmative defense provision will hamper citizen enforcement. First, 

injunctive relief is still available and the threat of penalties would not deter violations in cases 

where all of the conditions of the affirmative defense have been satisfied because the affirmative 

defense criteria ensure that all reasonable steps were taken to prevent a malfunction that causes 

excess emissions.

Further, litigating whether a source has met the affirmative defense will not burden citizen 

groups any more or less than would litigating the appropriate penalty amount in the penalty 

assessment stage of a citizen suit enforcement action, because the 113(e) penalty assessment 

criteria and the affirmative defense criteria are similar and in fact overlap. For example, the 

requirement that the Administrator or the court consider “good faith efforts to comply” is bound 

to generate the type of fact-intensive disputes that the commenter complains of. In addition, 

several of the affirmative defense criteria are exactly the type of criteria the Administrator or 

Court might consider in determining whether a source made “good faith efforts to comply.” For 

example, to take advantage of the affirmative defense, the source must prove by a preponderance 

of the evidence that, among other things, the excess emissions “were caused by an unavoidable 

failure of air pollution control and monitoring equipment, process equipment, or a process to 

operate in a normal or usual manner” and “could not have been prevented through careful 

planning, proper design or better operation and maintenance practices” and “did not stem from 

any activity or event that could have been foreseen and avoided, or planned for.”
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Thus, the EPA does not expect the affirmative defense provision to significantly alter the burden 

of bringing a citizen enforcement action. For those cases that do proceed to trial, even in the 

absence of this affirmative defense, sources generally raise equitable arguments to argue for a 

low penalty and citizens often rebut such arguments. Therefore, as a practical matter, the EPA 

does not expect the affirmative defense provision to materially affect the practice of CAA 

enforcement.

The EPA is not adopting commenters’ suggestion with respect to compensatory damages or 

limits on the frequency of use of the affirmative defense. It is not clear that the EPA has 

authority to require the automatic imposition of compensatory damages and even if such 

authority exists, the EPA does not think automatic imposition of damages is appropriate, as it 

would unduly complicate the enforcement process. Ensuring that malfunctions do not recur can 

be handled through imposition of appropriate injunctive relief. In addition, the EPA’s view is 

that it would not be appropriate to limit a source’s ability to take advantage of the affirmative 

defense to one time over a specified period of time such as ten years given that the affirmative 

defense is only available when the source could not have prevented the excess emissions. With 

respect to commenters’ suggested reporting requirements, the reporting requirements in the rules 

promulgated today already require malfunction reporting and the affirmative defense provisions 

require that parties choosing to assert the affirmative defense meet additional malfunction 

reporting requirements. Any such reports submitted to the EPA are publicly available pursuant to 

CAA section 114. 

Comment: Three commenters (4218, 4258, 4266) state that proving an affirmative defense will 

be close to impossible for malfunctions that occur at many of their facilities because they are 

located in remote areas that are not continually staffed. Commenters report that excess emissions 

can result from weather conditions or gathering system/processing plant outages that are beyond 

the control of the operator. According to commenters, inspection and maintenance visits occur 

on average anywhere from weekly to twice per month. Commenters note that winter weather 

often makes it difficult to visit sites causing extended periods between site visits. According to 

the commenters, although telemetry is often utilized for new production well sites to optimize 

the need for operator attention, weather conditions can affect not only the control device (flare 

flameout) but can also affect telemetry which would catch and report such discrepancies. 

Commenters report that system outages to the gathering system, gas treating plants, or gas 

processing plants occur infrequently but can occur several times during the year. They report that 

these outages immediately result in a stop in production, but that most wells must be visited 

manually in order to shut down the well and associated equipment. One commenter (4266) 

requests that the EPA specify how they would consider weather and “system” outages that are 

beyond the control of the upstream operator in a malfunction work practice. 
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Three commenters (4192, 4241, 4246) report that VRUs that are electric will not operate during 

power outages.

Response: In response to commenters that state that aspects of the affirmative defense would be 

“close to impossible” to prove, other than sources being remote and unmanned, specifics were 

not provided. However, the EPA is revising certain criteria of the affirmative defense that may 

ease the burden for owners and operators of remote sources. The EPA is eliminating both the 

immediate notification and 45-day malfunction report requirement. The final rule language 

requires the owner or operator seeking to assert an affirmative defense to submit a written report 

to the Administrator with all necessary supporting documentation. This affirmative defense 

report shall be included in the first periodic compliance, deviation report or excess emission 

report otherwise required after the initial occurrence of the violation of the relevant standard 

(which may be the end of any applicable averaging period). If such compliance, deviation report 

or excess emission report is due less than 45 days after the initial occurrence of the violation, the 

affirmative defense report may be included in the second compliance, deviation report or excess 

emission report due after the initial occurrence of the violation of the relevant standard. This 

change provides sources with sufficient time to demonstrate that they have met the required 

affirmative defense criteria.

Comment: Four commenters (4192, 4219, 4258, 4356) report that a variety of States, such as 

Texas and New Mexico, apply affirmative defense criteria that differ from what is proposed in 

subpart OOOO. One commenter (4192) opines that the EPA’s proposal would complicate 

enforcement in those States by necessitating that facilities submit two affirmative defenses (one 

corresponding to the State standard and the other corresponding to the EPA’s standard). 

One commenter (4258) reports that New Mexico’s “affirmative defense” found in 20.2.7 NMAG 

allows operators a 30-day timeframe within which to assert “affirmative defense,” which is 

inconsistent with the proposed Federal requirements. 

Three commenters (4219, 4258, 4356) request that the EPA expressly provide in the proposed 

rules that a SIP-approved State affirmative defense program would be sufficient to establish the 

affirmative defense for the Federal rules, or that the EPA defer to the State’s exceedance policies 

and regulations in lieu of the Federal affirmative defense provisions.

Response: Pursuant to CAA section 111(c) and the EPA regulations at 40 CFR 60.10, States 

may require equivalent or more stringent requirements. States that have SIP approved affirmative 

defense provisions that are equivalent to or more restrictive than the affirmative defense 

provisions in the final rule applicable to malfunction periods may seek to have those programs 

apply in lieu of those in the final rule.
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Comment: Two commenters opine (4192, 4246) that the EPA should not require an affirmative 

defense document for what are typically very small VOC process units. The commenters state 

that the proposed affirmative defense documentation is too detailed and burdensome (in that it 

requires, for instance, a “root cause” analysis), especially considering the nature of the excess 

emissions likely to occur under subpart OOOO. The commenters explain that excess emissions 

under subpart OOOO are not likely to trigger a violation of major source thresholds (for either 

criteria pollutant or HAP emissions), but would instead reflect brief emissions from very small 

sources with very little “uncontrolled” emissions. The commenters opine that the amount of 

documentation and level of proof for an affirmative defense are too high for the types of sources 

covered by subpart OOOO.

The commenters (4192, 4246) state that the strict requirements in the EPA’s proposed 

affirmative defense are the same as those that a refinery or chemical plant must meet. The 

commenters assert that their sources are vastly different than large emissions sources such as 

refinery process units, chemical plants, power plants, and large boilers, and request that the EPA 

streamline the affirmative defense procedures to reflect the differences between their sources and 

large process units. In developing streamlined affirmative defense procedures, the commenters 

request that the EPA also keep in mind that without a SSM exemption, owners and operators will 

engage in far more frequent reporting of excess emissions due to malfunctions.

One commenter (4241) recommends that the EPA reconsider the proposed affirmative defense 

language in light of the nature of the sources affected, and that it consider simply requiring that 

the operator maintain records documenting that: (1) the event was truly a malfunction, and (2) 

that the operator took all reasonable steps to minimize emissions during the malfunction and to 

correct the malfunction as expeditiously as possible. According to the commenter, this language 

would provide a more appropriate threshold for exceedances of emissions limits caused by 

malfunctions of properly designed and maintained equipment at small emissions sources. The

commenter also requests that the EPA reexamine the affirmative defense language as it is 

proposed, specifically in the context of storage vessels. The commenter explains that the 

proposed language was specifically developed for large sources with significant levels of 

emissions, and that the proposed rules cover small individual sources of VOCs where the 

proposed stringent affirmative defense language is not warranted.

Four commenters (4104, 4192, 4246, 4273) assert that the proposed affirmative defense 

requirements are too onerous or detailed, and restrictive.

One commenter (4104) supports inclusion of a malfunction exemption in the proposed new 

subpart OOOO. The commenter asserts that both the CAA and the Constitution require an upset 

defense as part of any technology-based standard. According to the commenter, as drafted, 

however, the proposed defense is far too narrow and restrictive to satisfy the CAA’s and the 
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Constitution’s requirements. For example, according to the commenter, the proposed rule would 

excuse only those events that do not “stem from any activity or event that could have been 

foreseen and avoided, or planned for[.]” 76 FR at 52829. However, the commenter asserts that, 

any number of events may be “foreseen” and “planned for,” but still interfere with a facility’s 

ability to comply with the standards. The commenter cites events such as a power failure or 

natural disaster as examples that may be anticipated, where the facility may have developed an 

appropriate emergency response plan to implement during these periods – yet may still find itself 

unable to comply with the standard, due to events such as lack of power, lack of access to the 

site, flooding, severe weather, earthquakes, mud slides, vandalism or terrorism, or upstream 

upsets that affect the natural gas that arrives at a natural gas transmission facility. According to 

the commenter, for all of the reasons discussed above, these types of foreseeable yet 

unpreventable events must either be reflected in the overall requirements, or excused as a 

malfunction.

One commenter (4192) requests that the EPA delete the proposed affirmative defense provisions. 

This commenter mostly opposes the onerous nature of the provisions and believes that less 

restrictive provisions are needed. 

One commenter (4273) states that there is no justification for including criteria to establish an 

affirmative defense against an alleged violation that are more onerous than the requirements of 

the regulation. They state that the requirements to show a malfunction under the proposed 

revised definition and general duty standard are less stringent that the criteria listed for 

establishing an affirmative defense against an alleged violation and that the EPA does not 

explain their reasons. The commenter acknowledges that the EPA cites two memoranda to 

support the proposed criteria, but asserts that the criteria outlined in the proposed rule are even 

more stringent than what is set out in the cited memoranda. For example, the commenter states 

that there is no reference to the malfunction event being “short;” there is no reference to a 

“written root cause analysis;” there is no reference to minimizing the impact of the excess 

emissions on the environment and human health; and there is no reference to limitations on the 

use of the bypass stack. According to the commenter, for technology-based standards, the EPA 

and courts have recognized that the EPA must either: (a) consider SSM in setting the standards 

or (b) provide an upset defense.

One commenter (4192) requests that if the EPA does not retain the exemption for SSM periods 

in subpart OOOO, that the EPA streamline the elements it has proposed for the affirmative 

defense.

One commenter (4219) states that the EPA proposes to include an exemption for malfunctions, 

but that they believe it is too narrow or restrictive. The commenter states that the exemption 

would excuse events that could not have been foreseen and avoided or planned for, but that 
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events that might be foreseen or planned for can still interfere with a facility’s ability to comply 

with the proposed standards. The commenter argues that these types of foreseeable yet 

unpreventable events (e.g., weather upsets) should either be reflected in the overall BSER 

requirements or they should be excused. 

One commenter (4273) believes that the EPA fails to explain how the system of emissions can be 

demonstrated for malfunction periods when it is not working during those periods. The

commenter provides extensive comments regarding why malfunction periods are not reflective 

of normal steady-state operations.

One commenter (4273) asserts that the EPA’s proposed affirmative defense criteria are arbitrary 

and capricious. The commenter states that the EPA does not explain why it proposes to limit 

affirmative defense to malfunction events (and not allow for an affirmative defense for startup 

and shutdown events).

Response: The EPA disagrees with comments that criticize the affirmative defense criteria as 

being arbitrary, capricious and overly vague or unduly restrictive and complex. The EPA 

believes that courts are well equipped and often do evaluate and apply the type of criteria set 

forth in the affirmative defense. Many of the conditions were modeled after the conditions of the 

affirmative defense in the EPA’s SIP SSM policy, which several States have adopted into their 

SIPs. (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)). We do not have any 

indication that parties to enforcement proceedings have had any significant difficulties applying 

the terms of these SIP affirmative defenses. In addition, the EPA’s view is that use of consistent 

terms in establishing affirmative defense regulations and policies across various CAA programs 

will promote consistent implementation of those rules and policies. 

Some commenters suggest that many malfunction excess emissions may be very small and not 

worth the burdensome effort of asserting an affirmative defense. The EPA reminds these 

commenters that sources are not required to assert an affirmative defense, so if it is not worth the 

effort, then sources do not have to take these additional steps. Indeed, if the excess emissions are 

very small, it may well be that enforcement officials will likewise not seek any remedy.

With respect to commenter’s concern that events such as floods or earthquakes that are 

foreseeable and have been planned for would not be eligible for the affirmative defense, the EPA 

believes that malfunctions that are caused by such events and that lead to violations could, 

depending on the circumstances, be eligible for the affirmative defense if the resulting violations 

could not have been prevented whether or not there was an attempt to plan for the event. 
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Preparing and having a plan in place that addresses floods generally does not mean that all 

consequences of flooding can be planned for or avoided. 

The EPA has evaluated some of the affirmative defense criteria, and is revising both the 

immediate notification and 45-day malfunction report. Instead, the final rule allows owners or 

operators seeking to assert an affirmative defense to demonstrate, with all necessary supporting 

documentation, that it has met the affirmative defense criteria by submittal of the affirmative 

defense report in the first periodic compliance, deviation report or excess emission report 

otherwise required after the initial occurrence of the violation of the relevant standard (which 

may be the end of any applicable averaging period). If such compliance, deviation report or 

excess emission report is due less than 45 days after the initial occurrence of the violation, the 

affirmative defense report may be included in the second compliance, deviation report or excess 

emission report due after the initial occurrence of the violation of the relevant standard. This 

change provides sources with sufficient time to demonstrate that they have met the required 

affirmative defense criteria.

Comment: Two commenters (4104, 4273) state that criteria outlined in the Proposed Rule are 

significantly more stringent than that provided in the analogous “upset defense” under the Clean 

Water Act, imposing substantial burdens on regulated entities for actions that, by definition, are 

not the fault of the facility. The commenters state that the EPA provides no explanation as to 

why it has chosen to move away from the long-standing upset defense at 40 C.F.R. §122.41(n), 

promulgated under the Clean Water Act. The commenters assert that, under the CWA, an “upset 

constitutes an affirmative defense.” 40 C.F.R. §122.41(n)(2). To establish the defense under the 

Clean Water Act, the commenters state following criteria must be met:

• an upset occurred and the permittee can identify the cause(s) of the upset;

• the permitted facility was at the time being properly operated;

• the permittee submitted notice of the upset (required within 24 hours); 

• the permittee took all reasonable steps to minimize or prevent the violation. See 40 

C.F.R. §122.41(n)(3), (l)(6)(i). 

One commenter (4104) specifically recommends that the EPA replace the proposed language 

with the language used at 40 CFR §122.41(n), the upset defense provided under the Clean Water 

Act. The commenter asserts that the language was crafted to cure the same statutory and 

constitutional deficiencies that compel the inclusion of a malfunction defense here, see, e.g., 

Train, 539. F.2d at 986, and so is the most appropriate and efficient mechanism for addressing 

these same deficiencies for subpart OOOO.

One commenter (4228) opines that the affirmative defense provisions in the proposed rule should 

be deleted and appropriate exemptions from rule standards should be added that account for 
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operating periods when even well managed BSER control technology would not provide 

compliance. According to the commenter, the EPA should replace the proposed rule malfunction 

defense language with the upset defense provided under the Clean Water Act (40 CFR 

122.41(n)).

Response: The EPA does not find the commenter’s preference for the affirmative defense under 

the Clean Water Act persuasive enough to deviate from the affirmative defense approach that has 

been used under the CAA for nearly 20 years. While we recognize that certain characteristics of 

the two approaches are similar, our preference is to adopt an approach that has been practiced 

under the CAA.

Comment: One commenter (4104) requests that the affirmative defense criteria be modified 

considering the following: 

• Timely notification: The availability of the affirmative defense should not be negated 

by a failure to notify, especially for events that involve small quantities of emissions.

• “Infrequent” events: Restricting the malfunction defense to “infrequent” events is 

legally acceptable only if more “frequent” events are excepted under some version of 

the startup/shutdown defense. 

• “Off-shift and overtime labor”: The requirement to use off-shift and overtime labor 

should be deleted, because it impairs the site’s ability to respond in the manner most 

appropriate under the circumstances. 

• “Severe property damage”: The word “severe” should be struck. Determining 

whether property damage is sufficiently “severe” to merit application of the defense is 

highly subjective and vague. 

• Signed operating logs: The EPA should remove the requirement that operating logs 

be signed. Many facilities now use some form of electronic media to document 

response actions; other facilities may use paper records that do not require a 

signature. 

• Root cause analysis: The requirement to perform a root cause analysis is vague and 

does not put industry on notice of the type of analysis that the EPA will deem 

sufficient, or the time in which such an analysis must be performed. Such an analysis 

is also unnecessarily burdensome and serves no environmental protection purpose for 

many malfunction events where the “root cause” is clearly identifiable (e.g., power 

outage, hurricane). 

Another commenter (4356) requests that the EPA provide clarification on the following criteria:

• Operating Logs: Proposed §60.5415(h)(1)(vii) lists a requirement that “All actions in 

response were properly documented by properly signed contemporaneous operating 
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logs,” but does not define or accurately describe what would fulfill that requirement. 

This requirement is impractical for many sites that are unmanned, where there will be 

no operator logs.

• Root Cause Analysis. Proposed §60.5415(h)(1)(ix) stipulates that “a written root 

cause required to determine, correct, and eliminate the primary cause of the 

malfunction.” This inevitably leads to an owner or operator attempting to describe a 

preventative action to an event that (by definition in §60.5415(h)(1)(i)(B)) could not 

have been prevented.

• Control Device Bypass Requirements. Proposed §60.5415(h)(1)(iv) unnecessarily 

requires additional conditions to meet an affirmative defense to bypass a control 

device. In some circumstances, the bypass may be the most appropriate temporary 

implementation while correcting or repairing a condition of upset, since the upset 

may be with the control device itself. 

Response: The EPA has considered the commenter’s suggestions associated with specific 

affirmative defense criteria changes. Although not all of the changes were accepted, some are 

reflected in recent changes the EPA has made to these provisions.

• Timely Notification: The EPA has removed the requirement to notify the EPA within 

two days of violation of a standard in order for sources to be able to avail themselves 

of a claim for an affirmative defense. The owner or operator seeking to assert an 

affirmative defense shall submit a written report to the Administrator with all 

necessary supporting documentation. This affirmative defense report shall be 

included in the first periodic compliance, deviation report or excess emission report 

otherwise required after the initial occurrence of the violation of the relevant standard 

(which may be the end of any applicable averaging period). If such compliance, 

deviation report or excess emission report is due less than 45 days after the initial 

occurrence of the violation, the affirmative defense report may be included in the 

second compliance, deviation report or excess emission report due after the initial 

occurrence of the violation of the relevant standard. 

• “Infrequent” Events: The EPA believes that if malfunctions occur on a frequent basis 

that the basis for the malfunction more likely falls in the categories of poor design, 

poor operational decision making, or failure to operate a source in a normal manner 

and has retained the word “infrequent” in this criteria element.

• “Off-shift and overtime labor”: The EPA believes that rather than impair a sources 

response to a malfunction, the use of off-shift and overtime labor supports the 

premise that urgency is necessary to minimize to the maximum extent practicable all 

excess emissions associated with a malfunction and has retained this language in the 

criteria. 
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• Severe Property Damage: The EPA believes that a bypass of control equipment or a 

process, which results in a violation, should be an exception and not undertaken 

lightly, and has maintained the word “severe” in this criteria.

• Signed Operating Logs: As an alternative, the EPA accepts electronically signed 

operating logs where the format and method of submission meets the regulatory 

criteria and are compatible with the EPA and the delegated authorities’ electronic 

submission systems. Any source submitting records electronically should exercise 

due diligence to assure receipt by the EPA and the delegated authority. 

• Root Cause Analysis: The EPA believes it has provided clear criteria within the 

affirmative defense provisions to support the development of an affirmative defense 

report. The EPA believes that these provisions will result in a minor administrative 

burden, but will result in sources analyzing their violation emissions to reduce or 

avoid those emissions in the future, which is an environmental benefit. A root cause 

analysis is not mandatory and is only required if a source seeks to assert an 

affirmative defense. However, such an analysis is beneficial in resolving or 

preventing violations and excess emissions whether the source seeks to assert the 

affirmative defense or not. A root cause analysis is one example of what constitutes 

good air pollution control practices to minimize emissions. A root cause analysis is 

not required for every malfunction, as specified above, and is only required for those 

malfunctions for which the source chooses to assert an affirmative defense. 

• Control Device Bypass Requirements: The EPA has not received compelling evidence 

on how releasing uncontrolled regulated pollutants to the atmosphere while repairing 

a control device could be the most appropriate course of action during a malfunction. 

However, affirmative defense provides the opportunity for a source to assert such a 

conclusion. The criteria listed in the rule references the use of bypasses, and stipulates 

the underlying reason why a bypass might be justified: “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.” 

Nonetheless the EPA cannot pre-judge the validity of any justification for asserting 

affirmative defense beyond the guidance provided in the rule.

Comment: One commenter (4218) recommends deleting §§60.5370(b) and 60.5415(h). 

According to the commenter, if the EPA makes the recommended deletions and would like to 

require reporting regarding malfunctions, the commenter suggests that the EPA require a 

submission of information similar to what is specified in §63.6650(c)(4) in the annual report 

required under proposed §60.5420(b).

One commenter (4266) asserts that the proposed 2-day notification is unrealistic, unnecessary, 

and burdensome. The commenter asserts the provisions of §60.5415(h)(1)(i)-(ix) would specify a 

9-step procedure for determining whether a given malfunction event qualifies for the affirmative 
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defense. In most cases, according to the commenter, it would not be realistic to complete this 

determination process within 2 days following the occurrence of the event. The commenter 

believes that facilities might therefore tend to routinely submit the 2-day notification in order to 

preserve the potential for an affirmative defense, even in cases which subsequently are 

determined to not qualify. Furthermore, the commenter states, there is no environmental benefit 

that would accrue from this notification, and similar provisions in refinery consent decrees do

not require it. The commenter believes the result of this unrealistic and unnecessary requirement, 

then, would be to burden both the facility and the regulatory agency having jurisdiction with the 

processing of paperwork that has no associated environmental benefit. As proposed, the 

commenter believes these notifications would be required for the smallest of emission 

exceedances with no reportable quantity threshold being set. The commenter asserts this is 

contradictory to other EPA reporting rules such as those under CERCLA and EPCRA where 

reportable quantities are established for unauthorized releases. The commenter believers that 

requirements for immediate reporting of excess emissions of VOCs should be left to the States as 

they are best equipped to handle any response that might be required as a result of the release. 

The commenter adds that immediate reporting to the EPA serves no beneficial purpose. The 

commenter concludes that if the EPA insists on a notification requirement, the rules should allow 

at least 15 business days following the occurrence of the event for this notification to be 

submitted.

One commenter (4242) requests that the EPA allow malfunction reports to be submitted with the 

excess emissions reports on a semi-annual basis. The commenter believes that there is no reason 

to require a reporting frequency that differs from the semi-annual basis. 

One commenter (4218) requests that, if the EPA does not delete §§60.5370(b) and 60.5415(h), 

that the EPA remove the requirements for the 2-day and 45-day malfunction reports required by 

proposed §60.5415(h)(2) and instead require that the owner or operator (1) maintain records of 

the information necessary to prove the affirmative defense, and (2) notify the EPA of each 

emission limit exceedance for which the owner or operator is claiming the affirmative defense in 

the annual report required under proposed §60.5420(b). The commenter also requests that the 

EPA remove the requirements for the owner or operator to provide a root cause analysis, 

(h)(1)(ix), in order to establish the affirmative defense. The commenter provides suggested 

revisions to proposed §60.5415(h) regulation language that reflects their requests (refer to 

comment letter for their suggested regulation language revisions).

Response: The EPA has evaluated some of the affirmative defense criteria, and is removing both 

the immediate notification and 45-day malfunction report requirement. Instead, the final rule 

allows owners or operators seeking to assert an affirmative defense to demonstrate, with all 

necessary supporting documentation (as was required under the proposed 45-day report), that it 

has met the affirmative defense criteria by submittal of the affirmative defense report in the first 
209

periodic compliance, deviation report or excess emission report otherwise required after the 

initial occurrence of the violation of the relevant standard (which may be the end of any 

applicable averaging period). If such compliance, deviation report or excess emission report is 

due less than 45 days after the initial occurrence of the violation, the affirmative defense report 

may be included in the second compliance, deviation report or excess emission report due after 

the initial occurrence of the violation of the relevant standard. This change provides sources with 

sufficient time to demonstrate that they have met the required affirmative defense criteria.

2.8.2 Other Comments

Comment: One commenter (4236) requests that the EPA acknowledge that malfunctions can 

happen, and may in fact happen more frequently, during periods of startup and shutdown and 

that the factors considered in determining whether an event is a malfunction apply equally if the 

malfunction occurs during a period of startup and shutdown.

Response: As the EPA explained in the preamble to the proposed rule, the EPA recognizes that 

even equipment that is properly designed and maintained can fail and that such failure has the 

potential to cause a violation of the relevant emission standard. The EPA included an affirmative 

defense in the final rule 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 limits may be exceeded under circumstances beyond the 

control of the source. The affirmative defense simply provides for a defense to civil penalties for 

excess emissions that are proven to be beyond the control of the source and appropriately 

balances competing concerns.

Comment: One commenter (4273) opines that deviations should not be construed or assumed to 

be “non-compliance” or violation of a regulatory requirement (see proposed §60.5420(b)(2)(ii) 

and (c)(1)(ii)). The commenter states that by construing a deviation as a violation of a regulatory 

requirement, the EPA is defining a deviation in the context of a legal conclusion, which will 

operate as an admission of liability. The commenter provides that not all deviations are 

violations (e.g., deviations from parameter monitor requirements) and facilities may have 

defenses available to them where a deviation would not be a “noncompliance” situation.

Two commenters (4192, 4246) recommend that deviations be identified in semiannual or annual 

reports, in lieu of the 2-day and 45-day notification and report requirements.

One commenter (4226) recommends that, to avoid the slightest malfunction from resulting in a 

civil action, the EPA could develop small/de minimis incidents that could be tracked as 

deviations rather than exceedances. Under this scenario, the commenter asserts that industry 
210

would still track the incidents and report them to EPA but the affirmative defense and associated 

criteria would not need to be met.

Response: The EPA does not assert that all deviations are violations. The EPA has not changed 

the definition of deviation in this subpart, and deviation reporting is to continue operating as 

before. It should be pointed out, however, that deviations are generally instances where a source 

has failed to meet a standard. The second step, the determination of whether a deviation was an 

infraction of the law, is determined through an enforcement proceeding.

Reporting for affirmative defense, which seems to be the object of commenters 4192 and 4246, 

is not the same as reporting a deviation in a deviation report. The EPA has eliminated the 

requirement to submit a 2-day malfunction notification and 45-day report requirement if a source 

decides to assert an affirmative defense. Instead, the final provisions require submittal of the 

affirmative defense report in the first periodic compliance, deviation report or excess emission 

report otherwise required after the initial occurrence of the violation of the relevant standard 

(which may be the end of any applicable averaging period). If such compliance, deviation report 

or excess emission report is due less than 45 days after the initial occurrence of the violation, the 

affirmative defense report may be included in the second compliance, deviation report or excess 

emission report due after the initial occurrence of the violation of the relevant standard. 

Submitting this report to assert an affirmative defense is entirely at the discretion of the source, 

and is not a condition of compliance. A report to assert affirmative defense may contain most or 

all the information with respect to a specific deviation, but only the deviation report is a 

requirement.

Comment: One commenter (4254) requests that the EPA clarify that neither the new EPA 

interpretation of SSM explained in the preamble (section V.E.5) nor the requirements for 

continuous compliance in §60.5415(e) of the proposed rule require a backup control device. 

Two commenters (4231, 4254) suggest that the EPA should include a provision that a combustor 

or flare that continues to emit without a functioning flame constitutes a per se malfunction, and a 

source would not be required to mount an affirmative defense to prove the malfunction. The 

commenters support ANGA's position that if a combustor or flare emits while there is no flame, 

emissions from such an upset or malfunction (SSM, or SSM) should not count against the 95 

percent control of VOC emissions required under normal conditions. Another commenter (4241) 

states that flares are generally equipped with a flame arrestor to ensure safe operation of the 

device and they seek clarification from the EPA on whether such events would be treated as 

“malfunctions” where a good faith effort is made to minimize emissions by limiting the period of 

time that a pilot flame might be extinguished.

One commenter (4254) requests that the EPA clarify that any emissions resulting from a proven 

or EPA-defined malfunction will not count against a source's total emissions allowance.
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Response: The use of a flare or combustor as a control device is subject to the requirement that 

standards be met at all times. In the event that such a device operates and emits without flame, 

this would contravene the requirement to operate a flare or combustion device to reduce 

emissions to the atmosphere. The EPA further clarifies for the commenter that a combustor or 

flare that continues to emit without a flame may be emitting regulated pollutants, and those 

pollutants should be quantified and included in the calculation of emissions to determine 

compliance for the source.

The EPA cannot provide the clarifications requested, because the EPA is not prepared to assert in 

this case that a secondary or backup control technique would not be warranted. It remains the 

domain of the source to manage their process and control equipment, and choose the control 

strategy that best meets the needs of the source to comply with applicable standards. In certain 

cases it may be in the interest of a source to develop a secondary or backup control strategy to 

avoid failing to comply with standards during or as a result of malfunctions. While the EPA 

generally believes that standards governing flares are flexible enough to allow some variation in 

operating efficiency, the EPA is not prepared to issue a blanket statement that sources need not 

invest in equipment to ensure continuous compliance with applicable standards.

The EPA’s rationale for its approach to malfunctions is explained in the preambles to the 

proposed and final rules. The EPA thinks the commenter misinterprets the meaning of 

malfunction and affirmative defense. To avoid a judgment that includes civil penalties, a source 

must prove not only that the event in question meets the definition of malfunction, but must also 

show that the operation and maintenance prior to the event and the source's response to it meet 

the criteria of affirmative defense. Second, to exclude emissions from a flare that is 

malfunctioning from a compliance calculation is to continue to grant another form of a 

malfunction exemption. Finally, following a malfunction with a good faith effort to minimize 

emissions is one of several actions required to meet the criteria to successfully assert affirmative 

defense. 

Finally, by “emissions allowance” the EPA takes the commenter to mean the quantity of 

emissions allowed by an applicable standard. Emissions of HAPs or criteria pollutants from a 

malfunction are to be included in any compliance calculation, because to do otherwise would be 

to allow sources to emit beyond what the EPA has determined is an appropriate safe level of

emissions to be protective of human health and the environment.

Comment: Two commenters (3469, 4254) request that the EPA confirm that States have 

enforcement discretion and can determine whether or not to prosecute an incident with excess 

emission:
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"[S]tates may ... as an exercise of their inherent enforcement discretion, choose not to 

penalize a source that has produced excess emissions" as long as this discretion does not 

prevent EPA or third parties from bringing an enforcement action. EPA Memorandum, 

State Implementation Plans: Policy Regarding Excess Emissions During Malfunctions, 

Startup, and Shutdown (Sept. 20, 1999).

Response: The EPA affirms the language. The EPA reminds the commenters that affirmative 

defense is asserted when it is established that a violation of a standard has occurred. In affirming 

this language, the EPA is affirming that delegated authorities enforce regulations with 

established principles of discretion. In affirming that a source “has produced excess emissions” 

the EPA is not providing anything that the States do not already have. States already have the 

ability to examine excess emissions events and determine whether a violation of an applicable 

standard has occurred, and if so, what enforcement action is appropriate.

Comment: Two commenters (4231, 4254) recommend that the EPA provide up to 24 hours 

before equipment downtime is determined to be a malfunction, after which reporting is required. 

The commenters explain that companies can be responsible for hundreds of process units spread 

over considerable distances that are often difficult to get to, which differs from other process 

units that the EPA regulates that are centrally located and operated. The commenters suggest 

that, if equipment downtime is less than 24 hours, the EPA could require facilities to keep 

records of the incident and emissions, but not require reporting. In cases where repair is not 

completed within 24 hours, the commenters suggest that the EPA could require the EPA or 

delegated authority be notified with a justification as to why the repair was not completed.

Another commenter (4266) requests that the EPA provide an allowance for a reasonable period 

of routine maintenance for the control device. The commenter states that proper operation of a 

control device includes periodic routine maintenance, and manufacturers of control devices 

typically recommend preventive maintenance on a semi-annual basis. According to the 

commenter, the EPA has stipulated in other rulemakings that standards do not apply during 

planned routine maintenance, other than a work practice standard that such periods shall not 

exceed 240 hours per year and records must be maintained to document such periods. 

One commenter (4219) states that startups and shutdowns are periodically required for testing 

and installation of new equipment that can result in increased efficiency and enhanced 

environmental benefit. The commenter opines that if owners and operators risk non-compliance 

during periods of SSM, they would have a disincentive to install equipment that would improve 

air quality.

Response: 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 
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“emission limitation and emission standard”). See generally Sierra Club v. EPA, 551 F.3d 1019, 

1021 (D.C. Cir. 2008) (emissions limitations under CAA section 112 must both continuously 

apply and meet section 112’s minimum stringency requirements, even during periods of SSM). 

Thus, the EPA is required to ensure that section 111 emissions limitations (as well as section 112 

emissions limitations) are continuous. The EPA’s rationale for its approach to malfunctions is 

explained in the preamble to the proposed rule. The commenter failed to provide any data, define 

any process or operational limitations, or to provide a specific rationale or basis to support a 

maintenance allowance or work practice during maintenance activities specific to control 

devices. 

The commenter generally asserts that the EPA should include a maintenance allowance provision 

in this rule, but did not identify any specific process or operational limitations or provide any 

data or explanation to support its assertion. The EPA, therefore, has not included such a 

provision in the final rule. 

The commenter did not provide an explanation or information to support the claim that owners 

and operators would risk noncompliance during periods of startup and shutdown when installing 

or testing a new control device. The EPA, therefore, has not included alternate standards for 

startup and shutdown in the final rule.

Additionally, as noted in response to a comment on malfunction reporting, the EPA has 

evaluated some of the affirmative defense criteria, and is revising both the immediate notification 

and 45-day malfunction report. Instead, the final rule allows owners or operators seeking to 

assert an affirmative defense to demonstrate, with all necessary supporting documentation (as 

was required under the proposed 45-day report), that it has met the affirmative defense criteria by 

submittal of the affirmative defense report in the first periodic compliance, deviation report or 

excess emission report otherwise required after the initial occurrence of the violation of the 

relevant standard (which may be the end of any applicable averaging period). If such 

compliance, deviation report or excess emission report is due less than 45 days after the initial 

occurrence of the violation, the affirmative defense report may be included in the second 

compliance, deviation report or excess emission report due after the initial occurrence of the 

violation of the relevant standard. This change provides sources with sufficient time to 

demonstrate that they have met the required affirmative defense criteria, and addresses some of 

the commenters’ concerns. 

Comment: Three commenters (4159, 4220, 4273) request that the EPA exclude drilling and 

completion activities as they are effectively startup after initial construction rather than steadystate operations aimed at creating an ongoing producing well. The commenters assert that the 

EPA has historically excluded startup emissions from regulation under NSPS and should do the 

same here.
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Response: The EPA disagrees with the assertion that drilling or completing a well constitutes a 

“startup” or “shutdown.” Generally, standards regulate identifiable emission points, and 

production process equipment. The affected facility covered by these standards is the well, which 

includes the well bore, casing, tubing, and wellhead. The operational standard imposed by the 

NSPS applies to the completion operation involving the well. The completion operation is not 

considered a startup, but is a discrete operation conducted on the affected facility. The 

completion operation begins with flowback following hydraulic fracturing and ends with well 

shut-in or continuous flow of gas to the sales line, whichever is earlier. The drilling operation is 

not affected by the NSPS since it precedes the completion operation as defined in the final rule. 

Comment: One commenter (4240) requests that, if the EPA finalizes any form of an affirmative 

defense, it requires that all reports related to that defense be submitted by electronic media, and 

that the EPA make those reports available immediately to the public on its website. The 

commenter asserts that the public has the right to all collected reports under the CAA, 42 U.S.C. 

§7414(c), and that the EPA must disclose this information to the public on the Internet, without 

the need for any person to submit a FOIA request for such report.

Response: The EPA accepts documents in electronic format, as long as the format is compatible 

with the requirements of the standards. The written reports required to demonstrate that the 

affirmative defense provisions have been met and requests for an extension of the deadline for 

these reports may be submitted electronically. Owners and operators that submit documentation 

for affirmative defense electronically should exercise due diligence to ensure receipt by the 

Administrator and the delegated permit authority. 

In response to the commenter that requests that the EPA require all reports related to an 

affirmative defense be submitted by electronic media and be made available immediately to the 

public on its website, we have not adopted their request. The NSPS sources subject to regulation 

under this rulemaking are typically small individual sources that are spread out and often in 

remote areas. It is important for the EPA to allow various options for submittal of reports, though 

it is likely that most sources will opt to submit their reports electronically. Additionally, any such 

reports submitted to the EPA are publicly available pursuant to CAA section 114, and some 

States make this information publicly available on their websites.

Comment: One commenter (4242) states that the EPA needs to evaluate technology and 

improved work practices that would eliminate or reduce malfunction events at natural gas 

processing plants. The commenter recommends that, in evaluating this technology, the EPA 

consider that a large proportion of emissions from natural gas processing plants occur during 

malfunction events. 
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Response: The EPA agrees that it would be helpful to be able to evaluate technology and work 

practices with respect to malfunctions, and overall effectiveness of control devices and processes 

to operate reliably. However, retrospective data would be of reduced value to that effort, given 

that such malfunctions did not result in violations of the standard. Henceforth, sources will 

monitor and report such events more thoroughly, with particular interest in reducing their 

frequency, duration, and severity. The data that will be generated and collected during such 

events will help stakeholders, and the EPA, to understand what technology is most effective at 

pollution control, including with respect to avoiding malfunctions.

Comment: One commenter (4245) asserts that SSM emissions will no longer be exempt from 

permitting and control requirements. The commenter states that the noted exemption in the 

proposed regulation from title V (federal permit) specifically does not apply to emission 

increases triggered by accounting for SSM emissions. The commenter is concerned that, by 

forcing operators to account for startup, shutdown, and maintenance emissions as part of their 

operating emissions “footprint” it will shift the permitting, control, monitoring and reporting 

requirements upward (in the direction from permit-by-rule registration to standard permit to 

major permit). Thus, according to the commenter, countless oil and gas facilities in Texas that 

are presently covered by permit-by-rule (most requiring registration due to H2S) will be moved 

to standard permit requirements and many presently covered by standard permit will be pushed 

upward to major (title V) permit requirements. The commenter asserts that this is a tremendous 

challenge for the Permian Basin in Texas, which is constrained with respect to sour gas handling 

and processing capacity. The commenter asserts that the EPA’s proposal to require the inclusion 

of start-up, shut-down and maintenance emissions will have the effect of vastly expanding the 

scope of regulatory requirements for small oil and gas producers. According to the commenter, it 

will also create, on a wide scale, circumstances where operators cannot physically comply with 

emission standards due to real limitations in gas gathering systems, thus forcing them to curtail 

or shutdown their operations. 

Response: The changes that we proposed to the startup, shutdown and malfunction (SSM) 

provisions of the Oil and Natural Gas Production MACT do not affect how a source determines 

whether it is a “major source” and, therefore, required to obtain a title V operating permit.25 

Rather, the proposed changes simply propose to eliminate the exemption in the original Oil and 

Natural Gas Production MACT, which provides that sources do not need to comply with the 

emission standards in the rule during periods of SSM, and thus require compliance with the 

standards at all times. Removing that exemption does not alter how the source or a permitting 

authority determines a source’s potential to emit (PTE) or whether the source is required to 

obtain a title V operating permit. 

 

25 As a general matter, area sources that are subject to subpart HH are exempt from the requirement to obtain a title 

V operating permit.
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With respect to commenter’s suggestion that EPA leave the regulation of SSM emissions to the 

respective state agencies, EPA notes that in accordance with the decision in Sierra Club v. EPA, 

551 F.3rd 1019 (D.C. Cir. 2008), EPA is required to establish emission standards under section 

112 that apply at all times, including during periods of startup, shutdown or malfunction. Thus, 

EPA cannot defer the regulation of SSM emissions to state agencies.

2.9 Notification, Recordkeeping and Reporting Requirements for the 

Proposed NSPS

Comment: One commenter (4356) requests that the EPA confirm that the recordkeeping, 

monitoring, and reporting requirements under these rules are sufficient to comply with all 

necessary title V requirements.

Response: The EPA cannot confirm that the recordkeeping, monitoring, and reporting 

requirements under the rule are sufficient to comply with all necessary title V requirements, nor 

are we required to do so as the programs are established under separate authorities. Where 

information is already submitted for the title V program, we have clarified in the final rule that 

the same information may be used for the annual report, as long as all of the required elements of 

the annual report are included.

Comment: One commenter (4251) notes that the 30-day notification for wildcat wells would 

conflict with the need to protect proprietary business information.

Response: The final rule no longer contains a 30-day advance notification for well completions. 

Instead, the final rule relies on a notification, which may be sent via email, no later than 2 days 

prior to commencement of the well completion. While this change was not made in response to 

this comment, we believe that it will address the concerns raised by the commenter. Regardless, 

we believe the CAA provides ample protection for submittal of confidential business information 

(CBI). The commenter should contact their State regulatory agency or EPA Regional Office for 

further instructions on the submittal of CBI.

Comment: One commenter (4161) states that in §60.5420, the annual reports subsequent to the 

initial report are due on the same date as the initial report. The commenter is concerned that if a 

company submits the report a day early, it would be in violation of this requirement. 

Response: Due dates are interpreted as “on or before” the specified date. Submitting a report 

early would not be considered a violation of the requirement to submit.

Comment: One commenter (4191) recommends that the EPA consider whether the proposed 

rule provides adequate reporting and recordkeeping provisions, and enforcement provisions 
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where the necessary reporting and recordkeeping is either not submitted, or found to be 

incomplete or inaccurate.

Response: The final rule clearly states that the owner or operator of an affected facility must 

perform the recordkeeping and reporting required by the rule. For example, §60.5375(e) states 

that the required notification, recordkeeping and reporting requirements must be performed for 

each gas well affected facility. The final rule contains similar provisions for the other affected 

facilities. Thus, failure to comply with these requirements is a violation and the EPA may take 

enforcement actions.

Comment: One commenter (4231) believes the applicability date of August 23, 2011, makes 

compliance very difficult for pneumatic controllers and requested that the compliance date be 

extended to 60 days after the final rule is issued.

Response: As required by law, affected facilities are subject to the rule as of August 23, 2011. 

The final rule, however, does allow affected facilities until the effective date (30 days after the 

rule is published in the Federal Register) to achieve compliance. As described elsewhere in this 

document and in the final rule preamble, the final rule also allows a compliance phase-in for 

certain affected facilities.

Comment: Four commenters (4158, 4175, 4209, 4228) state that the classification of each 

pneumatic controller as an affected facility and the associated monitoring, recordkeeping, and 

reporting requirements prescribed in the proposed rule makes compliance overly burdensome.

Another commenter (4158) disagrees with the EPA’s benefit analysis and asked for the 

following changes: classification of high versus low-bleed should be based on vendor 

specifications and not on guarantees; and in §60.5420(b)(5)(iii), the term “manufacturer’s 

guarantee” should be replaced with “manufacturer’s specification.” Another commenter (4231) 

suggests that “guarantee” be replaced with the word “rated.” Another commenter (4104) 

suggests that “guarantee” be replaced with the word “documentation.” 

Two commenters (4266, 4268) note that limiting this regulation to high-bleed gas-driven 

pneumatic controllers in VOC service would greatly reduce reporting and recordkeeping burden 

in this rule.

A commenter (4246) notes that a single natural gas processing plant may have several hundred 

pneumatic controllers, with only a small subset of those intended to be subject to the proposed 

rule. The commenter wonders why they should have to track and report on pneumatic controllers 

already compliant with subpart OOOO. The commenter suggests that the only pneumatic 

controllers that require reporting are high-bleed gas-assisted controllers located at any facility, 

and low-bleed gas-assisted controllers located at natural gas processing plants. The commenter 
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also suggests that the initial report from owner/operators list all pneumatic controllers that do not 

already meet subpart OOOO standards at the time of the report.

Response: As detailed in the preamble to the final rule, we have revised the recordkeeping and 

reporting requirements for pneumatic controllers in the final rule to reduce the burden of these 

requirements. We also agree that a bleed rate guarantee may not be available from the pneumatic 

controller manufacturers. Therefore, the final rule requires that records be maintained of 

documentation of the bleed rate. Annual reports need include only documentation for certain 

exemptions and a listing of pneumatic controller affected facilities constructed, modified or 

reconstructed during the reporting period. 

Concerning the comment on tracking and reporting pneumatic controllers already in compliance 

with the subpart OOOO requirements, we remind the commenter that the final rule applies only 

to new, modified or reconstructed affected facilities. Existing pneumatic controllers would not be 

subject to the rule unless replaced, modified or reconstructed.

Comment: One commenter (4266) recommends a way to reduce the reporting requirements for 

owner/operators. This commenter points out that determination of an affected facility for 

pneumatic controllers or pneumatic process units can be made on a site-wide basis instead of by 

individual controllers. For example, if compressed air is available to drive pneumatic controllers 

at any oil and gas site, the commenter claims it will be available to drive all controllers.

According to the commenter, reporting on a site-wide basis for driver medium would reduce the 

burden on owner/operators.

Response: In the final rule, we have defined the affected source as “a single continuous bleed 

natural gas driven pneumatic controller operating at a natural gas bleed rate greater than 6 scfh 

...” Thus, the compressed air driven controllers mentioned by the commenter would not be an 

affected facility and would not be subject to the rule. While this will address much of the 

commenter’s concerns, we do not agree that the affected facility determination should be done 

on any type of group level because of inspection issues related to determining whether each 

controller is in a regulated group or unregulated group.

Comment: One commenter (4104) argues that operator records that document the basis for 

using high bleed controllers in certain circumstances are all that should be required, not a 

demonstration to the Administrator.

Response: We agree with the commenter. The final rule specifies the appropriate recordkeeping 

requirements for the use of high bleed controllers in limited circumstances. No demonstration or 

petition to the EPA is required.
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Comment: One (4231) commenter suggests a set annual reporting date for all applicable sources 

(including pneumatic controllers) to avoid tracking different annual report dates by facility.

Response: The final rule envisions a single annual report, not an annual report per affected 

facility. The final rule also provides flexibility in when the report is submitted, as well as 

combining the annual report with other reports.

Comment: One commenter (4246) requests that the EPA add the words “and the reporting 

requirements found in 40 CFR §§60.5420 and 60.5422” at the end of §60.5401(d). Although the 

commenter supports the text as written, this exemption should apply to reporting requirements as 

well as to routine monitoring.

Response: There are no reporting or monitoring requirements for these affected facilities in 

§§60.5420 or 60.5422; therefore, the requested change is not needed.

Comment: One commenter (4255) says that administrative expenses associated with the 

proposed rule would affect the economic viability of low production wells. The commenter states

that the administrative cost of achieving initial compliance with the 6 scf per hour standard 

through a manufacturer’s guarantee of performance and the subsequent recordkeeping and 

reporting requirements needed to demonstrate standards compliance would be unduly 

burdensome. Therefore, the commenter suggests low production wells should be exempt from 

the proposed pneumatic controller requirements.

Response: As discussed previously and in the preamble to the final rule, we reviewed all 

recordkeeping, reporting and monitoring requirements in the proposed rule and retained only 

those requirements we believe are necessary to assure the public and regulatory agencies that the 

owner or operator is achieving compliance. As discussed elsewhere in this document, we 

performed a very detailed analysis of the cost and burden of the recordkeeping, reporting and 

monitoring requirements. This analysis did not show an excessive burden on the industry, 

including small sources. Therefore, we did not include an exemption for low production wells in 

the final rule.

Comment: One commenter (3528) states the required annual report of all pneumatic controllers 

due within one year of start-up or one year after publication of the final rule contradicts the 

EPA’s GHG Rule, 40 CFR part 98, subpart W for Oil and Gas Production, which allows three 

years for the completion of a pneumatic controller inventory. The commenter thinks this annual 

report would be excessively burdensome for operators with hundreds or thousands of pneumatic 

controllers.
220

Response: There are no regulatory requirements that the reporting requirements of subpart 

OOOO (or any other NSPS) must coincide with subpart W. The two rules serve very different 

purposes and it makes sense that reporting requirements would differ.

Comment: Once commenter (3560) expresses concern that manufacturer data for low and no 

bleed devices would be difficult or impossible to provide. The commenter claims that data 

needed to document that newly installed devices are no or low bleed devices is often lost due to 

devices being warehoused prior to use or located from other facilities. The commenter 

recommends that manufacturer data be required only for pneumatic devices manufactured 180 

days after promulgation of the regulation.

Response: We disagree with the commenter. Our communications with manufacturers and 

suppliers of pneumatic controllers indicate that this information is readily available. We also 

believe that should documentation be lost, a replacement is readily available from the 

manufacturer or the manufacturer’s web site.

Comment: Once commenter (4266) states that providing records of existing controllers’ 

installation dates may not be possible.

Response: We remind the commenter that the final rule does not apply to existing pneumatic 

controllers unless the existing controller is replaced, modified or reconstructed. Thus, no records 

would be required for existing pneumatic controllers.

Comment: Three commenters (4104, 4209, 4219) request that the EPA reevaluate requirements 

for pneumatic controller/devices associated with pipelines. The commenters argue that, as 

written, the proposed rule’s applicability would be too broad and would result an undue 

recordkeeping and permitting burden. The commenters argue that the administrative burden does 

not justify the regulation of component parts that emit on the order of 100 pounds or less of VOC 

emissions per year. The 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).

Response: We agree that requirements applied to pneumatic controllers located in the 

transmission and storage sector would present unreasonable monitoring, recordkeeping and 

reporting burdens for sources with reliably low VOC emissions. Therefore, the pneumatic 

controller requirements in the final rule apply only to affected facilities located between the 

wellhead and the point of custody transfer to the natural gas transmission and storage segment.
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2.10 Other Comments

2.10.1 Use of Data from the Natural Gas STAR Program

Comment: Three commenters (3350, 3528, 4160) question the need for command and control 

regulations when the Natural Gas STAR program is an available, successful, voluntary 

partnership program, which has achieved emissions reductions of VOC along with methane 

reductions. One commenter (3350) states that the EPA is required under EO 13563, to the extent 

possible, to “identify and consider regulatory approaches that reduce burdens and maintain 

flexibility and freedom of choice for the public.” The commenter states that regulating industry 

now ignores the significant progress toward emissions reductions that have been made through 

voluntary programs. The commenter states that the EPA acknowledges the achievements of this 

program in the reductions of methane (and CO2e) through the implementation of cost-effective 

technologies and practices. The commenter believes the EPA should consider whether the 

existing programs to control natural gas emissions are sufficient to achieve the desired result 

without the need for new regulation, or whether existing voluntary programs or incentives could 

be improved to achieve these results. One commenter (3528) adds that continuing to build upon 

the gas savings and emission reduction efforts already achieved through the Natural Gas STAR 

program may be a better approach than a new ruling, much of which is covered in various state 

air quality regulations and oil and gas commissions. 

Response: While we agree that the Natural Gas STAR program has been beneficial, the EPA is 

not free to abandon rulemaking under the CAA. We are required periodically to review the 

source categories listed pursuant to the NSPS and NESHAP programs, and we are required to 

regulate emissions from those source categories as prescribed by the CAA. In addition, we note 

that the Natural Gas Star program is voluntary, so there are no provisions in place to assure the 

public and regulatory agencies that compliance is being achieved on a continuous basis. Also, as 

a voluntary program, there is no assurance that facilities will in the future continue to participate 

in the program.

Comment: Three commenters (4104, 4228, 4249) believe that the EPA has relied upon limited 

information derived from the Natural Gas STAR methane reporting program to support the 

proposed standards. The commenters believe these select data are not representative of the 

industry, are not indicative of "average" operations, and are not appropriate for rule 

development. The commenters believe that the resulting EPA emissions and controls data and 

analysis are flawed and do not reliably establish that subpart OOOO would achieve meaningful, 

cost-effective VOC emission reductions for the affected emission sources. The commenters state 

that, because this is a voluntary program, companies naturally selected projects with the greatest 

potential for natural gas emissions reductions at the lowest cost. The commenters state that nonverified data were used in the STAR program, and many of the reductions were reported using 
222

optimistic data or “best of the best” opportunities or scenarios to highlight various companyspecific efforts. According to the commenters, the Natural Gas STAR data were not 

systematically collected to be representative of the industry, were not collected for the purpose of 

regulatory development, and are subject to a high emissions reduction bias and a low cost bias 

due to common sense project selection incentives. The commenters state that the Natural Gas 

STAR data were developed for completely different purposes and are wholly inappropriate for 

rule development. The commenters believe that using those data violates the good intentions of 

industry participants in a voluntary program.

One commenter (4104) adds that information in the preamble to the proposed rule demonstrates 

deficiencies in Natural Gas STAR data or related historical data, and these data have a tendency 

to inaccurately represent industry “average” operations. The commenter states, for example, that 

the EPA indicates that compressor usage rates at natural gas transmission and storage facilities 

are 79 and 68 percent, respectively. The commenter states these utilization rates are up to two or 

more times higher than actual average utilization for these two sectors. The commenter believes 

the EPA’s reliance on biased data can result in inappropriate perceptions of operations and 

emission reduction over-estimates. 

One commenter (4216) points out specific analytical flaws resulting from the misuse and 

inaccurate application of Natural Gas STAR program data collected from a small number of 

wells to assume industry-wide emission rates — based on the erroneous assumption that methane 

reported as captured through “green completions” would otherwise be vented to the atmosphere 

when a green completion is not performed.

Four commenters (4104, 4228, 4249, 4265) assert the EPA has repeatedly stated that the intent of 

subpart W reporting is to inform future rulemakings to address natural gas venting and 

equipment leaks, and initial subpart W reports will not be submitted until September 2012. Until 

data from subpart W reporting is available, the commenters believe the EPA’s cost-benefit 

analysis lacks a reliable foundation and regulating natural gas transmission and storage sources 

through subpart OOOO is premature. According to one commenter (4228), basing subpart 

OOOO on Natural Gas STAR data implies that the subpart W objective to inform future 

rulemakings has already been achieved. The commenter believes that if emission sources are 

regulated under subpart OOOO, then subpart W reporting of these emission sources should no 

longer be required. The commenter adds that NSPS for associated emission sources should not 

be proposed until subpart W emissions data have been collected for a sufficient time such that

natural gas VOC emissions can be accurately quantified and cost-effective control requirements 

can be identified.

Two commenters (4249, 4265) believe a full data set of emissions from the natural gas sector, 

preferably several years’ worth of data, will provide much more robust information upon which 
223

to base NSPS for this rule. The commenters add that it is expected that the required signature of 

a Designated Representative on the final subpart W report submittal will heighten awareness of 

emission leaks from the natural gas industry, and it is expected to drive further emission 

reductions in the absence of a mandatory emission reduction program.

Response: The EPA bases its regulations on the best available data. There is a variety of data 

sources that inform VOC emissions estimates and control technologies from the oil and gas 

industry. These include data from the U.S. inventory, Natural Gas STAR Program, State 

programs, and other published studies and materials. The EPA deemed this body of data 

comprehensive and of an appropriate level of quality and certainty such that action on VOC 

emissions could be addressed under the current NSPS Subpart OOOO. The EPA conducted 

detailed analyses to evaluate available data and information, including Gas STAR information, in 

the proposed and final rule impacts analyses to assess applicability, emission reduction potential, 

and other key factors in developing emission control standards. 

In addition, during the comment period, several commenters provided supplemental data for our 

consideration where they felt our original data was insufficient. We welcomed these submissions 

and reviewed all data presented to us. Where that data was credible and verifiable, we adjusted 

our analyses using the new data. Since the public had ample opportunity to review our data and 

submit new data, we believe the data set on which the final rule is based represents the best data 

available to the EPA at this time.

While the EPA based this regulation on an extensive body of published studies, data, and 

literature, the EPA will continue to evaluate and update our emissions estimates as new data and 

information become available. In particular, subpart W of the Greenhouse Gas Reporting rule 

will provide detailed facility level data on greenhouse gas emissions from the oil and gas 

industry which is indeed of value to the Agency in regard to informing our oil and gas emissions 

data and as well as future policy considerations. 

Response: During development of the proposed rule, there were a number of areas in which the 

EPA had insufficient data to determine the current level of control, effectiveness of control 

technologies, and cost of controls. One source we used to help fill these data gaps was the 

Natural Gas STAR program. A wide variety of data on emission reduction methods and the cost 

of those methods was publicly available through detailed technical information developed by the 

EPA in collaboration with industry partners . We assumed that the data reported by the industry 

partners is truthful, accurate, and not misleading, even though this is a voluntary program. We 

note that we also used data from the NEI and the RBLC.

Several commenters provided supplemental data for our consideration where they felt our 

original data was insufficient. We welcomed these submissions and reviewed all data presented 
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to us. Where that data was credible and verifiable, we adjusted our analyses using the new data. 

Since the public had ample opportunity to review our data and submit new data, we believe the 

data set on which the final rule is based represents the best data available to the EPA at this time.

2.10.2 VOC Content of Natural Gas

Comment: Several commenters (4104, 4174, 4192, 4217, 4225, 4241, 4252, 4266) believe the 

EPA must establish a minimum VOC content for determining applicability for controlling 

sources of VOC. The commenters suggest that a VOC content of 10 percent by weight or higher 

should be required to categorize equipment "in VOC service" and only affected sources in VOC 

service should be subject to the NSPS. Commenter 4217 notes that, without a minimum 

applicability threshold for VOCs in natural gas, the regulations will require controls on coal-bed 

methane (mainly methane and no VOCs) and other low-VOC natural gas sources where the costbenefit for VOC controls has not been justified. The commenter operates exploration and 

production facilities where natural gas is produced with no measurable VOC. Two commenters 

(4104, 4192) also provide examples of low VOC content gas. 

Several commenters (4104, 4164, 4192, 4219, 4225, 4228, 4229, 4234, 4241, 4246, 4249, 4252, 

4254, 4258, 4263,4265, 4266) believe this issue can be remedied by establishing a natural gas 

minimum VOC threshold to ensure cost effectiveness as required by the CAA. The commenters 

believe the EPA should define an “in VOC service” threshold of greater than or equal to 10 

percent by weight, as is the current requirement in other subparts such as KKK. Similarly, the 

commenters note that §60.5400(f) of the proposed rule retains this threshold for an affected gas 

processing source. According to the commenters, applicability sections of the rule for 

completions, pneumatics, and LDAR would then be limited to those facilities in VOC service. 

One commenter (4225) adds that, considering that the EPA calculated cost effectiveness (in $/ton

of VOC reduced) based on natural gas that is 18 percent by weight VOC, a 10 percent threshold 

for “in VOC service” seems quite reasonable. The commenter believes the EPA must 

economically justify its regulations for not just the average “model” facility, but for reasonably 

expected variations. 

One commenter (4266) adds that the average VOC content for shale gas production, the fastest 

growing sector of the natural gas industry, is only 2.95 percent by weight, and the average VOC 

content is 2.35 percent by weight for the natural gas transmission segment. The commenter 

calculated the cost effectiveness for the compositions the EPA included in the docket for 

determining an “average natural gas stream” (in Attachment G, RIA Review for Completions, 

Table G-6) and reports their estimated cost effectiveness numbers as being $4,814/ton at 17.95

percent by weight VOC, $8,564 at 10.09 percent by weight VOC, and $16,552/ton at 4.81 

percent by weight VOC. The commenter asserts that their estimates mean that the cost benefit 

approaches infinite $/ton of VOC for gas with no VOC content (i.e., CBM and some of the shale 
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gas fields). The commenter states that, when compared to the other cost effectiveness decisions 

that the EPA made in determining regulatory strategies in the TSD, restricting these regulations 

to streams “in VOC service,” seems reasonable.

One commenter (4263) recommends adding a definition for “in VOC service” consistent with 

subpart VVa. Another commenter (4266) recommends that the EPA add a definition of “in VOC 

service” consistent with subparts VV, GGG and KKK. One commenter (4104) states that if 

requirements for transmission and storage sources are retained in subpart OOOO, only 

equipment “in VOC service” should be affected sources. The commenter states that similar to the 

subpart OOOO provision contained in §60.5400(f) for the onshore natural gas processing 

segment, equipment in VOC service would be based on natural gas streams that exceed 10 

percent by weight VOC. The commenter adds that this percent by weight threshold precedent is 

consistent with the current NSPS subparts KKK and VVa. 

Response: It is the EPA’s intent that subpart OOOO regulate significant sources of VOC 

emissions. However, we do not agree that a global “in VOC service” exemption is warranted for 

this source category. A threshold based on “in VOC service” introduces the possibility that an 

emission source with a low VOC concentration, high volume throughput which does not meet 

the definition of “in VOC service” could escape control yet have appreciable emissions. 

However, certain revisions we have made since proposal, though made for different reasons, 

would also address the concerns of these commenters. For instance, we are not currently 

finalizing standards for pneumatic controllers and compressors in the transmission and storage 

and distribution segments. For storage vessels, we have converted the proposed throughput 

threshold to 6 tpy of VOC emissions, which we had determined in the proposal to approximate 

the VOC emissions from the proposed throughput.

We believe that the changes described above will eliminate the likelihood of regulating sources 

with little or no VOC while requiring controls on those with appreciable emissions.

2.10.3 Assessing Co-benefits from Greenhouse Gas Emission Reductions

Comment: One commenter (4178) provides quantitative information on the amount of methane 

emissions from oil and gas exploration and production, concluding that 2.8 percent of global 

anthropogenic methane emissions from the U.S. are from oil and gas exploration and production. 

The commenter states that if 100 percent of the methane is removed from oil and gas, it would 

achieve an overall reduction of methane emissions of approximately 2.8 percent.

One commenter (4178) notes that the proposed rule states that methane is an ozone precursor and 

that a reduction in methane emissions will reduce ozone exposure. The commenter adds that this 
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statement is repeated in the RIA, which also references the article, “Linking ozone pollution and 

climate change: The case for controlling methane.” The commenter believes that the reductions 

of ozone obtained therein assumed the unrealistic and unsupported proposition of a 50 percent

reduction in anthropogenic methane emissions, not the 2.8 percent that might result from this 

proposed rule. Using the results of the cited article, the commenter asserts a 2.8 percent reduction 

will yield a 0.2 ppb reduction in background ozone. 

One commenter (4240) states that the EPA has identified natural gas systems as the “single 

largest contributor to United States anthropogenic methane emissions.” The commenter states 

that industry is responsible for over 40 percent of total U.S. methane emissions, which amounts 

to 5 percent of all carbon dioxide equivalent (CO2e) emissions in the country. 

One commenter (4275) states that controlling methane will help to offset high CO2 emissions 

from the oil and gas industry in some regions. The commenter states that CO2 entrained in the 

gas is removed using acid gas removal units at natural gas processing facilities, and then vented 

to the atmosphere. Thus, the commenter states, on top of the methane emissions from leaks, well 

completions, and other sources, CBM wells release CO2. The commenter states CBM producers 

in the San Juan Basin and other regions were required to use RECs, the methane reductions

would help offset the currently uncontrolled release of CO2.

One commenter (4104) believes the EPA should abide by the current convention for reporting in 

the U.S. (e.g., under the GHG reporting rule, subpart W). The commenter estimates methane 

(and VOC) reductions are likely to be biased high, because the EPA inappropriately relies on 

information from the voluntary Natural Gas STAR program. The commenter believes these 

estimates could be improved once data is available from the GHG reporting rule, but initial 

subpart W reporting of emissions for natural gas systems will not occur until September 2012. 

The commenter believes it is premature for the EPA to credibly estimate emissions, let alone 

monetize estimated emission reductions, until subpart W data are available.

Response: We appreciate the thorough information provided by these commenters.

2.10.4 Harmonization with Other Rules

Comment: One commenter (4251) states that the EPA should assure the language used and 

definitions cited in the rule are concurrent with the language and associated definitions in subpart 

W to streamline data gathering, compliance and reporting for industry. The commenter states 

both subpart W and this NSPS cover many of the same emission sources, including pneumatic 

controllers, tanks, completion/recompletion events, and compressors with varying definitions 

between the rules. The commenter adds that the definition of “facility” is drastically different (in 

subpart OOOO an “affected facility” is one pneumatic controller or one tank for example; in 

subpart W, a “facility” is an entire basin, for the onshore petroleum and natural gas production 
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industry segment) adding more confusion to an already complex rule with a short time frame for 

understanding and compliance. 

Three commenters (4104, 4159, 4228) state that the EPA should harmonize nomenclature with 

the GHG mandatory reporting rule for petroleum and natural gas systems (40 CFR, Part 98, 

subparts W and A) and provided a number of recommendations. 

Response: We appreciate the need to harmonize different rules that apply to similar industries. 

However, each regulatory program has varying goals and enabling laws that in some instances 

require us to take different approaches. While we have strived to harmonize definitions as much 

as possible, the differing requirements of the various regulatory programs limit our ability to 

provide complete harmonization.

Comment: One commenter (4219) states that reduction of the number of cross-references would 

also be consistent with the criticism the EPA has launched at certain state programs. The 

commenter notes, for example, the EPA has repeatedly criticized TCEQ for using incorporation 

by reference rather than spelling out the terms of the applicable requirements in the state’s title V 

program. The commenter adds that the EPA should clarify that any facility that once was, but no 

longer is, covered by subpart OOOO would similarly no longer be covered by any of the part 63 

requirements that are incorporated into subpart OOOO by cross-reference. Because the MACT 

rules have a once-in/always-in feature, the commenter believes clarification is needed so subpart 

OOOO-covered sources that are subject to the MACT rules via cross-referencing will not always 

be subject to those rules when they are no longer subject to subpart OOOO. The commenter adds 

this is another reason why cross-referencing is inappropriate; if the applicable standards were 

stated in full in subpart OOOO, rather than through the shorthand convention of crossreferencing, then possible misapplication of the MACT rules would not exist. The commenter 

believes cross-referencing raises questions as to whether generalized attributes of the referenced 

rule regime - here the MACT rules once-in-always-in feature - are being imported along with the 

specifically referenced rules.

Response: As discussed previously, we have eliminated the cross-referencing to 40 CFR part 63, 

subpart HH in the final rule. 

Comment: One commenter (4263) states that the EPA should delete §60.5365(f)(5) because the 

cited rules (part 60 subparts GGG and GGGa) apply to petroleum refineries. The commenter 

states that no natural gas processing plant, as defined in the proposed rule at §60.5430, would be 

co-located with a petroleum refinery. Furthermore, the commenter states that subpart VVa 

applies to SOCMI facilities and no SOCMI facility would be co-located with a natural gas 

processing plant. The commenter adds that subpart OOOO cross-references requirements in 

subpart VVa, but subpart VVa does not apply to gas plants.
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Response: The cross-referenced rules do not have to apply to the affected facilities in subpart 

OOOO. We are simply referring to specific provisions within those rules to avoid duplicating 

identical requirements throughout many rules.

Comment: One commenter (4217) notes cross-referencing concerns mainly in the requirements 

for LDAR and storage vessels. The commenter is especially concerned with the referencing for 

the storage vessels requirements because the EPA uses the NESHAP subpart HH, a rule for the 

control of HAP, as the source for the reference. The commenter believes that NESHAP standards 

are not an appropriate source for requirements under NSPS because they are typically the most 

stringent requirements to control HAPs and not necessarily the best demonstrated technology (or 

BSER) for controlling VOCs. The commenter adds that, occasionally, the reference the EPA 

uses contains emissions limits, performance standards, test methods, etc. for total HAPs or a 

specific HAP. The commenter believes it is unclear how an owner/operator should apply a 

requirement referencing HAPs to a VOC standard. 

One commenter (4219) notes that part 63 requirements may be appropriate for HAPs but they are 

overkill as applied to section 111 sources of VOC emissions, many of which are small sources of 

minimal emissions. The commenter notes, for example, the storage vessel rule of subpart OOOO 

covers tanks with as little as 1 bbl of condensate throughput per day, which equates to only 0.5 

tpy VOC, yet the efficiency standard for the controls for storage vessels is expressed by 

reference to the MACT standards set forth in part 63 for hazardous emissions. 

One commenter (4246) states that MACT standards are excessive for the small sources regulated 

under subpart OOOO. The commenter believes MACT subpart HH is a complicated regulation, 

particularly for smaller companies that typically lack in-house environmental staffing capable of 

handling the complex intricacies of the requirements. The commenter adds that many natural gas 

processing facilities do not have the financial resources to add the level of staffing necessary to 

interpret and implement this complicated and confusing regulation and typically use contractor 

staffing for component monitoring and the initial regulatory interpretation, but much of the 

periodic testing, monitoring, reporting and recordkeeping fall on the local operating staff.

Response: 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. Regarding recordkeeping and reporting, 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. We also 

considered a variety of innovative compliance approaches that could maximize compliance and 

transparency while minimizing burden on the regulated community and regulators.
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Comment: Two commenters (4218, 4246) state that the control standards for storage vessels 

should be revised to accommodate the use of VRUs that capture and route storage tank emissions 

to the inlet of the gas processing plant. The commenters are concerned that the storage vessel 

standards in the cross-referenced NESHAP subpart HH standards do not accommodate the VRUs 

that are used to control storage vessel emissions at many compressor stations and gas processing 

plants that are existing subpart HH major sources. 

One commenter (4218) adds that the description of a vapor recovery device as used in 

§63.771(d)(1)(ii) does not describe the commenter’s VRUs, which do not reduce the TOC or 

HAP content of the gas they receive. Furthermore, the commenter believes the performance test 

procedures set forth in §63.772(e)(3)(iii) do not make sense for these VRUs because the 

procedures require the measurement and comparison of the mass rate of TOC or HAP at the inlet 

and outlet of the control device and believes these provisions should be revised.

Response: In the final rule, we have revised the storage vessel requirements to state that 95 

percent control of VOC emissions must be achieved. The owner or operator is free to use any 

control technology, so long as compliance with the emission reduction requirement can be 

demonstrated. We believe that this change eliminates the commenters’ concerns.

Comment: One commenter (4267) states that the proposed rule conflicts with existing BLM, 

Tribal, Federal, State, county and city regulations. The commenter argues that the State and 

BLM already get reports on completions so another completion report to the EPA is needless 

duplication that costs money with no real environmental benefit. 

Response: We revised the reporting requirements to allow the use, wherever possible, of reports 

already created for other purposes, so long as the current reports contain all of the information 

required by the final rule. We also reduced the reporting requirements to include only those that 

we believe are necessary to demonstrate compliance and inform regulatory agencies of relevant 

activities at the facility.

2.10.5 Relationship to 40 CFR 98, Subpart W

Comment: One commenter (4104) describes conflicts in the EPA’s objectives under subpart 

OOOO and subpart W. The commenter states that in developing subpart W, the EPA has 

consistently identified a primary objective of “informing future rulemakings” associated with

sources that report GHGs, including natural gas venting and equipment leak sources that report 

under subpart W. In subpart OOOO, the commenter states the EPA has decided which sources 

warrant control – i.e., three of the six subpart W reportable sources for transmission and three of 

the four subpart W reportable sources for underground storage are affected sources in subpart 
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OOOO. In addition, the commenter states that the EPA has specifically excluded other sources 

from subpart OOOO (e.g., equipment leaks in the transmission and storage segment). The 

commenter states that subpart OOOO would regulate pneumatic controllers and compressors 

despite the fact that the initial subpart W reports for petroleum and natural gas systems will not 

be submitted until September 2012. The commenter believes the proposed rule is pursuing 

emission reductions prior to acquiring pertinent subpart W reporting data. The commenter adds 

that the EPA inappropriately relies upon data reported in a voluntary program designed for 

completely different purposes. The commenter believes the overlap between subpart OOOO and 

subpart W and related objectives imply an obvious conclusion: both regulations are not 

warranted at this time and either subpart W reporting for transmission and underground storage 

should be rescinded (because the EPA believes it has enough information to impose emission 

reduction regulations) or transmission and underground storage requirements in the proposed 

rule should be eliminated from the final rule pending collection of emissions data to inform 

rulemakings for sources of natural gas venting and equipment leaks. 

Response: Regarding comments on subpart W and Natural Gas STAR Program data, please see 

previous comment response. We also clarify that the final rule requirements for reciprocating 

compressors, centrifugal compressors and pneumatic controllers apply to affected facilities 

located between the wellhead and the point at which the gas enters the transmission and storage 

segment. Please refer to section IV of the preamble to the final rule.

Comment: One commenter (4243) notes that the proposed green well completion NSPS have 

important implications for estimating the GHG footprint of natural gas. The commenter states 

that although the annual “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009”

showed a decrease in methane and other GHG emissions from the natural gas distribution sector, 

the inventory offset this decrease with a significant increase in estimated emissions from natural 

gas production. The commenter argues that this is largely because the Inventory vastly overestimated the methane emissions from shale gas well completions using hydraulic fracturing, by 

assuming erroneously that no well completions are performed using methane-capturing green 

well completion technology. The commenter notes that many producers are already using this 

technology voluntarily on most of their well completions. The commenter believes the EPA 

should revise the upcoming annual Inventory to reflect the actual percentage of well completions 

that used green well completions in recent years, and to note that this percentage is likely to 

increase each year – both through voluntary action and through compliance with the mandatory 

provisions of the green well completion NSPS, if made final.

Response: Please refer to section 2.2.3.3 of this Responses to Comments document (entitled 

Accuracy of Cost Estimate for REC Performed by a Contractor, Given the Estimated Number of 

Wells in 2015). 
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2.10.6 Proposed Standards Would Apply to Affected Facilities that Commence 

Construction, Reconstruction, or Modification After August 23, 2011

Comment: Several commenters (2803, 4168, 4192, 4209, 4215, 4218, 4219, 4231, 4244, 4246, 

4254, 4266, 4317, 4320, 4358) request that the compliance deadline for affected facilities be 

extended. The commenters provided numerous examples justifying delays ranging from 60 days 

to 4 years. One commenter (4266) states that the compliance dates of the final rule need to be 

extended to at least the effective date (60 days after the publication in the Federal Register) to 

comply with the Congressional Review Act. 

Response: We remind the commenters that subpart OOOO applies to new, reconstructed or 

modified affected facilities, not existing affected facilities. Upon promulgation of the final rule, 

existing affected facilities will not have to be replaced or controls installed until the existing 

affected facility is reconstructed or modified. The final rule states that all affected facilities must 

be in compliance on the effective date, which is 60 days after promulgation of the rule.

However, due to 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 (non-exploratory and 

non-delineation wells) on or before January 1, 2015. Completion operations at category (1) wells 

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

pressure wells) begun prior to January 1, 2015 are now required to perform REC or route the 

flowback emissions to a completion combustion device unless it is technically infeasible or 

unsafe to do so. Similarly, we are providing a one-year compliance phase-in for pneumatic 

controllers at natural gas processing plants and for storage vessels with VOC emissions equal to 

or greater than 6 tpy.

Comment: Two commenters (4275, 4240) argue that existing sources should be regulated under 

NSPS using emission guidelines. The commenters describe section 111 requirements and note 

that the EPA listed Crude Oil and Natural Gas Production on its “priority” list of categories that 

“cause[s], or contribute[s] significantly to, air pollution” which endangers human health and 

welfare in 1979. Thus, the commenters state the EPA is obligated to promulgate NSPS for 

sources within this category which includes a wide range of equipment, but has only issued two 

performance standards for this category. The commenters state these standards are inadequate 

because they apply only to a fraction of the sources located within the source category and only 

to two of the many types of air pollutants emitted from these sources. According to the 

commenters, although existing sources create the largest portion of emissions from oil and gas, 

the EPA still has not created emission guidelines to reduce air pollution from existing sources. 

The commenters state that the CAA requires the EPA to issue emission guidelines for existing 

sources once it establishes an NSPS for a category of new sources.
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Response: Whereas CAA section 112 standards are issued for new and existing stationary 

sources, standards of performance under section 111 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.
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3.0 Comments Regarding Subpart HH and Subpart HHH

3.1 Representativeness and Comprehensiveness of NEI Data Used in Analyses

Comment: One commenter (4230) notes that it appears the EPA is missing accurate facility and 

emissions information for sources in West Virginia for the risk analysis and the commenter 

suggests revisions. Specifically the commenter states that their only major source subject to 

subpart HHH has been mischaracterized as subject to subpart HH instead. The commenter 

requests that the EPA remove the Columbia Gas Adaline station from the subpart HHH major 

source designation, and add Dominion's Lightbum station (041-00013) as a major source subject 

to this regulation. Further, the commenter states that of West Virginia's 60 title V major facilities 

that relate to oil and gas, 34 have dehydrators. The commenter also contends that the EPA only 

listed 21 such facilities as area sources subject to subpart HH. 

Therefore, the commenter believes that a significant number of facilities in West Virginia are 

missing from the EPA's data for subpart HH. The commenter states that a separate submittal of 

data corrections will be made.

Response: We are conducting a residual risk review of the major source MACT standards in 

subpart HH. As such, the focus of the review is on the major sources subject to the MACT 

standards in subpart HH. The commenter did not submit substantiating data to the EPA other 

than what was provided in the comment letter. Therefore, we were unable to make specific 

determinations on the facilities mentioned by the commenter. However, as discussed in the 

preamble and Memorandum titled, “Changes to Risk Assessment Facility Information for the Oil 

and Natural Gas Production and Natural Gas Transmission and Storage Source Categories,” 

dated February 8, 2012, we re-evaluated the emissions associated with several facilities in 

response to comments received on the proposal. As a result, we identified certain sources that 

were area sources that should not have been included in the risk assessment, and some of those 

facilities include facilities in West Virginia.

Comment: Regarding the EPA’s request for data estimating the number of major sources in the 

upstream and transmission sectors, two commenters (4192, 4246) state that, in the limited 

amount of time available for comment, they were not able obtain this information. 

Response: The preamble to the proposed rule originally provided for a 60-day comment period. 

The EPA received numerous requests for extending the public comment period and, based on the 

information provided in the requests, the EPA determined that an extension of 30 days was 

appropriate. We believe that the extended public comment period was sufficient as evidenced by 

the large number and detail of the responses received. Moreover, often a proposed rule asks for 

commenters to provide additional information and data. The fact that the commenters did not 
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provide the information requested is not material. The Agency made a request for information 

and reasonably based the final rule on the information currently available to it, including 

information submitted through comments.

Comment: One commenter (4270) states that after performing its NESHAP analysis for subpart 

HHH using data on 321 sources from the NEI, the EPA did not perform any subsequent analysis 

for facility type, age, location and other variables that could change emission characteristics. 

Before proposing performance and emission standards, the commenter believes that the EPA 

needs to broaden the data set to account for these variables.

Response: We believe that the NEI dataset used in both the technology review and the risk 

review is the best available data for emissions from the natural gas transmission and storage 

source category. The NEI includes data for over 300 facilities with a MACT code associated 

with this source category, which is approximately the number of major sources we estimate are 

in the category. The factors cited by the commenter (i.e., facility type, age, location, etc.) should 

be reflected in the NEI emissions data. In addition to emissions, the risk review conducted under 

section 112(f)(2) also takes into account emission point characteristics such as release type, 

release height, velocity and temperature, and that information is also contained in the NEI. . 

3.2. Previously Unregulated Sources

Comment: One commenter (4457) supports the EPA’s proposal to set a MACT standard for the 

first time for small glycol dehydrators and previously uncontrolled storage vessels. 

Response: We appreciate the commenter’s support. The final rule establishes MACT standards 

pursuant to section 112(d)(2) and (d)(3) for the subcategory of small glycol dehydrators. 

However, based on the comments received, we are not finalizing the MACT standard for the 

subcategory of storage vessels without the PFE, which was a subcategory that was left 

unregulated in the initial MACT standards. We believe that we need additional data and 

information to set emission standards for storage vessels without the PFE, and we intend to 

collect additional data and propose MACT emission standards under section 112(d)(2) & (3) of 

the CAA for such storage vessels. 

Comment: Two commenters (4230, 4241) question whether the EPA would still consider small 

dehydrators at major sources having a throughput of less than 85,000 scmd or actual average 

benzene emissions less than 0.9 Mg/yr to be major for HAPs while meeting the exemption 

conditions. The commenters explain that, under their State requirements, this subcategory of 

sources has been successful in obtaining synthetic minor permits to reduce their emissions to 

below the 0.9 Mg/yr, and the use of controls allows them to be reclassified as an area source of 

HAPs. Therefore, according to the commenter, any existing source which installed controls 
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before the end of their 3-year compliance deadline would now be exempt from the major source 

requirements by their State. The commenter inquires how the EPA envisions the excess risk to be 

addressed if most of the sources no longer qualify as a major source of HAPs. The commenters 

also ask whether the EPA’s finding of excess risk extends to the area source program, which also 

uses the same exemption and seems to encompass the majority of sources described as "small 

dehydrators." 

Response: The final amendments do not apply to area sources. They apply to small glycol 

dehydration units located at major sources of HAP. As discussed at proposal [76 FR 52767], we 

only conducted the risk assessment for facilities designated as major sources of HAP, as the risk 

assessment under 112(f)(2) is not required to extend to area sources which are subject to 

generally available control technology (i.e., GACT) standards and not MACT. In addition, small 

glycol dehydration unit s are defined as only being located at major sources of HAP. 

Nonetheless, we believe, the number of major sources in the oil and natural gas sector are likely 

to be overestimated because the major source designation in the NEI does not take into account 

the limitations set forth in section 112(n)(4) of the CAA regarding aggregation of emissions from 

wells and associated equipment in determining major source status. Therefore, we believe that 

our risk assessment covers many of the dehydration units for which the commenter was 

concerned.

Comment: One commenter (4241) requests that the EPA clarify that a “small glycol dehydration 

unit” would not lose its classification as a “small” unit if it has an excursion that results in actual 

emissions in excess of 1 tpy (0.9 Mg/yr). The commenter suggests that such a small “synthetic 

minor” dehydrator that availed itself of the 1 tpy compliance option by securing a federally 

enforceable emission limit of less than 1 tpy benzene emissions should not be considered large 

under revised rules if it has an excursion, provided that the 1 tpy exemption was part of a 

federally enforceable permit prior to the effective date of the final rule.

Response: The commenter is correct that a glycol dehydration unit that qualifies as a small 

dehydration unit by accepting a 1 tpy benzene emissions federally enforceable limit would not 

lose its classification if it has an excursion that results in actual emissions greater than 1 tpy. 

However, the commenter should be aware that any excursion may be a violation of their permit.

Comment: One commenter (4189) states that the EPA should require at least 98 to 99 percent 

control efficiency for storage tanks and dehydrators, to match what some jurisdictions already 

require, instead of the proposed 95 percent.

Response: To the extent the commenter is referring to the standards we proposed on August 23, 

2011 for storage vessels without the PFE, we are not finalizing those requirements, as discussed 
236

in the preamble. For the standards being finalized for small glycol dehydrators, those units must 

meet a BTEX emissions limit, not a percent reduction requirement, so the commenter’s 

suggestion is not applicable. 

3.2.1 Legal Authority

Comment: Four commenters (4271, 4220, 4266, 4273) dispute the EPA’s regulatory authority to 

revise existing MACT standards pursuant to section 112(d)(2) and (3), which they assert is 

unrelated to the section 112(d)(6) technology review or the section 112(f)(2) residual risk 

determination requirements. 

One commenter (4266) states that the EPA’s own statements in the preamble make it clear that 

EPA is not invoking section 112(d)(6) as the authority for the new proposed standards and that 

the preamble provides no analysis of “developments in practices, processes, and control 

technologies” to justify the proposed standards under section 112(d)(6). 

One commenter (4273) states that the EPA has expressly recognized that section 112(d)(6) does 

not require reanalysis of the floor pursuant to section 112(d)(3) during the 8-year technology 

reviews. 76 FR at 52741 (citing NRDC v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008)). In 

particular, the commenter states that, in NRDC v. EPA, the D.C. Circuit upheld the EPA’s 

interpretation that the periodic review requirement in CAA section 112(d)(6) does not impose an 

obligation to recalculate MACT floors. 529 F.3d at 1084. Rather, according to the commenter, 

the review and revise provisions require the EPA only to consider developments in pollution 

control at the sources and to revise the standards based on an evaluation of costs, non-air quality 

effects, and related energy implications. See 71 FR 76603, 76608-76609 (Dec. 21, 2006) (noting 

EPA has discretion to weigh “all relevant factors” in section 112(d)(6) review). 

Two commenters (4266, 4273) believe that section 112(d)(6) requires the Administrator to 

review and revise emission standards “as necessary,” and that the EPA has significant discretion 

to interpret “as necessary” to mean less than a full-blown MACT floor re-calculation. One 

commenter provides that perceived “gaps” in the original MACT determinations are not 

“practices, processes, and control technologies” that are within the scope of a section 112(d)(6) 

review and the EPA does not have unfettered discretion to revisit a prior MACT determination 

once that determination has been issued unless it is determined to be “necessary” according to 

explicit criteria. 

One commenter (4189) opines that, in order for the EPA to meet its legal obligations under 

section 112(d) of the Act, the EPA must update the maximum achievable control technology 

(MACT) standard based on current data and information. The commenter states that the EPA 
237

must both expeditiously promulgate the vitally important standards for previously uncovered 

sources and update the now stale 1999 standards to remedy the deficiencies set forth above. 

Three commenters (4217, 4266, 4273) argue that the EPA does not have the legal authority to 

revise the prior MACT floor. These commenters state that removal of the applicability to limit 

the major source definition to only storage vessels with the potential for flash emissions is 

essentially redoing the MACT floor. The commenters argue that the EPA is attempting to 

supplement the MACT floor analysis conducted in 1997, which they did not believe was within 

the scope of section 112(d)(6).

One commenter (4159) states that the EPA lacks the authority to conduct a new MACT floor 

analysis of standards currently in effect. The statute contemplates a one-time setting of the 

MACT floor. According to the commenter, recent case law on MACT floor setting does not 

require the EPA to reassess the floors for all MACT standards. The commenter asserts that once 

the EPA conducts its residual risk review and determines that the emissions are protective with 

an ample margin of safety, requiring further emission reductions through revisions to the MACT 

standards are both contrary to law and bad policy.

One commenter (4457) states that the EPA is correct in recognizing that, under the statute, a 

MACT limit is needed for previously uncontrolled sources that emit HAPs in significant 

quantities, including all storage vessels in the Oil and Natural Gas Production source category. 

One commenter (4273) asserts that the setting of the MACT floor under section 112(d) is a onetime requirement. The commenter explains their position by stating that Congress has made 

distinctions between the initial “promulgation” of a standard and its “revision” throughout the 

CAA. According to the commenter, unlike in section 112(d), Congress has expressly provided 

the EPA authority to revise standards in the same manner as the initial promulgation for other 

standards in the Act. See, e.g., 42 U.S.C. §§7409(b)(1) (“Such primary standards may be revised 

in the same manner as promulgated.”); 7409(b)(2) (“Such secondary standards may be revised in 

the same manner as promulgated.”). Again, according to the commenter, in amending section 

112, Congress was concerned with the EPA’s delay in promulgating health-based standards for 

HAPs. The MACT provisions were carefully crafted to ensure that an interim technology-based 

standard would be established until the EPA could promulgate a health-based standard. See

generally Sierra Club v. EPA, 353 F.3d 976, 979-80 (D.C. Cir. 2004). The commenter asserts 

that the EPA has recognized the “ultimate goal” of such emissions standards is protecting public 

health with an ample margin of safety. 71 FR 76,603, 76,609 (Dec. 21, 2006) (HON). However, 

the commenter states that once the EPA establishes residual risk standards, it is within EPA’s 

discretion to find further revisions are not needed due to the efficacy of the standards. 42 U.S.C. 

§7412(d)(6).
238

One commenter (4273) believes that the EPA does not have authority to revise the MACT floor 

determinations that have been incorporated into currently effective standards never invalidated 

by the D.C. Circuit, even if the floor represents sources with no control. The commenter provides 

that the time for challenging the standards at issue in the proposed rule has long since passed. 42 

U.S.C. §7607(b) (requiring any challenges to such regulations be filed within 60 days). The 60-

day deadline is “jurisdictional in nature, and may not be enlarged or altered by the courts.” Motor 

& Equip. Mfrs. Ass’n v. Nichols, 142 F.3d 449, 460 (D.C. Cir. 1998) (citation omitted); see also 

NRDC v. EPA, 571 F.3d 1245, 1265 (D.C. Cir. 2009). The commenter states that this time limit 

on seeking judicial review “serves the important purpose of imparting finality into the 

administrative process, thereby conserving administrative resources and protecting the reliance 

interests of regulatees who conform their conduct to the regulations.” NRDC v. Nuclear Reg. 

Comm’n, 666 F.2d 595, 602 (D.C. Cir. 1981); see also Sun Enters., Ltd. v. Train, 532 F.2d 280, 

292 (2d Cir. 1976) (noting, in finding a petition to review NPDES permit untimely, “the equities 

. . . lie heavily with the intervenors who have proceeded at great expense in reliance on the 

permit and who cannot be charged with any deficiencies in respondent’s performance”) This 

commenter provides extensive case law support for their position in their comment letter.

One commenter (4273) asserts that the EPA also lacks authority to revisit beyond-the-floor 

analyses for sources with existing MACT standards. According to the commenter, similar to the 

EPA not being able to revisit the MACT floor, the EPA has no direct authority under sections 

112(d)(2) and (3) to revisit beyond-the-floor analyses for previously promulgated MACT 

standards which have remained in effect.

One commenter (4189) notes that the EPA’s proposed rule under sections 112(f)(2) and (d)(6) 

contains significant gaps in the sources of emissions covered. The commenter states that the EPA 

must address all significant sources of HAP that the current standards do not control, including 

wastewater pits and impoundments, well pads, well completions, and fugitive toxic air 

emissions. The commenter states that the EPA must also consider the same controls for natural 

gas transmission and storage that it is proposing for oil and natural gas production. For example, 

the commenter states that the EPA is proposing controls for storage vessels and equipment leaks 

in the production sector, but not for the same sources found in the transmission and storage 

sector (where the EPA is only proposing to regulate glycol dehydrators). Although the 

commenter is pleased that the EPA has recognized the need to regulate previously uncontrolled 

sources, the commenter believes the EPA needs to take this important opportunity to fully assess 

and address health risks from all emissions in this sector and remove all major gaps in the 

existing standard.

One commenter (4354) believes that the EPA is not authorized by section 112(d)(2) or (d)(3) to 

fill “gaps” in existing MACT standards. The commenter asserts that once the EPA establishes a 

MACT standard for a particular source category, the Agency has the authority under section 
239

112(d)(6) to “review and revise as necessary (taking into account developments in practices, 

processes, and control technologies), emissions standards promulgated under this section no less 

often than every 8 years.” The commenter contends that the EPA does not have discretion to 

revisit a prior MACT determination once that determination has been issued. The commenter 

believes that, even if the Agency had invoked section 112(d)(6) as authority for revising the 

existing MACT standards, it still would not have authority to regulate the emissions points for 

which standards were not established in the first round of MACT rulemaking. The commenter 

states that prior MACT determinations may be revised only “as necessary (taking into account 

developments in practices, processes, and control technologies.” The commenter also states that 

it is not a reasonable exercise of authority to establish new emissions limitations under existing 

MACT standards when there is no significant risk associated with emissions from sources in the 

given source category. The commenter contends that establishing new standards under these 

circumstances is unreasonable and cannot be justified under section 112(d)(6) because the socalled regulatory “gaps” in the current rules clearly are not contributing to unacceptable risk. The 

commenter asserts that even if, for the sake of argument, the EPA is correct in concluding that 

“MACT allowable” emissions cause unacceptable risk to public health, that still does not justify 

establishing new regulations for dehydrators and tanks. In the commenter’s opinion, the EPA has 

determined that the unacceptable risk can be remedied by eliminating the 0.9 Mg/yr compliance 

option. The commenter states that, even accepting the EPA’s risk analysis, further regulation of 

dehydrators and tanks clearly is not needed to adequately protect public health.

Response: In Medical Waste Institute v. EPA, 645 F. 3d 420, 425-27 (D.C. Cir. 2011), the D.C. 

Circuit held that the EPA may permissibly amend improper MACT determinations, including 

amendments to improperly promulgated floor determinations, using its authority under CAA 

section 112 (d) (2)-(3). The lack of judicial invalidation on these issues is a distinction without a 

difference. The absence of standards for these HAP is not proper. National Lime, 233 F. 3d at 

633-34; see also Medical Waste Institute, 645 F. 3d at 426 (resetting MACT floor, based on postcompliance data, permissible when originally-established floor was improperly established, and 

permissibility of EPA’s action does not turn on whether the prior standard was remanded or 

vacated).26 The D.C. Circuit’s decision in Portland Cement Ass’n v. EPA, 665 F.3d 177, 189 

 

26 It is well-settled that an agency generally remains free to revise improperly 

promulgated or otherwise unsupportable rules, even in the absence of a remand from a Court. 

United Gas Improvement Co. v. Callery Props., Inc., 382 U.S. 223, 229 (1966) (“An agency, like 

a court, can undo what is wrongfully done by virtue of its order.”); Macktal v. Chao, 286 F.3d 

822, 825–26 (5th Cir. 2002) (“[I]t is generally accepted that in the absence of a specific statutory 

limitation, an administrative agency has the inherent authority to reconsider its decisions.”). 

Agencies have particularly broad authority to revise their regulations to correct their errors. Last 

Best Beef, LLC v. Dudas, 506 F.3d 333, 340 (4th Cir. 2007); Friends of the Boundary 

WaterWilderness v. Bosworth, 437 F.3d 815, 823 (8th Cir. 2006) (“It is widely accepted that an 
240

(D.C. Cir. 2011) confirms that the EPA is not constrained by section 112 (d)(6) and it may 

reassess its standards more often, including revising MACT floors pursuant to section 112(d)(2) 

and (d)(3). The commenters are thus incorrect that EPA lacks authority to set MACT standards 

under 112(d)(2) and (d)(3) for small glycol dehydrators and storage vessels without the PFE that 

were not controlled under the initial NESHAP for the oil and gas source categories. Put another 

way, if the EPA did not adopt a proper MACT standard initially, it is not amending a MACT 

standard but adopting one for the first time. That is the case here for small glycol dehydrators 

and storage vessels that were not controlled under the initial NESHAP. The EPA adopted no 

MACT standard at all for these emission points, an approach soundly rejected by the D.C. 

Circuit in National Lime, 233 F. 3d at 633-34. Consequently, the EPA is not barred from making 

MACT floor and beyond-the-floor determinations and issuing MACT standards pursuant to 

section 112 (d)(2) and (3) in this rulemaking.

The EPA is not invoking section 112(d)(6) or 112(f)(2) as its authority to promulgate the MACT 

standards for currently uncontrolled sources. As one commenter correctly notes, the EPA is 

promulgating these MACT standards for the first time pursuant to sections 112(d)(2) and (3), the 

provisions that directly govern the promulgation of MACT standards. Using sections 112(d)(2)-

(3) ensures that the process and considerations are those associated with initially establishing a 

MACT standard. Because the EPA is not establishing these MACT standards under section 

112(d)(6), some commenters mistakenly thought that, in setting MACT standards to address 

certain unregulated sources, the EPA conducted new MACT floor analysis for standards 

currently in effect. As explained above, the EPA is promulgating new standards, not revaluating 

the original standards, under sections 112(d)(2)-(3). The EPA’s action to set MACT standards 

for small glycol dehydrators, which were not regulated in the current MACT, is consistent with 

several recent rulemakings, in which we have chosen to fix underlying defects or make other 

 

agency may, on its own initiative, reconsider its interim or even final decisions, regardless of 

whether the applicable statute and agency regulations expressly provide for such review.”) 

(citations omitted). Moreover, an agency may reconsider its methodologies and application of its 

statutory requirements and may even completely reverse course, regardless of whether a court 

has determined that its original regulation is flawed, so long as the agency explains its bases for 

doing so. Motor Vehicle Mfrs. Ass’n v. State Farm Mutual Auto Ins. Co., 463 U.S. 29, 42 (1983); 

FCC v. Fox Television Stations, Inc., 129 S. Ct. 1800, 1810 (2009); Nat’l Cable & Telecomms. 

Ass’n v. Brand X Internet Servs., 545 U.S. 967, 981–82 (2005) (internal citations omitted) (’An 

initial agency interpretation is not instantly carved in stone. On the contrary, the agency * * * 

must consider varying interpretations and the wisdom of its policy on a continuing basis,’ 

Chevron, supra at 863–864[], for example, in response to changed factual circumstances, or a 

change in administration. That is, no doubt, why in Chevron itself, this Court deferred to an 

agency interpretation that was a recent reversal of agency policy.”).
241

necessary revisions or clarifications in existing NESHAP under sections 112(d)(2) and (3), the 

provisions that directly govern the initial promulgation of MACT standards (see National 

Emission Standards for Hazardous Air Pollutants From Petroleum Refineries, October 28, 2009, 

74 FR 55670; and National Emission Standards for Hazardous Air Pollutants: Group I Polymers 

and Resins; Marine Tank Vessel Loading Operations; Pharmaceuticals Production; and the 

Printing and Publishing Industry, April 21, 2011, 76 FR 22566). 

The EPA proposed setting MACT standards for the first time for small glycol dehydrators that 

were left unregulated in the original NESHAP. Establishing standards for these emission points 

does not involve doing new MACT floor analysis for MACT standards currently in effect. In the 

original NESHAP, the EPA created two subcategories of glycol dehydrators. The EPA 

established MACT standards for one subcategory – large dehydrators - but left unregulated the 

subcategory of so-called “small dehydrators.” Therefore, the EPA is establishing for the first 

time MACT standards for the “small dehydrators” subcategory. Based on available data on 

“small glycol dehydrators,” the EPA performed the MACT floor and beyond-the floor analysis to 

determine the MACT standards for this subcategory. In doing so, the EPA did not reanalyze the 

MACT floor analysis for the standards established in the original NESHAP for the large glycol 

dehydrators.

Regarding the proposed MACT standards under section 112(d)(2) and (d)(3) for the subcategory 

of storage vessels without the PFE, we are not finalizing those standards today. Based on our 

review of the comments, we believe that we need additional data in order to set an emissions 

standard for this subcategory of storage vessels. We intend to collect the appropriate data and 

propose a MACT emission standard as appropriate under section 112(d)(2) and (3) of the CAA 

for the subcategory of storage vessels without the PFE. 

One commenter claims that sections 112(d)(6) and 112(f)(2) rules must address all significant 

sources of HAP that the current standards do not control. However, the commenter’s claim is 

unsupported by the plain language of section 112(d)(6), which directs the EPA to review and 

revise as necessary “emission standards promulgated.” The residual risk review included 

evaluation of all emissions sources, including any significant HAP emission points, for which we 

have available data. As explained in sections VII.A and B of the preamble, based on our revised 

assessment, we have determined that the MACT standards, including those promulgated in this 

final rule pursuant to sections 112(d)(2)-(3), reflect an acceptable level of risk and provide an 

ample margin of safety.

3.2.2 Glycol Dehydrators – 40 CFR subpart HH
242

Comment: One commenter (4266) states that they examined the EPA’s small dehydrator dataset 

to evaluate potential subcategorization and MACT floor options. The commenter provides that 

Table 20-6 in their comment document illustrates the EPA’s small dehydrator dataset sorted by 

uncontrolled BTEX emissions.

The commenter (4266) asserts that, if the outliers created by applying an assumed 98 percent 

control efficiency to the controlled streams are not considered (this assumption resulted in 

uncontrolled BTEX emissions of 125 tpy, 375 tpy, and 2,965 tpy), the data do show some 

expected outcomes. For example, the commenter states that the average emissions for the 25 

percent lowest inlet BTEX concentrations are 2.5 tpy BTEX and 0.2 tpy benzene, while the 

remaining 75 percent have average emissions of just over 5 tpy BTEX and 1.2 tpy benzene. The 

commenter also states that the BTEX emissions for the lowest 25 percent of the throughputs 

average 3 tpy, while the BTEX emissions for the remaining 75 percent of the data set with higher 

throughputs average over 5 tpy. 

According to the commenter (4266), the average benzene emissions from the lowest 25 percent 

throughput dehydrators (1.3 tpy) are actually higher than the average benzene emissions for the 

higher throughput dehydrators (0.8 tpy). The commenter provides that evaluation of all the data 

show a slight correlation between BTEX emissions and inlet BTEX concentration (R2 = 0.2), but 

the data show a decrease in BTEX emissions with increasing throughput. The commenter 

concludes that the EPA’s dataset indicates that neither inlet BTEX concentration nor dehydrator 

throughput have a sufficient correlation with emissions to further break small dehydrators into 

technically and legally sound subcategories based only on these characteristics. Therefore, the 

commenter recommends that an uncontrolled emissions threshold be established to subcategorize 

small dehydrators. Given the large number of variables that impact emissions from dehydrators, 

the commenter believes that emissions are the most relevant and comprehensive indicator of 

differences in dehydrator class, type, and size.

One commenter (4266) states that the EPA’s proposed subcategorization scheme and resulting 

equations would require controls on every dehydrator, no matter how low the natural BTEX 

level or the potential dehydrator emissions. 

Two commenters (3560, 4266) assert that the EPA’s proposed calculation for benzene emissions 

assumes a lower benzene emission threshold based on a lower benzene concentration in the gas 

stream. The commenters state that this means that small dehydrators can have a zero benzene 

emission limit, which they may not be able to meet.

One commenter (4266) states that, in the event that the EPA chooses to continue with the 

proposed subcategorization approach, the EPA must make changes to the proposed equations. 

According to the commenter, the equations used in the proposed subparts HH and HHH rules 
243

approach a mass limit of zero. The commenter asserts that the BTEX emission limit equation for 

small dehydrators should not go to zero. The commenter explains that the equation would give 

the intended result if the product of Throughput and Concentration (Ci, BTEX) were assigned a 

lower bound. The commenter states that their suggested correction to the equations for subparts 

HH and HHH would result in a minimum emission limit of 0.286 tpy BTEX for oil and natural 

gas production and 1.45 tpy BTEX for natural gas transmission and storage (i.e., the MACT 

floors), rather than zero tpy. The commenter opines that, if EPA’s proposed equations are 

promulgated, they would represent a level of control that was beyond the MACT floor.

The commenter (4266) suggests that, if the EPA moves forward with standards, to be legally 

defensible, the EPA should subcategorize small dehydrators appropriately and develop MACT 

floors for each subcategory and identify de minimis emission levels for dehydrators with 

insignificant emission levels.

One commenter (4252) suggests that the EPA remove the proposed requirements for small 

dehydrators. The commenter states that, if the EPA elects to promulgate standards for small 

dehydrators, it must establish subcategories that appropriately account for fundamental 

differences among small dehydrators to be regulated and determine MACT floors for the 

subcategories. The commenter opines that the dual use of 0.9 Mg/yr benzene as a criterion for 

separating small and large dehydrators and an emission limitation for large dehydrators 

effectively creates a situation where all dehydrators are subject to standards.

One commenter (4266) opines that the EPA has already established the appropriate threshold for 

this subcategorization – 0.9 Mg/yr (1 tpy) benzene. The commenter recommends that the small 

dehydrator subcategory for oil and natural gas production (subpart HH) be separated into (1) 

those dehydrators with uncontrolled average benzene emissions less than 0.9 Mg/yr and (2) those 

dehydrators with uncontrolled average benzene emissions of 0.9 Mg/yr or greater and actual 

annual average flow rates less than 85,000 SCMD. For natural gas transmission and storage, the 

commenter states that these subcategories are (1) those dehydrators with uncontrolled average 

benzene emissions less than 0.9 Mg/yr and (2) those dehydrators with uncontrolled average 

benzene emissions of 0.9 Mg/yr or greater and actual annual average flow rates less than 283,000 

SCMD. 

Once the subcategories are established, the commenter (4266) states that the EPA must then 

determine MACT floors for each subcategory. The commenter asserts that the EPA’s dataset 

available in the docket does not include sufficient levels of detail to fully evaluate process 

variations or other factors that influence emissions. More importantly, according to the 

commenter, based on the EPA’s data, there is no way that the EPA can determine whether any 

simple “floor” level calculated from these data can be achievable by all dehydrators in the 

subcategory. The commenter believes that this is especially germane in this situation where 
244

many aspects that impact emissions are not under the control of the owner or operator. However, 

the commenter states that the owner or operator can ensure that the dehydrator is operated in a 

manner to reduce emissions to the maximum extent possible without add-on controls by 

optimizing the glycol circulate rate. The commenter says that this practice is already recognized 

as an effective method by the EPA and is required by §63.764(d)(2) for area source dehydrators 

not located within an urbanized area (UA) plus offset and urban cluster (UC) boundary, as 

defined in §63.761 of subpart HH. The commenter asserts that this is a clear example of the type 

of “design, equipment, work practice, or operational standard, or combination thereof,” standard 

allowed under section 112(h) of the CAA. 

In many situations, the commenter (4266) states that emissions from these low-emitting 

dehydrators are below the detection limit of prescribed test methods. The commenter contends 

that this clearly meets the criteria of section 112(h), justifying the establishment of standards that 

require the optimization of glycol circulation rate to reduce emissions. 

The commenter (4299) contends that as dehydrator emissions increase (i.e., are above 0.9 

Mg/yr), the ability to effectively control increases and differences in inlet BTEX concentration, 

throughput, and other variables are less critical. Therefore, the commenter believes it is 

technically valid and legally defensible to determine the MACT floor for those small dehydrators 

with uncontrolled benzene emissions of 0.9 Mg/yr or greater. 

The commenter (4266) reports that, for oil and natural gas production, the average of the lowest 

5 emitting dehydrators (since there are less than 30 dehydrators in the data set for the 

subcategory) is 4 tpy BTEX. According to the commenter, for natural gas transmission and 

storage, there is only one dehydrator in the dataset with benzene emissions of 1 tpy or greater, 

and the BTEX emissions for this dehydrator are 5.5 tpy.

Response: As explained in the proposal preamble, the 1999 NESHAP created a subcategory of 

glycol dehydrators but left it uncontrolled. The subcategory of uncontrolled dehydrators are 

small dehydrators and the subcategory consists of glycol dehydrators with an actual average 

natural gas flowrate less than 85,000 scmd or actual average benzene emissions less than 0.9 

Mg/yr for subpart HH, and an actual annual average natural gas flowrate less than 283,000 scmd 

or actual average benzene emissions less than 0.9 Mg/yr for subpart HHH. We therefore 

proposed standards for that subcategory. In so doing, we did not re-examine the 

subcategorization decisions made in 1999. We do not believe that is necessary for purposes of 

setting MACT standards for a long-established subcategory. Because we did not reopen the 1999 

subcategorization for notice and comment, we are not addressing those subcategorization 

decisions in this final rule.
245

In addition, in response to comments regarding the variability of glycol dehydration unit 

operating parameters discussed elsewhere in this document, we have revised the BTEX emission 

limits to account for variability, and we believe those changes will address some of the 

commenters’ concern regarding low-emitting units.

Comment: One commenter (4104) states that they were not able to obtain legacy docket A-94-

04 data or complete the mapping of data in Attachment 2 (ECR memorandum from Heather 

Brown (EC/R) to Bruce Moore (EPA), “Oil and Natural Gas Production MACT and Natural Gas 

Transmission and Storage MACT - Glycol Dehydrators: Impacts of MACT Review Options,” 

July 28, 2011; EPA–HQ–OAR–2010–0505-0047) to the floor data during the limited comment 

period. The commenter requests that the data be made available in the docket for review and 

further analysis. 

One commenter (4457) states that since the EPA is relying on its prior rulemaking, it should 

make all of the documents from that rulemaking available as part of the current rulemaking 

docket. 

Response: We included in the docket to the proposed rule, those materials on which the 

proposed rule relied. Indeed, the specific memorandum cited by the commenter was available in 

the docket upon publication of the proposed rules in the Federal Register. Moreover, all 

documents from the EPA legacy docket A-94-04 are available by contacting the EPA Docket 

Office.

Comment: One commenter (4457) states it is unclear how the EPA “considered” the 

optimization of glycol circulation rates in the prior MACT review since it did not appear to be a 

MACT requirement at that time, even though many operators are using this approach. The 

commenter stated that review of the prior rulemaking and its supporting documents did not 

provide any indication that this was considered. 

Response: The optimization of glycol circulation rates was considered to be a process 

modification under the original MACT and the provisions specifying their use in complying with 

the standard are contained in §63.771(e)(2) of the existing rule. The recognition that properly 

operated condensers with a flash tank in the system can achieve 95 percent control is addressed 

in Legacy docket A-94-04, memo number II-A-007, titled “Recommendation of MACT Floor 

Levels for HAP Emission Points at Major Sources in the Oil and Natural Gas Production Source 

Category.”

3.2.3 Glycol Dehydrators – 40 CFR subpart HHH

3.2.3.1 Appropriateness of Using Data from Previous NESHAP
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Comment: According to one commenter (4457), the EPA’s failure to extend HAP standards for 

small glycol dehydrators to HAPs other than BTEX violates section 112(d)(2), (3) and (6). The 

commenter states that, under the proposed rule, BTEX are the only HAPs that the EPA proposes 

to control with any specificity despite the agency’s obligation to regulate each listed HAP 

emitted by the source categories. 42 U.S.C. §7412(d)(1); see also Nat’l Lime Ass’n v. EPA, 233 

F.3d 625, 634 (D.C. Cir. 2000). The commenter assumes that the EPA does not intend to regulate 

additional HAPs through the use of surrogates because the EPA has not identified any surrogates 

or provided any explanation for the use of surrogates in this rulemaking. See Nat’l Lime Ass’n, 

233 F.3d at 639; see also Mossville Envtl. Action Now v. EPA, 370 F.3d 1232, 1243 (D.C. Cir. 

2004) (The EPA must demonstrate that a “correlation exists” between two pollutants when 

deciding to use a surrogate, and the EPA must memorialize that correlation in “a fashion that 

commenters, interested members of the public, regulated entities, or ... a reviewing court, can 

assess.”) According to the commenter, pursuant to sections 112(d)(2), (3) and (6), when setting 

MACT for the first time for small glycol dehydrators, the EPA must set a numerical limit both on 

BTEX pollutants and on other HAPs emitted by these sources. For example, the commenter 

states that there is information available from Colorado showing that glycol dehydrators emit 

other HAPs such as n-hexane, 2,2,4-trimethylpentane, ethylene glycol, and possibly others. 

The commenter (4457) contends that where recent actual emissions data of higher quality than 

the legacy data are readily available to the Agency, the use of legacy data, that fail to reflect 

industry developments, for calculating a numeric standard at both the floor and beyond-the-floor 

stages of the MACT analysis is arbitrary and capricious, and not in accordance with law. The 

commenter supports the EPA’s efforts to reduce harmful pollution from previously uncontrolled 

sources, but states that the EPA’s attempt to calculate a MACT floor standard for these 

unregulated sources using outdated data fails to meet the statutory requirements that new 

facilities limit their emissions to a level achieved by the “best controlled similar source” and, for 

existing facilities, to “the average emission limitation achieved by the best performing 12 percent 

of the existing sources.” The commenter adds that the EPA must determine a MACT floor for all 

HAPs emitted by small glycol dehydrators and that the EPA’s failure to extend HAP standards 

for small glycol dehydrators to HAPs other than BTEX violates section 112(d)(2), (3) and (6).

The commenter (4457) states that the process employed by the EPA improperly looks at the 

expected performance of a single control device rather than the performance demonstrated by the 

source. The commenter states the EPA acknowledges that where a flash tank is incorporated in 

the design of the dehydrator system, potential emissions are captured by that device, leading to 

lower inlet concentrations at the condenser and lower overall emissions. The commenter asserts 

that rather than recognizing the superior environmental performance of the entire system, the 

EPA has devised a complex scheme that removes the effect of this part of the control system 
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from the calculation of the MACT floor. The commenter believes that the EPA should 

recalculate the MACT floors using current data (which will show that more sources are 

achieving very low levels) and follow the D.C. Circuit Court’s instruction to examine the 

performance of the system, rather than an individual control device and to set standards that 

reflect the emission levels that the best performing sources achieve. 

Response: As stated in the preamble to the proposed rule (76 FR 52768), we did not have new 

emissions data concerning small dehydration units and therefore, we evaluated the dataset 

collected from industry during the development of the 1999 MACT standards. We also discussed 

our rationale for not establishing a MACT floor as a mass limit (i.e., Mg/yr) due to the variability 

of gas throughput and inlet gas composition. As we stated in section X.A of the preamble, we 

normalized emissions for a more accurate determination of the best performing sources in terms 

of emissions per BTEX concentration and natural gas flowrate.

The 2005 NEI was an emissions dataset that was available to us when evaluating the MACT 

floor. However, the 2005 NEI does not contain throughput data for glycol dehydration units, nor 

does it contain BTEX emissions data. Therefore, we were not able to determine which units 

would be considered small glycol dehydration units based on throughput.

We also refute the commenter’s assertion that the BTEX emission limit is a surrogate for HAP 

emissions. The data available to us only contained BTEX emissions for all units and therefore, 

we were only able to evaluate the emission limit on a BTEX emissions basis. This is not intended 

to be a surrogate for HAP emissions, although, as a co-benefit from the control of BTEX 

emissions, other HAP emissions will be reduced. Additionally, we intend to further investigate 

the non-BTEX emissions from small glycol dehydrators and once we obtain sufficient data, we 

would propose a MACT standard for those other HAP.

Comment: One commenter (4266) states that the EPA estimated the cost effectiveness of the 

proposed small dehydrator standards to be $8,360/Mg HAP (76 FR 52768). The commenter 

believes that this cost effectiveness estimate is high, and that the cost effectiveness analysis 

significantly underestimates the cost effectiveness of many dehydrators. The commenter reports 

that the primary reason for this underestimation is because the EPA did not account for the 

naturally occurring variability in HAP content in natural gas streams that would be covered by 

the proposed small dehydrator standards. 

The commenter (4266) provides that Table 20-3 of their comment letter was generated from 

GRI-GLYCalcTM runs using a range of dehydrator operating throughputs and actual gas 

compositions (furnished by API member companies); and the EPA’s annualized cost of control 

for dehydrators from Table 3-7 of the proposal RIA. According to the commenter, unless noted, 

the provided examples in the table reflect actual dehydrators in operation with their actual 
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throughputs and gas compositions. Additionally, the commenter states that more detail on the 

calculations used can be found in Attachment P to the comment letter, which is incorporated in 

their comments by reference.

The commenter (4266) states that, as seen in Table 20-3 of their comment letter, the cost 

effectiveness at the small dehydrator threshold ranges from $152,000,000/ton-HAP to 

$6,638/ton-HAP with most of the costs evaluated being substantially greater than the EPA’s 

estimate. The commenter believes these costs to be unreasonable for low BTEX content (San 

Juan Basin Coal Bed Methane) gasses regardless of throughput; moderate BTEX content 

(Haynesville shale) gasses with relatively high throughputs; and high BTEX content (Green 

River Basin Tight Sand) gasses with low throughputs (which are common in the Green River 

Basin). As defined in the proposed rule, the commenter asserts that these dehydrators would be 

classified as “small” and subject to application of “Equation 1” to determine allowable 

emissions. According to the commenter, the application of “Equation 1” results in zero allowable 

emissions of BTEX. The commenter states that, with the likely prospect of BTEX at some 

concentration lower than normal gas analysis detection limits this outcome essentially imposes 

100% control requirements on dehydrators with almost zero potential for HAP emissions and 

almost infinite control costs. The commenter opines that these costs are unreasonable and based 

on a likely technically unachievable requirement and must be corrected.

The commenter (4266) states that the EPA’s proposed BTEX emissions limit equation, if 

promulgated, would represent a level of control beyond the MACT floor. According to the 

commenter, the EPA has clearly stated that they did not believe the cost effectiveness of beyond 

the floor controls for both oil and gas production small dehydrators and natural gas transmission 

and storage small dehydrators were reasonable.

Response: The determination of MACT standards under section 112 of the CAA is governed by 

sections 112(d)(2) and (3). Section 112(d)(3) does not allow the consideration of cost in 

determining the MACT floor. Rather, the MACT floor is based on the “emission control that is

achieved in practice” by the best performing sources. Once we establish the floor, we proceed to 

evaluate whether to set standards tighter than the floor (beyond-the-floor), under section 

112(d)(2). Unlike the floor analysis, our beyond the floor analysis includes a consideration of 

cost. We conducted both a floor and beyond the floor analysis for small glycol dehydrators and 

set the MACT standard at the floor level. We rejected going beyond the floor due to costs that 

we considered to be unreasonable [76 FR 52768]. Therefore, the commenters’ concerns 

regarding costs are not relevant to setting the MACT floor and do not change our determination 

not to set beyond the floor standards for small glycol dehydrators. As discussed elsewhere in 

this document, we have revised the BTEX limits since proposal based on variability, and 

included a minimum combustion control device outlet TOC concentration, both of which may 

address the commenter’s concerns regarding low emitting units.
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Comment: One commenter (4274) states that it is worthwhile to investigate emission limits for 

the smaller glycol dehydration unit process vents. The commenter asserts that the Marcellus 

Shale, as well as other shale plays will have the experience of more industrialized sites close to 

homes than were ever before considered. The commenter believes that investigating the emission 

levels and determining what cost effective technologies are available to limit emissions is very 

worthwhile. The commenter adds that, in lieu of cost effective technologies, just by the 

investigation, it may be possible that industry will be interested and move forward with 

appropriate research and development programs to address this and similar initiatives. The 

commenter recommends that the EPA move forward with this provision.

Response: We appreciate the commenter’s insight. The docket for this rulemaking contains 

considerable information on the cost and effectiveness of a number of control technologies. We 

encourage further development of control technologies that will provide control beyond the 

levels required by the NESHAP.

Comment: According to one commenter (4457), the EPA must update the MACT floor for 

existing standards and consider setting a beyond-the-floor-standard for large glycol dehydrators 

under EPA’s CAA section 112(d)(6) review. According to one commenter (4457), and as 

detailed in the Buckheit Report included as an attachment to their letter, the EPA’s basis for the 

1999 MACT standard for glycol dehydrators was the same as that employed in other MACT 

standards of that era and that subsequently have been invalidated in court. Specifically, the 

commenter asserts that the EPA’s 1997 survey of emission sources failed to capture the best 

performing facilities and the EPA made no effort to quantify the emissions achieved in practice 

of even those facilities reported in the survey results. The commenter argues that, had the EPA 

considered data in the 1999 rulemaking record demonstrating facilities had achieved HAP 

control efficiencies of up to 99 percent, a different existing source MACT floor and limit would 

have been required. The commenter requests that the EPA resolve information gaps that exist 

and revise the existing standards for emissions from large glycol dehydrators to reflect the level 

of performance that is being achieved today. 

The commenter (4457) also requests that the EPA calculate the MACT floor for each HAP 

emitted by large glycol dehydrators and set MACT standards for these HAP sources that 

accurately reflect the emissions levels of the most efficient performers as required by 112(d). 

The commenter argues that sections 112(d)(6) and 112(d)(3) each require the EPA to set a 

numeric limit for each HAP emitted by the source category.

Response: The EPA disagrees with the commenter that section 112(d)(6) mandates that the EPA 

must correct any deficiency in an underlying MACT standard when it conducts the “technology 

review” under that section. We believe that section 112 does not expressly address this issue, and 
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the EPA has discretion in determining how to address a purported flaw in a promulgated 

standard. The “as necessary” language in section 112(d)(6) must be read in the context of that 

provision, which focuses on the review of developments that have occurred since the time of the 

original promulgation of the MACT standard and thus should not be read as a mandate to correct 

flaws that existed at the time of the original promulgation. In NRDC v. EPA, 529 F.3d 1077, 

1084 (D.C. Cir. 2008), the District of Columbia Circuit held that “We do not think the words 

‘review, and revise as necessary’ can be construed reasonably as imposing any such obligation” 

to re-calculate the MACT floors. The Court further held that there was no such duty in that case 

because the EPA had found that there were no significant developments in practices, processes 

and control technologies. Similarly, as described in the preambles to the proposed and final 

rules, we have determined that revision is not necessary because we have found no significant 

developments in practices, processes and control technologies for reducing emissions from large 

glycol dehydrators. See preamble section X.C for additional discussion of the technology review.

 

Comment: One commenter (4457) states that the EPA’s BTEX MACT standard for small glycol 

dehydrators relies on emission factors. The commenter asserts that emission factors are based on 

the average results of limited testing of some sources within the sector; as such, they cannot be 

relied on to determine the emissions profile of the category or to identify the best performing 

sources within the category. The commenter argues that, if using emission factors, the EPA must 

require robust monitoring to ensure transparency and effective enforcement. The commenter 

recommends that the EPA adopt numeric standards for the individual pollutants and adopt 

monitoring and enforcement measures that require facilities to accurately and clearly report their 

emissions reductions of all HAPs. 

Response: The commenter misinterpreted the proposed rule preamble discussion where we 

explain how we established the MACT floor by calculating an emission factor from emissions 

data. We first determined emissions for each individual glycol dehydration unit using GLYCalc 

and data provided by the surveyed facilities for those units. These emissions (in terms of tons per 

year) were then converted to a normalized emission rate in terms of BTEX concentration and 

natural gas throughput. This normalized BTEX emission rate is what we referred to as an 

“emission factor,” however this factor is only used for a facility to determine its BTEX emissions 

limit under the final rule , but we did not use emission factors to calculate source emissions in 

the process used to establish the MACT floor. As explained above, we could only establish 

standards for BTEX compounds at this time because we lacked information for other HAP 

emitted from these sources in the database that contained the necessary inlet concentration and 

natural gas throughput information. The facilities were then ranked according to the emission 

rate. The glycol dehydration units with the lowest normalized emission rate were then considered 

to be the best performing sources.
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Comment: One commenter (4457) points out that the EPA’s proposed MACT limit for new 

dehydrators in the oil and gas production sector is lower than the proposed limit for similar new 

dehydrators in the downstream natural gas transmission and storage sector. The commenter says 

that this is a counter-intuitive result because the EPA did not have emissions data for an adequate 

number of representative units for such sources from either sector. The commenter contends that 

while the EPA took appropriate steps by bringing these small dehydrators into the NESHAP, it 

has not gone far enough; the EPA should base its MACT limits on a more robust dataset, 

reflecting current emissions from sources in both source categories.

Another commenter (4104) states that the proposed BTEX emission limits for existing small 

dehydrators in subpart HH is 1.10 x 10-4gr/scm-ppmv as compared to the subpart HHH standard 

of 6.42 x 10-5gr/scm-ppmv. The commenter asserts that this difference is unexplained and not 

rationalized for similar equipment. The commenter requests that the EPA document why a more 

lenient standard is appropriate for subpart HH and provide analysis to supplement the 

background documentation that inaccurately indicates similar standards are proposed.

Response: In developing the MACT standards, we are required under section 112(d)(3) of the 

CAA to evaluate the best performing 12 percent of sources (or the best performing 5 sources if 

there are fewer than 30 sources in the source category or subcategory). In doing so for each 

source category or subcategory, we ranked the sources in our database by their emission rate 

(i.e., in terms of lb BTEX/MMscf-ppmv) from lowest to highest. The units with the lowest 

emission rates are considered to be the best performing sources. 

Intuitively, it is not unexpected that the emission rates for glycol dehydration units located in the 

transmission and storage source category would be lower than those for production, because the 

gas is drier further downstream. For existing sources that is the case. For new sources, the limits 

in the final rule are 4.66 x 10-6gr/scm-ppmv for subpart HH as compared to the subpart HHH 

standard of 5.44 x 10-5gr/scm-ppmv, so the limit is higher for the HHH standard. Nonetheless, 

the limit is at the MACT floor level of control, based on section 112(d)(2) and (3) and the 

commenter did not identify any error in our assessment that showed we deviated from the 

requirements of the CAA.

The MACT floor for subpart HH small glycol dehydration units was calculated by averaging the 

emission rates from the best performing 12 percent of sources. For subpart HHH, we had fewer 

than 30 sources in our dataset and so the MACT floor for subpart HHH small glycol dehydration 

units was calculated as the average of the emission rates from the best performing 5 sources. 

Comment: Two commenters (3560, 4258) request that small dehydrator benzene emission limits 

be revised. The commenters believe that assigning a lower benzene emission rate based on lower 

benzene contents in gas streams is infeasible. The commenters assert that the proposed 

calculation for establishing the required benzene concentration in gas streams would ultimately 
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mean that small dehydrators can have a zero benzene emission limit. The commenters state that 

small units in BTEX service can only reduce benzene emissions to a certain point and cannot 

necessarily reduce their emissions to zero. 

One commenter (4266) states that the EPA has routinely identified equipment with low HAP 

emission potential that they determine should not be regulated. The commenter insists that there 

is strong justification for such a threshold in the oil and gas production and natural gas 

transmission and storage source categories due to the naturally occurring differences in gas 

composition across the United States and thus, varying differences in dehydrator input stream 

HAP concentrations, throughputs, and emissions. The commenter recommends that the EPA 

establish de minimis levels of HAP emissions that would exempt small dehydrators from all 

requirements under subparts HH and HHH. 

The commenter (4266) states that, as was shown in real-world examples provided in Tables 20-3, 

20-4, and 20-5 of their comment letter, there are situations across the country where the natural 

gas being treated in dehydrators has such low benzene, BTEX, and HAP that the emissions will 

be trivial. The commenter recommends that the EPA establish de minimis levels of HAP 

emissions that would exempt small dehydrators from all requirements under subparts HH and 

HHH. The commenter recommends that this de minimis level be 0.5 Mg/yr total uncontrolled 

BTEX emissions.

One commenter (4246) asserts that, as the gas gets leaner, the standard gets harder. The 

commenter requests that the EPA amend the proposed MACT subpart HH to provide a strong 

incentive for sources to reduce HAP emissions. The commenter specifically recommends that the 

EPA offer owner/operators an exempt status by reducing HAP emissions below an enforceable 

limit, such as 1 ton per year (tpy) of benzene.

Response: The limits established for small dehydrators represent the MACT floor, as discussed 

elsewhere in this document and the preamble to the final rule, pursuant to sections 112(d)(2) and 

(d)(3). Therefore, our MACT floor determination is limited to small dehydration units located at 

major sources of HAP. While the commenter provides examples of units with low HAP content 

in the inlet gas stream, the commenter does not specify if these units are located at major sources 

or area sources of HAP. We would expect, in general, that these units would be located at area 

sources, since by virtue of the low HAP content in the gas stream the facility’s potential 

emissions would be below the 10/25 major source threshold. 

In the preamble to the proposed 40 CFR part 60, subpart NNN, NSPS for Air Oxidation Unit 

Process (48 FR 48932, October 21, 1983), we stated that 20 ppmv is the lowest outlet 

concentration of total organic compounds achievable by the combustion of low organic 

concentrations (i.e., inlet concentrations of 2000 ppmv or less). As stated in the preamble to 
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subpart NNN, the outlet concentration was established based on kinetic calculations of 

incinerators. It was demonstrated that, at a given temperature and residence time, a stream with a 

low inlet concentration (approximately 2,000 ppmv) could not be controlled in an incinerator to 

an outlet concentration below 20 ppmv. We believe that this same option should be available for 

small glycol dehydration units and as a result, the final rule allows the 20 ppmv limit when 

combustion devices are used. 

Comment: Several commenters (4104, 4241, 4252, 4266) request that the EPA revisit the 

MACT floor to better assess variability. One commenter (4104) argues that assessing variability 

is an important component of the analysis and consistent with recent court decisions. The 

commenter states that the EPA suggests that the normalization of emissions includes variability 

by taking into account unit-specific throughput and inlet BTEX concentration. The commenter 

argues that the five small dehydrator units considered in the MACT floor analysis all had no 

control, inlet BTEX concentration was 20 ppmv on 2 units and 155 ppmv on 3 units, and 

throughputs ranged from 20 to 120 MMscf/day. 

The commenter (4104) asserts that the throughput values and BTEX inlet concentration data 

only capture two values and these are not the only variables that can impact dehydrator 

emissions performance, and that many additional operating parameters can impact emissions 

variability. The commenter opines that the category lends itself to emissions modeling using 

GRI-GLYCalcTM as a method to assess variability.

The commenter (4104) recommends that multiple tests from a single dehydrator be acquired to 

appropriately assess emission variability or provide operating context for emission limit 

applicability. At a minimum, the commenter believes that the EPA should complete a series of 

GRI-GLYCalcTM model simulations to better assess emissions variability and obtain a more 

robust dataset. The commenter states that the EPA could assess variability from operating 

parameters through modeling, where GRI-GLYCalcTM uses field conditions and compositional 

data to simulate and estimate the resulting estimated emissions. The commenter asserts that the 

emissions data used are based on a “snapshot sample” and do not represent conditions and 

composition variance over time. 

One commenter (4241) asserts that it did not appear that the EPA adjusted the limit for 

variability, as allowed under the CAA. As was noted in the docket memorandum “Oil and 

Natural Gas Production MACT and Natural Gas Transmission and Storage MACT - Glycol 

Dehydrators: Impacts of MACT Review Options” (July 28, 2011), “gas throughput and inlet gas 

composition is highly variable from one source to another.” Because of this, the commenter 

believes that the EPA needs to make adjustments in order to reasonably account for the expected 

inter-unit variability between the 11 units used in the calculation of the floor. The commenter 

disagrees that a single emissions factor, scaled by gas volume and concentration, is sufficient, 
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and recommends that the emissions factor itself be adjusted to account for the substantial 

variation even between units used to calculate the MACT floor.

One commenter (4266) argues that, if the EPA moves forward with standards for small 

dehydrators, they must account for fundamental differences in naturally occurring inlet gas 

concentrations and dehydrator design. According to the commenter, subpart HH proposed 

Equation 1 would require over 90 percent of the “best performing” dehydrators to install 

additional control. The commenter asserts that there are flaws in the EPA’s small dehydrator 

floor analysis, derived Equation 1, and control approach to calculate dehydrator-specific BTEX 

emission limitations are clearly illustrated by the application of Equation 1 to the 11 dehydrator 

units used by the EPA for the MACT floor analysis for subpart HH. According to the 

commenter, Table 20-4 of their letter illustrates the flawed construct by applying the proposed 

equation for subpart HH to the specific dehydrators making up the “top 12 percent” in the EPA’s 

MACT floor dataset. The commenter states that only one of the 11 dehydrators that were used to 

calculate the MACT floor for small dehydrators in the oil and natural gas production source 

category can meet the proposed standard without the installation of additional controls. The 

commenter asserts that this would mean that the equation represents the average emission 

limitation achieved by best performing 1 percent of the dehydrators, not the best performing 12 

percent. The commenter argues that this does not represent a legitimate MACT floor. The 

commenter opines that the equations represent a beyond-the-floor level of control that the EPA 

has not contemplated nor justified. 

The commenter (4266) asserts that, despite the EPA’s inclusion of a throughput variable in the 

equations, the proposed small dehydrator equations are only sensitive to BTEX inlet 

concentration. Therefore, according to the commenter, throughput or potential emissions have no 

effect on the control efficiencies required to meet the calculation emission limitation. The 

commenter states that this artifact is illustrated by the analysis summarized in Table 20-5 of their 

comment letter, which shows the Equation 1 outcome to be sensitive only to BTEX inlet 

concentration from the perspective of required control percentage. 

Response: Based on information in the Technical Reference Manual for GRI-GLYCalcTM and 

other studies, it is our understanding that while other factors can influence glycol dehydration 

unit emissions, inlet gas BTEX composition, natural gas throughput, and glycol recirculation rate 

have the most significant effect on emissions. As a result, we used natural gas throughput and 

inlet gas composition (namely BTEX) to normalize emissions and identify the best performing 

sources from the available data. We lacked information on glycol circulation rate in our data 

(both the 1997 data and 2005 NEI) so did not consider that as a factor.

The proposed MACT floor limit for the oil and natural gas production source category was 

1.1x10-4g BTEX/scmd-ppmv. This limit was determined by calculating a straight average for the 
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top 12 best performing small glycol dehydration units. It should be noted that the commenter’s 

conclusion that of the 11 dehydrators included in the MACT floor, only one of them could meet 

the proposed standard is incorrect. In fact, eight of the 11 dehydrators could meet the proposed 

standard. By using the average of the best performing 12 percent of sources, as required by 

section 112(d)(3), it should be expected that some of the top 12 percent of the sources would 

have to be controlled in order to meet the floor. However, as pointed out by the commenter, it is 

recognized in the case law that the EPA may consider variability in estimating the degree of 

emissions reduction achieved by best-performing sources and in setting MACT floors. 

In response to comments, we revised the MACT floor limit, which was calculated based on the 

average of the best performing 12 percent of small glycol dehydration units in the subpart HH 

source category (and the best performing 5 for subpart HHH), to account for these units’ 

variability. To account for variability in the operation and emissions, the BTEX emission rates 

(in terms of g BTEX/scm-ppmv) were used to calculate the average emission rate and the 99 

percent upper predictive limit (UPL) to derive the MACT floor limit. For more information on 

how we performed the MACT floor analysis, see the Oil and Natural Gas Production and Natural 

Gas Transmission and Storage MACT Floor document, which is available in the docket.

Using this method, the MACT floor (or 99 percent UPL) for BTEX emissions from existing 

glycol dehydration units in the oil and natural gas production source category is 3.28x10-4g 

BTEX/scmd-ppmv. 

A similar analysis was performed for small glycol dehydration units in the natural gas 

transmission and storage source category. The proposed MACT floor limit was 6.42x10-5g 

BTEX/scmd-ppmv. Using the 99 percent UPL, the MACT floor limit for existing glycol 

dehydration units in the natural gas transmission and storage source category is 3.10x10-4g 

BTEX/scmd-ppmv. 

In addition we believe that the BTEX concentration data used to develop the MACT floor 

represents an annual average natural gas concentration. As a result, the BTEX emission limit 

formula has been modified for the final rule to use average annual BTEX concentration.

Comment: One commenter (4266) recommends that the EPA apply a control efficiency standard 

in lieu of a mass emissions limit. The commenter opines that a mass emissions limit imposes 

complicated costly compliance and recordkeeping obligations when contrasted with a control 

efficiency standard. The commenter suggests that small dehydrators have the option to comply 

with a 95 percent control requirement for large dehydrators in §63.765(b) as an alternative to 

complying with the mass emission limitations determined by equation, which they believe would 

result in greater emissions reduction for a lower burden.
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Response: The EPA set the MACT standards for the small dehydrators in accordance with 

section 112(d)(2) and (3). The commenter did not explain how its suggested alternative is 

representative of, or otherwise equivalent to, the MACT for the small dehydrators under section 

112(d)(2) and (3). We therefore decline to adopt the suggested alternative. 

Comment: According to one commenter (4457), the EPA must determine a proper beyond-thefloor MACT level for both small glycol dehydrators and storage vessels, by determining the 

“maximum degree of reduction in emissions” that is achievable, as required under section 

112(d)(2). The commenter asserts that the proposed rule fails to provide any discussion of a 

beyond-the-floor determination for storage vessels.

For the same reasons it cannot rely on the outdated analyses in establishing the MACT floors, the 

commenter (4457) argues that the EPA must now perform an up-to-date beyond-the-floor 

analysis based on current emission controls. The commenter opines that, absent this analysis, the 

EPA’s beyond-the-floor determination for the proposed rule is arbitrary and capricious. 

Response: A beyond-the-floor analysis was performed for small glycol dehydrators in the 

proposed rule (76 FR 52768). As we detailed in preamble section X.C, and elsewhere in this 

document. . Therefore, additional data gathering was not required. With regard to storage 

vessels, as discussed in preamble section VII.A we are not finalizing requirements for storage 

vessels without the PFE.

3.2.4 Other Comments on Glycol Dehydration Units

Comment: One commenter (4270) states that the EPA provides a significance threshold in terms 

of 0.9 megagrams (Mg) of benzene, yet Equation 1 of the proposed rule shows the calculation for 

the emission limit of BTEX. The commenter would like the EPA to clarify which parameter they 

are targeting for reductions, benzene or BTEX? The commenter explains that they do not 

monitor BTEX levels either in their pipeline gas or gas processed in dehydrators. The 

commenters request that the EPA delineate which constituent is to be used in emission 

calculations.

Response: As specified in §63.765 of subpart HH and §63.1275 of subpart HHH, you must limit 

emissions of BTEX and determine the appropriate limit for the small glycol dehydrator using 

inlet gas BTEX concentration measured at the inlet to the dehydrator.

Comment: One commenter (4263) requests that the EPA clarify that the language in 

§63.765(c)(3)(ii) only applies to dehydration units located at an area source that must be 

controlled as specified in §63.764(d)(1)(i).
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Response: We had proposed to eliminate the 0.9 Mg/yr benzene compliance option for large 

glycol dehydrators. The change suggested by the commenter to §63.765(c)(3)(ii) would have 

been necessary to clarify that only dehydrators at area sources could then use this compliance 

option. Since we are instead retaining the 0.9 Mg/yr benzene compliance option for large 

dehydrators at major sources, in the final rule, we have revised §63.765(c)(3)(ii) to read as 

follows to clarify that this compliance option is only available for large glycol dehydrators 

(which can be located at either major or area sources):

(ii) For any large glycol dehydration unit, benzene emissions are reduced to a level less than 0.90 

megagrams per year.

Comment: One commenter (4241) asserts that the EPA states the glycol dehydration standards 

can be met by routing emissions to a condenser or to a combustion device. The commenter notes 

that most glycol dehydrators are routed through flash tanks and rerouted to the boiler. The 

commenter seeks clarification on whether such units would be required to meet the glycol 

dehydrator standards applicable to the boiler, or would the unit be eligible to use the alternative 

for uncontrolled sources to demonstrate compliance with the use of the model GRI–GLYCalcTM 

(proposed §63.772(d)(2)(iii)).

Response: In the situation described by the commenter the boiler would be a control device and 

the requirements of §63.771(f)(1)(i) and 63.772(e) would apply. 

Comment: One commenter (4241) states that there is disagreement between the preamble and 

the rule. The commenter points out that the preamble states that the rule requires that existing 

small dehydrators located at major sources comply with a 1.10x10-4g/scm-ppmv BTEX limit 

and new sources with a 4.66x10-6g/scm-ppmv limit. Conversely, the commenter states that the 

proposed §63.765(b)(1)(iii) does not differentiate between existing and new affected facilities 

and the emission limit used in the equation to calculate emission limits is the 1.10x10-4g/scmppmv listed in the preamble for existing units. The commenter requests that the EPA clarify this 

discrepancy in the final rulemaking package.

Response: We have revised §63.765(b)(1) to address both large and small glycol dehydration 

units. This section now also includes separate equations for calculating the emission limit for 

existing and new small glycol dehydration units. We have also added a definition for small 

glycol dehydration units in §63.761. Similarly, we revised §63.1275 of subpart HHH to address 

calculating the emission limit for existing and new small glycol dehydration units and added a 

definition for small glycol dehydration units in §63.1271.

Comment: Two commenters (4192, 4246) suggest adding English units to the definitions of 

both small and large glycol dehydration units because sources are more accustomed to these 
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units. Similarly, the commenters recommend that the definition for “temperature monitoring 

device” should include Fahrenheit measurements.

Response: The original MACT standard was written using metric units. Since we did not 

propose the entire subpart on August 23, 2011 we cannot make the requested changes at this 

time.

Comment: One commenter (4320) states that the proposed rule has included the phrase 

"[e]xcept for control devices used for small glycol dehydrators," at the beginning of several 

subparagraphs under section 63.772(e)(1), implying that these control devices are exempt from 

testing for all affected sources except small dehydrators, which puts the largest burden and focus 

on the smallest sources. 

Response: The commenter is correct that the combustion control devices listed are not exempt 

from performance testing specifically when used to reduce small dehydrator emissions. Since 

small dehydrators could require a control device to exceed a 95 percent emission reduction level 

to meet its BTEX limit, we cannot exempt such devices from performance testing and rely on 

design/operating parameters alone as we have done for large glycol dehydrator control devices.

3.2.5 Future Residual Risk Analysis

Comment: One commenter (4457) states that the EPA is proposing that, for currently controlled 

sources, the existing standard, without the 1 ton (0.9 Mg/yr) alternative compliance option, 

provides an ample margin of safety. According to the commenter, the EPA states that “we do not 

believe it will be necessary to conduct another residual risk review under CAA section 112(f) for 

these two source categories 8 years following promulgation of the small dehydrator standards 

merely due to the addition of these new MACT requirements.” 76 FR at 52769. The commenter 

asserts that this analysis is unlawful, premature, and unsupported. According to the commenter, 

the EPA may not decide now that it need not fulfill its statutory duty to review and consider 

updating these standards in 8 years. The commenter argues that this is a legal duty required by 

section 112(f)(2) that the EPA cannot change or evade. The commenter states that eight years 

after finalizing a section 112(d) or MACT limit, section 112(f)(2) requires the EPA to review and 

set a residual risk standard if required to protect public health or prevent an adverse 

environmental effect. 42 U.S.C. §7412(f)(2). The commenter opines that the EPA cannot rely on 

its conclusions in the current proposed rule to evade the statutory requirement to conduct the 

review every eight years. 

Response: Section 112(f)(2) requires that the EPA conduct residual risk analysis for a source 

category within 8 years after promulgating MACT standards for that source category. As 

explained in the proposal preamble [76 FR 52770], in our residual risk analysis for the two oil 
259

and gas major source categories, we evaluated the risks that remain after the promulgation of the 

original MACT standards as well as the new MACT standards promulgated in the final rules, 

thereby fulfilling the section 112(f)(2) requirement to conduct such an analysis within 8 years of 

the promulgation of these new MACT standards. We therefore disagree with the commenter that 

we need to conduct another residual risk review in 8 years. 

3.2.6 Storage Vessels: Previously Unregulated and Regulated Sources

Comment: One commenter (4219) states that subpart HH should not be expanded to cover 

storage vessels without PFE and questions the validity of the EPA's justification for the proposal 

to expand subpart HH to do so. The commenter asserts that if the EPA determined in 1999 that 

the MACT floor for tanks without PFE was no control and that it was not cost effective to go 

beyond the floor, then the EPA is under an obligation to explain what if anything has changed in 

the industry between then and now so as to justify the proposed expansion of subpart HH 

controls to such tanks in 2011. The commenter believes that it would be inappropriate for the 

EPA to expand the coverage of the subpart HH requirements based on an unexplained decision 

to reverse a decision made by the Agency 11 years ago concerning the contents of a 

memorandum written l3 years ago. The commenter states the study in question is dated and 

certainly is not representative of current conditions, inasmuch as it did not consider the 

environmental impacts of the production, processing, and transmission of gas extracted from 

shale plays, which in many cases is dry gas with low VOC content. The commenter contends the 

EPA should conduct a new analysis to account for current conditions in the natural gas industry 

prior to any expansion of the subpart HH requirements to tanks without PFE to ensure that there 

is justification for this significant departure from current practice. 

Additionally, the commenter (4219) claims that expansion of the rule is unwarranted because the 

cost per ton of reduced emissions for storage vessels with low VOC content is very high and 

little environmental benefit is gained by increasing control requirements. The commenter urges 

the EPA to delete provisions in the proposed subpart HH rules that would expand control 

requirements to storage vessels without PFE. Alternatively, the commenter asks that subpart HH 

control requirements only be made applicable to storage vessels with 12 tpy of VOC emissions 

to alleviate what is currently a major problem with the proposed expansion of the subpart HH 

storage vessel rules - the fact that tanks holding but a few barrels of condensate will trigger 

coverage of subpart HH under the proposed changes. The commenter believes a 12 tpy threshold 

would be justified because it would limit coverage of the rules to tanks that emit enough 

pollutants to warrant coverage by the rules. 

One commenter (4275) supports the EPA’s decision to ensure that the MACT standards protect 

human health and the environment with a generous margin of safety, as required by the CAA. 

The commenter urges the EPA to broaden the scope of types of storage vessels covered under the 
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NESHAP to include produced water tanks and also applying the standard to storage vessels in 

the natural gas storage and transmission source category. The commenter also recommends that 

the EPA consider a more stringent control requirement of 98 percent to capitalize on the 

additional air quality benefits that are possible.

Response:, In response to comments on the proposed requirements for storage vessels without 

PFE, we reevaluated the available data for all storage vessels – both NEI data and section 114 

survey information that was used to develop the original MACT requirement for storage vessels. 

Based on that evaluation, we have determined that additional data is needed in order for us to 

establish an emissions standard for storage vessels without PFE as our existing data is not 

representative of current operations and emissions. We intend to collect the necessary data and 

propose a MACT standard under section 112(d)(2) and (3) of the CAA. Therefore, we are not 

promulgating the proposed amendments that would have required all storage vessels to be 

subject to control requirements under subpart HH.

As discussed previously, we have revised the definition of “storage vessel” to clearly define the 

storage vessels subject to the final rule. 

Comment: One commenter (4263) recommends revising §63.766 to provide for the alternative 

of routing emissions to a fuel gas system or process by revising paragraph (b). The commenter 

also suggests adding a new paragraph to §63.766 stating that such systems would comply with 

certain monitoring, recordkeeping and reporting requirements, but would not have to comply 

with any other provisions of subpart HH. 

Response: In the final rule, we have added §63.766(b)(3) to provide the option of venting 

emissions through a closed-vent system to a process natural gas line. However, we did not 

exempt these systems from other applicable requirements of subpart HH.

Comment: Two commenters (4246, 4266) state that while the EPA predicts that a very small 

fraction of the production field tank population will be affected by this rulemaking, they believe 

that the total cost impact of the rule will be dramatically greater than projected by the EPA.

Response: The commenter did not provide any population data to support their statement;

therefore, no changes have been made in response to this comment.

Comment: One commenter (4246) states that the EPA’s proposed MACT standard for storage 

vessels should offer some reasonable exemptions. As an example, the commenter recommended 

that any storage vessel subject to subpart OOOO controls should be exempt from subpart HH 

standards.
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Response: As previously stated, we are not promulgating the proposed MACT standards for 

storage vessels without the potential for flash emissions. However, we have established in the 

final subpart OOOO that storage vessels that are subject to and controlled in accordance with 

subpart HH are not subject to the requirements of subpart OOOO, and provided the 

complementary exemption from subpart HH to storage vessels without the potential for flash 

emissions subject to and controlled under subpart OOOO. Since the reporting period under 

subpart OOOO is less frequent (i.e., annually) than under subpart HH (semi-annually), we have 

added in language in subpart HH requiring sources complying with subpart OOOO to still report 

on the schedule specified in subpart HH.

Comment: One commenter (4266) states that changing subpart HH to include all tanks in lieu of 

tanks “with the potential of flashing emissions” will cause some facilities to become major 

sources and that the EPA has provided no beginning effective date for this change, any 

provisions for existing facilities to come into compliance with the newly applicable regulations, 

or even adequately made the regulated public aware that they need to recalculate their 

applicability to major per the new subpart HH definitions and obtain compliance with major 

source requirements if necessary. The commenter recommends that the EPA allow such facilities 

3 years to obtain compliance with these new requirements. 

Response: The effective date for sources affected by the change in the associated equipment 

definition, as proposed, is stated in §63.760(f)(9), A production field facility, as defined in 

§63.761, constructed on or 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 date of publication of the final rule in the Federal Register must achieve 

compliance no later than three years and 60 days after date of publication of the final rule in the 

Federal Register, except as provided in §63.6(i). Also note we are not promulgating 

requirements for storage vessels without the PFE.

Comment: One commenter (4356) states that the EPA estimated there are 329 sites with a total 

of almost 2,000 tanks that would potentially be subject to the 95 percent control requirements 

throughout the country each year. According to the commenter, for the NESHAP requirements 

the EPA estimated that 1,970 existing tanks would be required to control HAP emissions. The 

commenter states that in Texas, over 3,500 sites have registered in the last 12 months with an 

average of 2-3 tanks per site (not including produced water), and this trend is expected to 

continue. Under the proposed NESHAP, the commenter believes that a large portion of these 

new tanks and thousands of existing tanks will be required to control emissions since 

applicability is based on potential to emit (PTE) of HAPs from each tank.
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Response: As we have stated previously, we are not promulgating the proposed standards for 

storage vessels without the potential for flash emissions. Thus, we have not revised our estimate 

of the number of storage vessels subject to the rule.

Comment: Two commenters (4246, 4266) request that an alternative definition of “storage 

vessel” be used in subparts OOOO and HH and suggest detailed language. The commenters state 

that there is considerable ambiguity under subpart HH as to the population of storage vessels to 

which these rules are intended to apply and requests that the EPA clarify that the boundaries of 

the storage vessel provisions. The commenters state that term “storage tank” or “storage vessel” 

should be defined in a manner that is consistent with other rules, while acknowledging the 

particular scenarios unique to the oil and gas production sector. The commenters note that 

activities identified as process functions in other regulations include reactions and blending, 

collection of material discharged from a process prior to transfer to other equipment within the 

process or to a storage vessel, surge control, bottoms receiver, and knock-outs.

Response: The EPA agrees that a clarification of the subpart HH definition of a storage vessel is 

appropriate. In the final rule, we have added a sentence to the storage vessel definition to clarify 

that surge control vessels and knockout vessels are not considered to be storage vessels under 

subpart HH. We have not excluded wastewater tanks, as there are no separate standards for 

wastewater tanks in subpart HH.

Comment: Two commenters (4246, 4266) note that, based on the MACT floor memo for 

subpart HH, in the discussion of storage tanks, the storage vessels in this source category are 

those located in the production field which store condensate or crude oil. The commenters 

request clarification that the storage vessel provisions of subpart HH are applicable only to tanks 

storing crude oil or condensate and offer suggested rule text.

Two commenters (4246, 4266) state that the EPA’s authority to extend applicability of a 

regulation to a given facility is predicated on that facility being reasonably considered a source 

of the regulated pollutant. The commenters contend that the EPA has recognized this by use of 

the term “in organic HAP service” or “in VHAP service” for NESHAP regulations. The 

commenters contend that this is not a matter of requesting an exemption for facilities that are 

sources of the regulated pollutant, but rather it is a matter of recognizing that below certain de 

minimis thresholds of concentration, a facility is not reasonably deemed a source of that 

pollutant and thus is not part of the source category. 

The commenters (4246, 4266) state that the term “in VHAP service” as defined in subpart HH 

should also be applied in the determination of applicability of subpart HH to storage vessels, in 

that the EPA is not required to regulate de minimis sources of HAPs. The commenters believe 
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that revision of the rule language would clarify that the rule is applicable to storage vessels that 

are “in VHAP service” and ensure that applicability of the rule is practicable and effective.

Response: The group of controlled storage vessels, at major sources, that we used to establish 

the MACT floor for the June 17, 1999 rulemaking included units that stored liquids other than 

those cited by the commenter (e.g., produced water). Therefore, the clarification suggested by 

the commenter is not appropriate.

The commenters request that certain storage vessels not be subject to the NESHAP requirements. 

First, we are not promulgating final standards storage vessels without the potential for flash 

emissions, as discussed elsewhere in this document. Second, we are not modifying the MACT 

standards in subpart HH applicable to storage vessels with the PFE. Finally, the commenters 

have not identified a basis for excluding such storage vessels from the MACT requirements 

where they are a source of HAP emissions subject to subpart HH standards. See National Lime 

Ass’n v. EPA, 233 F.3d 625, 640 (D.C. Cir. 2000). Therefore we have not adopted the 

commenters’ request in the final rule.

3.2.7 Definition of Associated Equipment

Comment: One commenter (4178) states that applying the current MACT standard of 95 percent 

emission reduction to all storage vessels at major source ONG production facilities, not just 

those with the potential for flash emissions (PFE) will result in otherwise minor facilities 

becoming major sources. The commenter states that facilities will have to evaluate HAP 

emissions from all of their storage tanks. The commenter adds that being elevated to major 

source status will require that the rigorous and extensive requirements of title V permitting be 

met or that the facilities obtain synthetic minor permits to stay below the major source threshold. 

Due to the added burden, the commenter states they expect that facilities will be seeking 

synthetic minor permits in significant numbers. The commenter believes the potential for an 

unwieldy number is great considering the number of facilities currently considered minor 

sources. 

Response: We believe the commenter is referring to the change in the definition of associated 

equipment that will require all storage vessels to be considered in the major source 

determination. Sources that were previously determined to be area sources, but are subsequently 

determined to be major sources due to the definition change, may obtain synthetic minor permits 

as the commenter describes. In 1999, when the MACT standard was originally promulgated, we 

estimated that there would be 440 existing sources that would become subject to the glycol 

dehydration unit and storage vessel requirements under subpart HH (64 FR 32616). This number 

did not take into account an estimate for the number of sources that would obtain synthetic minor 

permits to stay below the major source threshold and avoid being subject to subpart HH. We are 
264

not aware of any issues or undue burden that occurred during the three year period prior to the 

compliance deadline following the 1999 promulgation for existing sources seeking synthetic 

minor permits. The commenter provides no supporting information, nor do we have any, to 

suggest that there would be such burden due to this definition change.

Comment: One commenter (4457) states that the EPA proposes to amend the definition of 

“associated equipment” to exclude all storage vessels and glycol dehydrators because they are 

significant sources of HAP emissions that must be controlled and therefore must be part of the 

major source aggregation equation. The commenter supports the EPA’s proposal on that and also 

urges the EPA to exclude all other similarly situated components. The commenter asserts that the 

EPA does not explain whether it considered other components in its assessment of unregulated 

emission points beyond storage vessels and small glycol dehydrators. The commenter further 

states that, if it did consider them, the EPA does not explain why it excluded them; and if it did 

not consider them, the EPA offers no explanation for excluding them from consideration. 

According to the commenter, by leaving the definition of “associated equipment” up to the EPA, 

Congress intended that the agency identify and control substantial HAP emitters that pose a 

threat to human health and the environment. As such, according to the commenter, the EPA must 

analyze each of the significant HAP emission points in the Oil and Natural Gas Production and 

Natural Gas Transmission and Storage source categories to consider excluding them from the 

definition of associated equipment. The commenter states that this analysis is a critical 

component of the public’s understanding of the scope and quantity of HAP emissions and the 

associated risks to human health.

Response: The EPA rejects the commenter’s claim that the EPA must analyze each of the 

significant HAP emission points in the Oil and Natural Gas Production and Natural Gas 

Transmission and Storage source categories to consider excluding them from the definition of 

“associated equipment.” Nothing in the CAA prescribes such specific duty on the EPA. Neither 

did the commenter provide any legal support for this claim. On the contrary, the commenter 

acknowledges that Congress leaves the EPA discretion in defining the term “associated 

equipment.” In any event, the commenter has not provided supporting evidence or even specified 

any HAP emission point that the EPA should have, but failed to, consider for exclusion from the 

definition of “associated equipment.” For the reasons stated above, the EPA rejects this 

comment.

3.2.7.1 Exclusion of All Storage Vessels

Comment: One commenter (4266) believes the proposed changes to the definition of an affected 

facility will likely cause some existing sites that were not previously major sources to become 

major sources, due to the expansion of emission points that the EPA proposes to include in the 

major source determination. The commenter asserts that tanks at these facilities would then 
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become subject to NESHAP HH controls, but that the EPA does not appear to have taken these 

tanks into account when evaluating the impact of the proposed rule revisions.

Response: We disagree with the commenter. Our calculation of the cost and environmental 

impacts of the MACT compliance options for storage vessels (see Docket ID No. EPA-HQOAR-2010-0505-0046) was based on a dataset obtained from the NEI of storage vessels at major 

source facilities. To determine major source status of the NEI facilities, we used the proposed list 

of emission sources. Thus, the estimated number of affected sources we used to scale up costs to 

nationwide levels included the additional number of major sources due to our revised major 

source determination procedure. As discussed elsewhere in this document and preamble section 

VII.A, we are not promulgating control requirements for storage vessels without the PFE.

3.2.8 Other Comments

Comment: One commenter (4270) requests that the EPA stipulate that dehydrators with BACT 

or LAER are in compliance with subpart HHH and no further action is necessary.

The commenter (4270) also notes that companies participating in the EPA's voluntary Natural 

Gas STAR program that have implemented Best Management Practices correlating to subpart 

HHH should be exempted from the proposed rule. Since the inception of the EPA's Natural Gas 

STAR program in 1993, the commenter claims that they have voluntarily reduced emissions by 

implementing many of the best management practices detailed in the program. By now 

mandating the best management practices in the voluntary program, and requiring compliance 

monitoring, recordkeeping and reporting, the commenter claims that the EPA is adding costly 

monitoring, recordkeeping and reporting burden and undermining participating companies' 

voluntary actions to reduce emissions.

Response: The EPA has no basis in the administrative record for this rulemaking, from the 

commenter’s submission or otherwise, to conclude that BACT or LAER requirements for 

dehydrators uniformly would comply with requirements in subpart HH or HHH, as applicable. 

Concerning Natural Gas STAR participants, this is a voluntary program, as noted by the 

commenter, lacking enforceable requirements, and therefore compliance is not assured to the 

public or regulatory agencies sufficient to satisfy applicable CAA requirements.

Comment: One commenter (4245) recommends that the EPA continue to defer to the States to 

regulate emissions from small glycol dehydrators.

Response: We are required to establish MACT standards for these small glycol dehydrators. The 

CAA does not allow the EPA to delegate this obligation to the States. 

Comment: One commenter (4237) reports that the accounts of individuals at the Pittsburgh 

Public Hearing on this matter indicate that many persons are experiencing negative health 
266

impacts from breathing the air near horizontal drilling sites. The commenter asserts that it is clear 

that the emissions of section 112(b) hazardous air pollutants from these sites may not be 

completely understood. The commenter urges the EPA to conduct an investigation into what

Section 112(b) pollutants are emitted at these sites and in what concentrations.

Response: The emissions we used in our analysis were reported by facilities to their State 

regulatory agencies and then reported to the NEI. We have no reason to believe the NEI data are 

incorrect or inadequate for the purposes of this rulemaking, nor does the commenter provide any 

reason.

Comment: One commenter (4184) states that, although the EPA has not proposed to open for 

comment the section of subpart HH relative to dehydrators at area sources, they believe it would 

be prudent to apply to those dehydrators the requirements applicable to small dehydrators at 

major sources under subparts HHH and HH. The commenter states that the residual risk analysis 

required under section 112(f) performed as part of the Risk and Technology Review shows that 

the benzene emissions from TEG sources can have significant offsite benzene concentrations and 

unacceptable risks. According to the commenter, the high inhalation cancer risks are attributed to 

the 0.9 Mg per year of benzene allowed as an alternative "control" measure. Given the high 

predicted cancer risk, the commenter states that the EPA has proposed to remove this 

“alternative” compliance option for major sources. Therefore, the commenter believes it is 

reasonable to apply the same regulatory approach to area source dehydrators whether these are 

located at the well pad or at off-site compressor locations. 

One commenter (4208) states that the EPA has already proposed to regulate small and large 

dehydrators for major sources; and that they believe this approach should also be approved for 

area sources. The commenter asserts that the residual risk analysis required under section 112(f) 

shows that the benzene emissions from dehydrators can have significant offsite benzene 

concentrations with the current stack configurations, and area sources have the potential to emit 

up to 0.9 Mg and are capable of producing similar offsite impacts as major sources.

According to one commenter (4457), currently, the EPA has in place a benzene limit of 0.9 

Mg/yr for glycol dehydrator area sources. The commenter states that this limit is the same as the 

alternative compliance option for major sources. The commenter asserts that the EPA has 

recognized that removing this compliance option for major sources would significantly reduce 

public health risk. In view of that recognition, the commenter believes that the EPA cannot 

justify keeping this compliance option for area sources and asserts that doing so would be 

arbitrary and capricious.

Response: The EPA acknowledges the comment on area sources. However, as one commenter 

notes, this action relates to the EPA’s review of the two oil and gas major source categories. The 
267

EPA did not review area sources and did not reopen any area source standards for notice and 

comment and is therefore not addressing area sources in this final rule. In any event, as discussed 

in the preamble to the final rule, in response to comments noting certain errors in the EPA’s risk 

assessment, the EPA has reviewed and revised the risk assessments for both oil and gas major 

source categories. Based on the revised risk assessment, we have determined that the MACT 

standards, including those promulgated in this final rule pursuant to sections 112(d)(2)-(3), 

reflect an acceptable level of risk and provide an ample margin of safety. We are also retaining 

the 0.9 Mg per year of benzene alternative compliance option, which we had proposed to remove 

based on our incorrect determination that it was driving the MIR. 

Comment: One commenter (4192) recommends that §63.760(f)(7) be modified to be consistent 

with 40 CFR part 60, subpart OOOO (which generally applies to facilities undertaking 

construction after August 23, 2011), as follows: “Each affected small glycol dehydration unit and 

each storage vessel that is not a storage vessel with the potential for flash emissions located at a 

major source, that commenced construction [add: on or] before August 23, 2011 must achieve 

compliance no later than 3 years after the date of publication of the final rule in the Federal 

Register, except as provided in §63.6(i).”

One commenter (4192) recommends that §63.760(f)(8) and (f)(9) be modified by removing the 

phrase “on or” to be consistent with subpart OOOO. 

Response: We disagree with the recommendations made by the commenter. We believe that 

§§63.760(f)(7) and (f)(8) are consistent with the requirements of §63.6.

Comment: One commenter (4263) requests that the EPA correct paragraph §63.771(f) as 

follows:

(f) Control device requirements for small glycol dehydration units. (1) The control device used 

to meet the BTEX emission limit calculated in §63.765(b)(1)(iii) shall be one of the control 

devices specified in paragraphs (f)(1)(i) through (iii) of this section.

Response: We agree that the suggested change would provide clarity to this paragraph and have 

made the change in the final rule.

3.3 Risk Assessment

3.3.1 General Comments on the Methods Used to Assess Risk

Comment: For Subpart HHH, one commenter (4174) states that the EPA improperly used 

formaldehyde emissions from reciprocating internal combustion engines (RICE) to justify 
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emission controls for benzene for this source category. The commenter believes that the EPA 

should withdraw these proposed provisions. 

Response: The commenter’s assertion that we used formaldehyde emissions from RICE to 

propose emission controls for benzene for subpart HHH is incorrect. The BTEX limits for small 

dehydrators are MACT requirements, and are not based on risk or emissions from RICE, and the 

proposed elimination in the large glycol dehydrator MACT standards of the alternative 

compliance option of 0.9 Mg/yr benzene was based on risk results from benzene emissions from 

the two oil and gas source categories and not from RICE. In addition, as discussed in the 

preamble and elsewhere in this document, we are retaining the existing alternative compliance 

option of 0.9 Mg/yr benzene for large glycol dehydrators.

Comment: One commenter (4215) is concerned that the EPA has made the decision to go 

forward with these expansive rules without properly quantifying the need for regulation. 

According to the commenter, the EPA states that it did not have time (because of the truncated 

timeline it agreed to in the consent order) to do air quality monitoring. The commenter states that 

what data the EPA does have (the residual risk analysis) shows nearly non-existent health-based 

risks. 

One commenter (4266) asserts that available data overwhelmingly show that the current 

standards protect public health with an ample margin of safety. The commenter states that 

regulation for the sake of regulation contradicts the Congress’s clear intent that an ample margin 

of safety is an appropriate stopping point for emissions limitations under section 112.

Response: The final rule is based on the information available to the Administrator, including 

data and emissions information provided by commenters. The commenter alleges that the EPA 

didn’t have enough time to do air quality monitoring. However, nowhere in the proposal did the 

EPA suggest that it had to have new air quality monitoring data to complete the residual risk 

analysis. For that review, we used NEI data, as we have done for most other source categories. It 

is not clear as to what the commenter is referring when it posits that we need additional “air 

quality monitoring.” We typically do not perform air quality monitoring as part of an RTR 

rulemaking. Further, as explained in the preamble to the final rule, we concluded that the MACT 

standards in subpart HH (coupled with the new MACT standard for small glycol dehydrators) 

provide an ample margin of safety to protect public health and prevent adverse environmental 

effects, and thus did not revise those standards pursuant to section 112(f).

Comment: Two commenters (4266, 4354) state that the EPA inappropriately proposes to apply 

new measures in the determination of acceptable risk and ample margin of safety. Commenters 

state that the “total facility” approach to conducting risk assessment exceeds the EPA’s authority. 

Commenters also state that demographics may not be considered in conducting risk assessments 
269

under section 112(f). The commenters state that while the EPA can consider other health-based 

factors in making its decision, it cannot replace or undermine the original 1989 Benzene 

NESHAP framework. The commenters believe that consideration of facility-wide risks is 

contrary to the express language of the statute, is bad policy, and should not apply to the EPA's 

residual risk review under section 112(f). 

Another commenter (4354) states that because the term “public health” cannot reasonably be 

interpreted to include consideration of environmental justice in the section 112(f) context, the 

EPA’s proposal to consider demographic analyses in conducting risk reviews under section 

112(f) is not a proper exercise of Agency authority. The commenter contends that section 

112(f)(2)(A) expressly instructs the EPA to impose additional emissions controls if needed to 

provide an ample margin of safety “to protect public health.” The commenter points out that the 

term “public health” is not defined in section 112 or in the EPA’s Part 63 regulations. The 

commenter states that the EPA’s approach would inappropriately cause arbitrary policy and 

political considerations to trump objective scientific analysis. The commenter stated that this is 

unreasonable and is not a supportable interpretation of section 112(f).

Two commenters (4159, 4273) state that the EPA cannot exceed its statutory authorities in 

addressing environmental justice concerns under section 112. The commenters assert that the 

EPA should not consider demographics in making regulatory decisions without evidence 

showing that the demographic category is more vulnerable to the specific health effects caused 

by the source category emissions beyond mere proximity to the source. The commenters state the 

EPA is correct in concluding that no demographic group is exposed to an unacceptable level of 

risk. The commenters believe that the EPA should consider the potential repercussions to 

communities of the potential loss of industry when taking into account environmental justice 

issues.

Response: We disagree that examining facility-wide risk in a risk assessment conducted under 

section 112(f) exceeds the EPA’s authority. We examined facility-wide risks to provide 

additional context to the source category risks. In May 2010, the SAB advised us “RTR

assessments will be most useful to decision makers and communities if results are presented in 

the broader context of aggregate and cumulative risks, including background concentrations and 

contributions from other sources in the area.” The development of facility-wide risk estimates 

provides additional information about the potential cumulative risks in the vicinity of the RTR 

sources, as one means of informing potential risk-based decisions about the RTR source category 

or categories in question. While we recognize that, because these risk estimates were derived 

from facility-wide emissions estimates which have not generally been subjected to the same level 

of engineering review as the source category emission estimates, they may be less certain than 

our risk estimates for the source categories in question, but they remain important for providing 

context as long as their uncertainty is taken into consideration in the process.
270

Our evaluation of facility-wide risks did not change our decisions under section 112(f)(2) about 

acceptability and ample margin of safety of the risks associated with the two oil and gas source 

categories. Therefore, comments on how these factors were used by the EPA in determining 

acceptable risks and ample margin of safety are not germane to the final rule. We note, however, 

that section 112(f)(2) of the CAA expressly preserves our use of the two-step process for 

developing standards to address residual risk and interpret “ample margin of safety” as 

developed in the Benzene NESHAP. In both the Benzene NESHAP and our Residual Risk 

Report to Congress, we explain that we do not define “rigid line(s) of acceptability” and that we 

will consider a series of other health measures and factors in determining if risk is acceptable. 

Our authority to use the two-step process laid out in the Benzene NESHAP, and to consider a 

variety of measures of risk to public health, is discussed more thoroughly in the preamble to the 

proposed rule. Nothing in the CAA or the Benzene NESHAP in any way forecloses us from 

considering facility-wide risks in making a determination under section 112(f)(2), as such 

information can constitute relevant health information. While we also provided a demographic 

analysis of populations surrounding the facilities in the source categories addressed by this RTR, 

the results of our demographic analysis only serve to provide information about the demographic 

make-up of the populations exposed to each of these source categories which might benefit from 

the proposed rules and did not affect any decision in this rulemaking.

Comment: Two commenters (4184, 4208) state that the socio-demographic analysis in the RTR 

fails to fully evaluate potential environmental justice issues because it did not consider 

fundamental aspects of disproportionate impacts to these neighborhoods. The commenters are 

unsure why a different approach was used in the demographic analyses for the Oil and Natural 

Gas Production and Natural Gas Transmission source categories than in the recent RTR analysis 

for Hard and Decorative Chromium Electroplating and Chromium Anodizing Tanks. The 

analyses for the chrome categories considered individuals projected to experience a risk greater 

than 1-in-1-million and individuals living within 5 km of the facility, regardless of projected risk. 

The commenter is concerned that the 50 km radius used in the RTR for the oil and gas source 

categories has the potential to include a greater proportion of individuals not in the target 

demographic groups, in instances where the operation is located in a minority and low-income 

community. The commenters recommend an additional analysis at the 5 km distance be 

conducted to assess facility impacts to nearby environmental justice communities since the 

sources associated with this industry have relatively low stacks that could result in nearby 

impacts. One of the commenters (4208) added that the EPA needs to develop criteria and specific 

guidance on how to interpret and apply the outcome of these types of analyses in the rulemaking 

process.

Response: The commenter is correct that we performed the demographic analyses for the oil and 

gas source categories differently than we did for the October 2010 proposed RTR for the chrome 
271

source categories. We performed the demographic analyses for the chrome source categories 

using two approaches as examples of how such analyses might be developed, and invited public 

comment on the approaches used and the interpretations made from the results. In the first 

approach, we focused the analysis on the total populations residing within 5 km of each facility, 

regardless of their estimated risks, and examined the distributions across various demographic 

groups within those 5 km circles. That analysis was a “proximity” analysis in that it considered 

only the distance from the emission sources to surrounding populations, and not the estimated 

risks to those populations 

In the second approach, we focused the analysis on the populations within 5 km of any facility 

estimated to have exposures to HAP which result in cancer risks of 1-in-1 million or greater or 

non-cancer hazard indices of 1 or greater. We examined the distributions of those risks across 

various demographic groups. In each approach, we compared the percentages of particular 

demographic groups to the total number of people in those demographic groups nationwide. We 

stated in the proposed rule for the chrome source categories that in future rules we planned to 

extend the analyses to cover the entire modeled domain for a facility (50 km radius) to capture 

all individuals with risks above 1-in-1 million or greater or non-cancer hazard indices of 1 or 

greater. We also stated that generally we have found that using a 5 km radius in the analysis will 

capture more than 90 percent of the individuals with cancer risks above 1-in-1 million.

In the February 2012 supplemental proposal for the RTR for the chrome source categories, our 

demographic analyses included populations within 50 km of each source (including those very 

near the sources) with risks of 1-in-1 million or greater or non-cancer hazard indices of 1 or 

greater. (77 FR 6628, Feb. 8, 2012). We did not include analyses using a 5 km radius in that 

supplemental proposal nor in the RTR proposal for the oil and gas source categories. We believe 

that, where a risk assessment has been performed, it is more informative to consider the 

demographics of all populations (including those beyond 5 km) with elevated risks than to limit 

the demographics analysis to populations located within 5 km of a facility. Where risk 

assessment has been performed, these populations are identified, and the source parameters (like 

the low release height mentioned by the commenter) are accounted for. As discussed above, we 

have found that most exposure locations with the highest estimated risks are within 5 km of a 

facility, so extending the radius to 50 km has little impact on an analysis based on risks, but 

makes more sense because 50 km corresponds to the risk modeling radius and includes all 

populations with elevated risk estimates. As indicated above, our evaluation of demographics did 

not affect our decisions about acceptability and ample margin of safety of the risks associated 

with these source categories.

Comment: Several commenters (4159, 4220, 4273) support the EPA's continued reliance on the 

decision framework included in the 1989 Benzene NESHAP in determining whether further 

regulation is appropriate under section 1l2(f), but question the EPA's reliance on conservative 
272

risk assumptions to make these determinations. The commenters state that the EPA has used 

multiple conservative approaches that arbitrarily inflate final estimates of risk by a factor of 100 

to 1,000 over the most likely/central estimates of risk. Specifically, the commenters object to the 

following approaches: 1) assuming that all members of the population are continuously exposed 

for their lifetimes; 2) failing to consider time-activity patterns; 3) using only the high end of the 

benzene URE for decision-making; and 4) using only ultra-conservative URE from CalEPA in 

the absence of IRIS values. 

Response: As discussed in the preamble to the final rule and pursuant to section 112(f)(2)(A) 

and (B), we agree that the decision framework set forth by the Benzene NESHAP is appropriate 

for residual risk determinations, but we disagree with the commenters’ assertions that our risk 

estimates are improper or arbitrarily inflated. Regarding exposure times and the consideration of 

time-activity patterns, we believe our risk assumptions are appropriately conservative; moreover, 

we do not believe that such considerations would significantly lower the general estimates of 

individual risks. Results from EPA’s National-Scale Air Toxics Assessment (NATA)27 (which 

model daily activity using EPA’s HAPEM model) indicate that while considering 

microenvironment concentrations and daily activities would, on average, reduce risk estimates 

about 25 percent for particulate HAPs, such considerations would reduce risk estimates for 

gaseous HAPs like benzene (which are the HAPs at issue) by much less. Further, the Benzene 

NESHAP defines the maximum individual risk (MIR) as “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” and explains that this measure of risk “is an estimate of the upper bound of risk based 

on conservative assumptions, such as continuous exposure for 24 hours per day for 70 years.” 54 

FR at 38044-38045.

The high end of the reported benzene cancer URE range was used in our assessments to provide 

a conservative estimate of potential cancer risks. Use of the high end of the range provides risk 

estimates that are approximately 3.5 times higher than use of the equally-plausible low end 

value. As stated in the preamble to the proposed rule (76 FR 52771), however, we also evaluated 

the impact of using the low end of the URE range on our risk results, and we considered both 

results in the determination of acceptability and ample margin of safety.

Commenters do not state which pollutants they consider as having overly conservative URE 

values. The CalEPA Office of Environmental Health Hazard Assessment has developed doseresponse assessments for many substances, based both on carcinogenicity and health effects 

other than cancer. The process for developing these assessments is similar to that used by the 

EPA to develop IRIS values and incorporates significant external scientific peer review. The 

non-cancer information includes available inhalation health risk guidance values expressed as 

 

27 www.epa.gov/nata.
273

chronic inhalation and oral reference exposure levels (RELs). CalEPA defines the REL as a 

concentration level at (or below) which no health effects are anticipated, a concept that is 

substantially similar to the EPA's non-cancer dose-response assessment perspective. CalEPA's 

quantitative dose-response information on carcinogenicity by inhalation exposure is expressed in 

terms of the URE, defined similarly to the EPA's URE. We have a prioritization process 

designed to incorporate into our assessments the best available science with respect to doseresponse information. This information is obtained from various sources and prioritized 

according to (1) conceptual consistency with the EPA risk assessment guidelines and (2) level of 

peer review received. Where we are lacking dose-response information with higher priority (e.g., 

IRIS), we use other information sources, such as CalEPA.

Comment: One commenter (4184) believes that the national median household income figure 

should be updated from the 1999 figure used for the past three NESHAPs. The number of people 

in poverty in 2010 is much larger than it was in 1999. Because historical Census values have 

been used, the commenter is concerned that the impact to minority and low-income communities 

has not been adequately addressed. 

Another commenter (4208) states that poverty statistics used to identify low-income 

communities should be updated to include 2010 Census data, rather than relying on older 

information. The commenter notes that the number of people in poverty in 2010 is the largest 

number in the 52 years for which poverty estimates have been published.

Response: The EPA agrees that the estimate of the percentage of people in poverty has increased 

between the 2000 Census (13 percent) and the 2010 Census (14 percent), but disagrees that this 

increase warrants re-doing the demographic analyses for these source categories. However, we 

intend to use the 2010 Census data in future analyses.

Comment: One commenter (4184) is concerned about the use of emergency planning response 

levels to assess acute risk to the general public, especially when these levels exceed current 

occupational standards or guidelines that were developed to protect healthy workers from acute 

chemical exposures. The commenter believes that calculating the hazard quotient from the acute 

occupational exposure values when they are below the emergency response values would 

represent a more valid approach to evaluating the potential for acute health effects from a 

source's emissions. The commenter believes this procedure will better characterize and validate 

the determination of worse case emissions as appropriately representative of the conditions the 

EPA is seeking to address in the acute exposure scenario.

Another commenter (4208) has concerns with the EPA’s use of AEGL or ERPG values to 

address acute exposures in the residual risk assessments. The commenter states that, unlike the 

RfCs for chronic exposures, the AEGLs and ERPGs do not include adequate safety and 
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uncertainty factors and cannot be relied upon to protect the public from the adverse effects of 

exposure to toxic air pollutants. The commenter notes that the use of AEGLs or ERPGs in 

residual risk assessments is not appropriate and does not ensure that public health is adequately 

protected from the acute impacts of HAP exposure. The commenter supports the EPA’s 

increased reliance on the California Reference Exposure Levels (RELs) to address acute 

exposures in the residual risk assessments and urges the EPA to use the RELs for these 

assessments. The commenter recommends that the EPA not rely on the AEGL, especially in 

cases where it exceeds the acute occupational guidelines. The commenter adds that EPA’s 

analysis shows a high level of acute health risk for both source categories and is unclear why the 

EPA is not proposing to reduce those health risks.

One commenter (4457) states that occupational exposure levels help demonstrate why the AEGL 

is not protective enough, but that the EPA should not use the occupational levels in place of the 

reference exposure level (REL) values created for the purpose of community resident exposure 

near a facility. The commenter also asserts that, after finding acute exposure levels 5 and 9 times 

the REL, the EPA has failed to justify not requiring the reduction of acute health risks.

Another commenter (4170) states that the use of occupational values is appropriate for this risk 

assessment and recommends that setting acute exposure limits on benzene, and any other air 

pollutant, be based upon the National Institute for Occupational Safety and Health (NIOSH) 

short-term exposure limit (STEL). The commenter recommends modifying the 15-minute time 

weighted average (TWA) STEL by diving by 4 to convert the 15 minute TWA to a 1-hour TWA, 

and dividing by 10 to account for sensitivity variation in the general human population, resulting 

in a benzene acute exposure benchmark of 0.4 mg/m3. The commenter notes that the EPA’s 

maximum 1-hour benzene concentration exceeds this value, but states that this likely would not 

cause non-cancer health concerns because the acute modeling scenario is worst-case due to the 

confluence of peak emission rates and worst case conditions.

Response: As discussed in the preamble to the proposed rule (76 FR 52772), the EPA considers 

various acute health effect reference values, including the California acute REL, and AEGL and 

ERPG values, in assessing the potential for risks from acute exposures. Occupational values, 

including STELs, typically are not used for the purpose of characterizing public health risks in 

RTR assessments because they are developed for a worker population of presumed healthy 

working-age adults and are not typically considered protective for the general public. Because 

they are developed for healthy working-age adults, occupational values usually exceed AEGL-1 

and ERPG-1 levels. However, for a few chemicals (including benzene), the one-hour AEGL-1 

and EPRG-1 values are higher than the STELs, and for this reason the comparison of the 

estimated maximum one-hour exposure to the AEGL and ERPG values is not appropriate as a 

secondary guideline for assessing potential acute risks from benzene exposure in community 

settings. The NIOSH benzene STEL for exposures of 15 minutes or less (8 mg/m3) is below the 
275

AEGL-1 value of 170 mg/m3and the ERPG-1 value of 160 mg/m3. Although we agree that in the 

case of benzene the level of the STEL indicates that the AEGL-1 and EPRG-1 values are not 

appropriate as secondary guidelines, we do not agree that the STEL should be used in place of an 

existing REL as a primary value to characterize acute exposures for RTR assessments because 

the population they are intended for is not representative of the general public, including 

sensitive subpopulations. The REL is one of the preferred acute values for use in RTR, as 

endorsed by SAB.

We disagree with the comment that recommends modifying the NIOSH STEL value. First, the 

California REL value is 1.3 mg/m3for a 6-hour exposure, but is applicable to any duration less 

than that.28

Based on the conservative nature of the acute exposure scenario used in the screening assessment 

for these source categories, the EPA has judged that, considering all associated uncertainties, the 

potential for effects from acute benzene exposures is low. Screening estimates of acute exposures 

were evaluated for each HAP at the point of highest off-site exposure for each facility (i.e., not 

just the census block centroids) assuming that a person is present at this location at a time when 

both the peak emission rate and worst-case dispersion conditions occur. Under these worst-case 

conditions, we estimate the benzene acute HQ values (based on the REL) could be as high as 9. 

Although the REL (which indicates the level below which adverse effects are not anticipated) is 

exceeded in this case, we believe the potential for acute effects is low for several reasons. First, 

the acute modeling scenario is worst-case because of the confluence of peak emission rates and 

worst-case dispersion conditions. Also, the generally sparse populations near the facilities with 

the highest estimated 1-hour exposures make it less likely that a person would be near the plant 

to be exposed.

Comment: One commenter (4208) recommends that the EPA use the truly maximum individual 

risk, irrespective of its location in the census block, in its section 112(f)(2) risk assessments.

Response: As we have explained in previous RTRs, such as the SOCMI HON RTR (71 FR 

76603, December 21, 2006), the EPA believes that, in a national-scale assessment of lifetime 

inhalation exposures and health risks from facilities in a source category, it is appropriate to 

identify exposure locations where it may be reasonably expected that an individual will spend a 

majority of his or her lifetime. Further, in determining chronic risks, the EPA believes that it is 

 

28 OEHHA. (1999). The Air Toxics Hot Spots Program Risk Assessment Guidelines. Technical 

Support Document For the Derivation of Noncancer Reference Exposure Levels. Air Toxicology 

and Epidemiology Section, Office of Environmental Health Hazard Assessment, California 

Environmental Protection Agency. June 2008. 

http://oehha.ca.gov/air/hot_spots/2008/NoncancerTSD_final.pdf.
276

appropriate to use census block information on where people actually reside, rather than points 

on a fence-line, to locate the estimation of exposures and risks to individuals living near such 

facilities. 

Census blocks are the finest resolution available as part of the nationwide population data (as 

developed by the US Census Bureau); each is typically comprised of approximately 40 people or 

about 10 households. In EPA risk assessments, the geographic centroid of each census block 

containing at least one person is used to represent the location where all the people in that census 

block live. The census block centroid with the highest estimated exposure then becomes the 

location of maximum exposure, and the entire population of that census block experiences the 

maximum individual risk. In some cases, because actual residence locations may be closer to or 

farther from facility emission points, this may result in an overestimate or underestimate of the 

actual annual concentrations (although there is no systematic bias for average levels). Given the 

relatively small dimensions of census blocks in densely-populated areas, there is little 

uncertainty introduced by using the census block centroids in lieu of actual residence locations. 

There is the potential for more uncertainty when census blocks are larger, although there is still 

no bias on average. The EPA concludes that the most appropriate locations at which to estimate 

chronic exposures and risks are the census block centroids because: 1) census blocks are the 

finest resolution available in the national census data, 2) facility fencelines do not typically 

represent locations where chronic exposures are likely, and 3) there is no bias introduced into the 

estimate of the MIR by using census block centroid locations.

Comment: Two commenters (4208, 4457) state that the EPA needs to fully consider and address 

multipathway risk and also add this risk to the inhalation risk, when assessing the level of public 

health risk to which communities are exposed. One commenter (4457) believes the EPA failed to 

fulfill its duty to consider or address whether a more stringent limit than the existing MACT is 

required to protect the environment. The commenter states that the EPA must perform an 

ecological risk assessment for the oil and gas sector, and may not rely solely on the human health 

assessment without a reasoned explanation for doing so that is not supported by scientific 

evidence in the record. The commenter asserts that the EPA has neither carried out the required 

ecological risk assessment, including evaluating whether there are effects that would warrant 

consultation under the ESA, nor presented a reasoned explanation supported by science in the 

record.

Response: Contrary to the commenter’s assertions, we considered and addressed the potential 

for multipathway and environmental effects. The potential for significant human health risks or 

environmental effects due to exposures via routes other than inhalation (i.e., multipathway 

chronic exposures) was screened by first determining whether any sources emitted any hazardous 

air pollutants known to be persistent and bioaccumulative in the environment (PB-HAP). The 

only PB-HAP identified in the emissions inventories for the oil and gas source categories was 
277

polycyclic organic matter (POM). These emissions were compared to levels developed for each 

PB–HAP using a hypothetical worst-case screening exposure scenario (See 76 FR 52773), where 

the levels represent a maximum lifetime cancer risk of 1 in a million or a hazard quotient of 1 for 

noncancer impacts. The POM emissions from the Oil and Natural Gas Production source 

category were below these levels, and the POM emissions from one facility in the Natural Gas 

Transmission and Storage source category exceeded (by a factor of 6) the level equivalent to 1 in 

a million lifetime cancer risk.

For POM, we identified dairy, vegetables, and fruits as the three most dominant exposure 

pathways driving human exposures in the screening exposure scenario. The single facility with 

emissions exceeding the screening level for POM is located in a highly industrialized area. 

Therefore, the exposure pathways driving human exposure are unlikely for this facility, and the 

ingestion cancer risk in this case would likely be much lower than 6-in-1 million. The inhalation 

cancer risk for this facility is 0.6-in-1 million, so even if the risks from all pathways were 

combined, they would be low. For the reasons discussed above, multi-pathway exposures and 

environmental risks (due to exposures via routes other than inhalation) were deemed low for 

these source categories, and we determined that no further quantitative multipathway analysis 

was necessary.

We evaluated the potential for significant ecological effects due to exposures via inhalation from 

exceedances of chronic human health inhalation thresholds in the ambient air near these 

facilities. Human health dose-response threshold values are generally derived from studies 

conducted on laboratory animals (such as rodents) and developed with the inclusions of 

uncertainty factors that could be as high as 3000. As a result, these human threshold values are 

often significantly lower than the level expected to cause an adverse effect in an exposed rodent. 

It should be noted that there is a scarcity of data on the direct atmospheric impact of these HAPs 

on other receptors, such as plants, birds, and wildlife and that the EPA will continue to monitor 

the scientific literature for new data in this area. Thus, if the maximum inhalation hazard in an 

ecosystem is below the level of concern for humans, which is the case for these source 

categories, see preamble discussion addressing risk review, we have generally concluded that 

mammalian receptors should be at no risk of adverse effects due to inhalation exposures from 

non PB-HAP, and have assurance that other ecological receptors are also not at any significant 

risk from direct atmospheric impact. Given the record, we reach such conclusion here. No 

comments were received that provided any additional information indicating potential 

environmental effects of the pollutants in the oil and gas source categories.

Comment: One commenter (4248) states that the proposed rule is subject to the EPA and OMB 

Information Quality Act (IQA) guidelines yet has failed to rely on the best available science in 

developing the proposed rule. The commenter states that, contrary to IQA guidelines, the EPA 

inappropriately applies the outdated IRIS dose-response values in determining formaldehyde 
278

inhalation exposure risk in support of the proposed rule. The commenter also states that the NAS 

report should be used in determining what constitutes the best available science and that the 

deference given to the 1991 IRIS assessment is directly at odds with the EPA’s mandate to 

“consider all credible and relevant information” in a rulemaking proceeding. The commenter 

adds that the EPA’s proposed rule should be based on the best available science at the time of the 

rulemaking and recommends incorporating the CIIT dose-response value in accordance with the 

recommendation of the NAS panel. 

Response: In 2004, the EPA determined that the Chemical Industry Institute of Toxicology 

(CIIT) cancer dose-response value for formaldehyde (5.5 x 10-9 per μg/m3) was based on better 

science than the IRIS cancer dose-response value (1.3 x 10-5 per μg/m3), and we switched from 

using the IRIS value to the CIIT value in risk assessments supporting regulatory actions. 

Subsequent research published by the EPA suggested that the CIIT model was not appropriate 

and, in 2010, the EPA returned to using the 1991 IRIS value. The EPA has been working on 

revising the formaldehyde IRIS assessment and the National Academy of Sciences (NAS) 

completed its review of the EPA’s draft assessment in April of 2011.29 The EPA will follow the 

NAS Report recommendations and will present results obtained by implementing the 

biologically-based dose-response (BBDR) model for formaldehyde. The EPA will compare these 

estimates with those currently presented in the External Review draft of the assessment and will 

discuss their strengths and weaknesses. As recommended by the NAS committee, appropriate 

sensitivity and uncertainty analyses will be an integral component of implementing the BBDR 

model. In the interim, we will present findings using the 1991 IRIS value as a primary estimate, 

and the EPA may also consider other information as the science evolves. Although formaldehyde 

was a driver of the risks attributable to facility-wide emissions, it did not change our decisions 

about acceptability and ample margin of safety of the risks associated with these source 

categories.

Comment: One commenter (4208) recommends that the EPA consider potential or allowable 

emissions, rather than actual emissions, in evaluating residual risk. The commenter states that 

because facility emissions could increase over time for a variety of reasons, and with them the 

associated impacts, the use of potential or allowable emissions is more appropriate. The 

commenter believes an analysis based on actual emissions from a single point in time could 

underestimate the residual risk from a source category. Further, the commenter states that major 

source HAP thresholds are based on the potential to emit, as opposed to actual emissions, and air 

agencies issue permits based on potential emissions. The commenter states that limiting the 

scope of a risk evaluation to actual emissions would be inconsistent with the applicability section 

of Part 63 rules. Further, the commenter recommends that the EPA assess acute health risks 

based on allowable emissions.

 

29 http://www.nap.edu/catalog.php?record_id=13142
279

Two commenters (4266, 4354) believe that the EPA fails to provide a rational basis for using 

allowable emissions in conducting risk assessments under section 112(f). The commenters state 

that the EPA proposes to find that the “risks are unacceptable” under the current subpart HH 

“due to MACT-allowable emissions” and, therefore, proposes to eliminate the 0.9 Mg/yr 

compliance alternative for dehydrators. The commenters state that the EPA cannot lawfully use 

MACT allowable emissions in the proposed risk assessments and residual risk determinations 

because the Agency has failed to provide any reasoned explanation for why risk assessments 

based on actual emissions estimates are inadequate. The commenters contend that section 

112(f)(1)(B) required the EPA also to report on “the actual health effects with respect to persons 

living in the vicinity of affected sources.” The commenters assert that it is unreasonable for the 

EPA to construe section 112(f) as authorizing the Agency to conduct risk assessments based on 

hypothetical “MACT allowable” emissions. According to the commenters, the Agency’s risk 

assessment methodology already is rife with conservative assumptions. The commenters 

similarly assert that the dispersion models used to predict off-site ambient HAP concentrations 

attributable to emissions from affected sources incorporate numerous conservative assumptions 

to simplify the analysis of highly complex factors, such as meteorology and atmospheric 

chemistry. In addition, the commenters state that risk assessments assume exposure to the most 

exposed individual on a continuous basis for an entire lifetime. The commenters believe that the 

failure to provide a reasoned explanation as to why this approach is justified and the failure to 

provide any record evidence supporting the use of MACT allowable emissions render this 

proposal insupportable under the law.

Response: Consistent with previous risk assessments, the EPA considers both allowable and 

actual emissions in assessing chronic exposure and risk under section 112(f)(2). (see, e.g., 

National Emission Standards for Coke Oven Batteries (70 FR 19998-19999, April 15, 2005); 

proposed and final National Emission Standards for Organic Hazardous Air Pollutants from the 

Synthetic Organic Chemical Manufacturing Industry (71 FR 34428, June 14, 2006, and 71 FR 

76603, December 21, 2006). This approach is both reasonable and consistent with the flexibility 

inherent in the Benzene NESHAP framework for assessing ample margin of safety. As a general 

matter, modeling allowable emissions levels is inherently reasonable since this reflects the 

maximum level sources could emit and still comply with national emission standards. But it is 

also reasonable to consider actual emissions, where such data are available, in both steps of the 

risk analysis. See National Emission Standards for Coke Oven Batteries, 70 FR 19992, 19998 

(April 15, 2005).

For emission points without MACT standards, we used actual emissions levels. We disagree 

with the commenter who suggested the use of allowable emissions in the assessment of acute 

effects. Our acute health risk screening in this rulemaking already uses conservative assumptions 

for emission rates, meteorology, and exposure location, including 1) peak 1-hour emissions that 
280

are 10 times the average 1-hour emission rates; 2) worst-case meteorology (from one year of 

local meteorology); and 3) that a person is located downwind at the point of maximum impact 

during this same 1-hour period.

We disagree with the commenter who does not support the consideration of allowable emissions 

because the “risk assessment methodology already is rife with conservative assumptions.” As 

explained above, we believe that considering allowable emissions is reasonable and consistent 

with the flexibility inherent in the Benzene NESHAP framework for assessing chronic risk. The 

commenter also does not provide specific details supporting their conclusion about how the 

chronic risk assessment is conservative. Elsewhere in this document we provide responses to 

comments on conservatism in specific aspects of our assessment. In addition, as discussed in the 

preamble, we updated our risk assessment, conclude that the MACT standards (including those 

promulgated in this rulemaking) for the two source categories provide an ample margin of safety, 

and are retaining the existing alternative compliance option of 0.9 Mg/yr benzene for large 

glycol dehydrators.

3.3.2 Uncertainties in the Risk Assessment

Comment: One commenter (4189) states that in setting residual risk standards under section 

112(f)(2), the EPA must assess and set limits to protect the most vulnerable populations living 

near ONG facilities from the health threats caused by toxic air pollution. The EPA should follow 

the lead of the California Office of Environmental Health Hazard Assessment by including early 

life vulnerability in all cancer assessments and accounting for increased prenatal susceptibility to 

carcinogens, and by accounting for early life vulnerability to other health risks. To address the 

additional health risk to children and overburdened communities, the commenter suggests that 

the EPA should use an additional 10-fold uncertainty factor. The commenter states that the EPA 

barely mentions health in its “ample margin” analysis and focuses almost exclusively on cost 

considerations. The commenter believes that the EPA must correct this error by assessing the 

level of emissions needed to provide an “ample” margin of safety for public health, explaining 

that analysis, and finalizing a rule that provides that level of protection. 

Another commenter (4208) states that the EPA needs to better assess and address the public 

health impacts of the oil and natural gas sector to ensure that local communities receive the 

required protection from unacceptable health risk. The commenter encourages the EPA to pay 

special attention to the needs of children and those communities that have had a history of 

disproportionate risk and are exposed to multiple sources of air pollution.

Response: We acknowledge that population subgroups, including children, may have the 

potential for risk greater than the general population due to greater relative exposure and/or 

greater susceptibility to the toxicant. As explained in previous actions, including the final 
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SOCMI HON RTR (71 FR 76603, Dec. 21, 2006), the assessments we undertake to estimate risk 

account for this potential vulnerability. With respect to exposure, the risk assessments we 

perform implicitly account for this greater potential for exposure by assuming lifetime exposure, 

in which populations are conservatively presumed to be exposed to airborne concentrations at 

their residence continuously, 24 hours per day for a full lifetime, including childhood. With 

regard to children’s potentially greater susceptibility to non-cancer toxicants, the assessments 

rely on Agency (or comparable) hazard identification and dose-response values which have been 

developed to be protective for all subgroups of the general population, including children. For 

example, a review of the chronic reference value process30 concluded that the Agency’s 

reference concentration (RfC) derivation processes adequately considered potential susceptibility 

of different subgroups with specific consideration of children, such that the resultant RfC values 

pertain to the full human population “including sensitive subgroups,” a phrase which is inclusive 

of childhood.

On the issue of cancer dose-response values, the EPA’s revised cancer guidelines31 and 

supplemental guidance32 recommend applying default adjustment factors to account for 

exposures occurring during early-life exposure to those chemicals thought to cause cancer via a 

mutagenic mode of action. For these chemicals, the supplemental guidance indicates that, in lieu 

of chemical-specific data on which age or life-stage specific risk estimates or potencies can be 

determined, default “age dependent adjustment factors” can be applied when assessing cancer 

risk for early-life exposures to chemicals which cause cancer through a mutagenic mode. There 

are three HAPs (acrylamide, benz[a]anthracene, and benzo[a]pyrene) emitted from these source 

categories that the EPA has determined have a mutagenic mode of action for carcinogenesis. The 

UREs for these HAPs include adjustments by age dependent adjustment factors and were used in 

the risk assessment. 

Comment: One commenter (4267) states that the use of a draft document on risk assessment 

(Draft Residual Risk Assessment for the Oil and Gas Production and Natural Gas Transmission 

and Storage Source Categories, see proposal preamble at 76 FR 52770) does not meet any 

objective criteria for decision.

 

30 A Review of the Reference Dose and Reference Concentration Process. U.S. Environmental 

Protection Agency. Risk Assessment Forum. EPA/630/P-02/002F. December 2002.

31 US EPA, 2005. Guidelines for Carcinogen Risk Assessment (2005). U.S. Environmental 

Protection Agency, Washington, DC, EPA/630/P-03/001F, 2005. 

http://cfpub.epa.gov/ncea/raf/recordisplay.cfm?deid=116283

32 US EPA, 2005. Supplemental guidance for assessing early-life exposure to carcinogens. 

EPA/630/R-03003F. http://www.epa.gov/ttn/atw/childrens_supplement_final.pdf.
282

Response: The commenter did not identify any specific deficiencies in the draft risk assessment, 

and we have updated and revised the final risk assessment as discussed in the preamble to the 

final rule.

3.3.3 Actions Taken Based on Risk Results

Comment: One commenter (4457) states that the EPA failed to justify relying on the 

presumption of 100-in-1 million as the benchmark for cancer risk acceptability, rather than 

ensuring a greater reduction of cancer risk. The commenter believes that the EPA must update 

and reduce its presumption that 100-in-1 million lifetime cancer risk is acceptable based on new 

circumstances and evolving values since the 1980s. The commenter states that the EPA has both 

full authority and a responsibility to update its approach and reduce the presumptive level of 

what cancer risk is acceptable under section 112(f)(2). The commenter states that in setting this 

presumption of acceptable risk, the EPA recognized that it could not easily compare the risk 

from hazardous air pollution with the risk from other activities studied because of numerous 

differences. Specifically, the EPA stated that the consideration of the acceptability of a specific 

level of risk depends on factors including, but not limited to: the certainty and severity of the 

risk, the reversibility of the health effect, the knowledge or familiarity of the risk, and whether 

the risk is voluntarily accepted or involuntarily imposed. The commenter states that significant 

new information has been discovered and major circumstances have changed that each should 

affect how the EPA applies these factors to a source category in a rulemaking today. The 

commenter states that during the more than two decades since the EPA established that 

presumption, dramatic scientific and societal advances have occurred that the EPA must take into 

account in its risk analysis, including: 

1993 National Research Council published Pesticides in the Diets of Infants and

Children, finding that children are not little adults, and have greater exposures and

susceptibility.

1994 President Clinton signed Executive Order 12898 on Environmental Justice.

1996 Food Quality Protection Act passed unanimously with a 10-Fold Children’s

Safety Factor.

Safe Drinking Water Act amendments required attention to susceptibility of

children.

EPA announced a new National Agenda to Protect Children’s Health.

1997 President Clinton signed the Children’s Environmental Health Executive Order

13045.

2000 EPA first published America’s Children and the Environment.

2008 National Academy of Science published Science and Decisions: Advancing Risk

Assessment.

2009 Administrator Jackson declared environmental justice and children’s health
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priorities.

2011 Administrator Jackson announced Plan EJ 2014 including rulemaking and science

goals.

Response: In 1990, Congress codified in section 112(f) of the CAA the approach we use for our 

residual risk analyses (i.e., the Benzene NESHAP, 54 FR 38044). Under that approach, the 100 

in a million cancer risk is not a bright line indicating that risk is “acceptable,” but rather we 

consider this health metric in conjunction with a variety of health factors to determine whether 

the risk is acceptable. Where we conclude that the risk is not acceptable, we cannot consider 

costs in requiring controls to bring risks down to an acceptable level. However, the analysis of 

whether risk is acceptable is not the endpoint. Once we determine that controls are sufficient to 

ensure risk is acceptable, we again review the health metrics in conjunction with considering the 

costs of controls to determine whether additional controls should be required to provide an ample 

margin of safety. Other than the chronology described above, the commenter does not provide 

support for its contention that “the risk that was acceptable in the world of the 1980s is no longer 

acceptable in today’s world.” Nor does the commenter explain how science has evolved in a way 

that would undermine the codified framework for determining acceptability.

3.3.3.1 Elimination of the Benzene Alternative Compliance Option for Glycol Dehydrators

Comment: One commenter (4174) is concerned that the part 63 subparts HH and HHH 

amendments are based on questionable residual risk analyses. For subpart HH, the commenter 

states that the EPA creates a "theoretical" facility with "maximum allowable" emissions under

the current rules to justify the changes. The commenter believes that the EPA overstepped its 

authority by creating a "fictional" oil and gas facility to impose controls on the entire industry. 

The commenter believes these provisions should be removed.

Another commenter (4208) agrees with the EPA’s determination that the current lifetime cancer 

risk the Agency found for the ONG production category is unacceptable. The commenter also 

supports the EPA’s proposal to reduce cancer risk for both source categories by removing the 

alternative compliance option for glycol dehydrators. However, the commenter recommends the 

EPA analyze whether it is necessary to further reduce cancer risk from both this category and the 

Natural Gas Transmission and Storage category to reach an acceptable level of risk and to 

provide the required “ample margin of safety to protect public health.” The commenter believes 

that because of the gaps in the EPA’s analysis and the use of emission estimates, the EPA should 

consider limiting HAP emissions more than proposed.

Response: As discussed in sections VII.A and B of the final rule preamble, we updated our risk 

assessment, and conclude that the MACT standards (including those promulgated in this 

rulemaking) for the two source categories provide an ample margin of safety, and are retaining 
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the existing alternative compliance option of 0.9 Mg/yr benzene for large glycol dehydrators. 

Accordingly, we are not revising subparts HH or HHH based on any risk analysis.

Comment: One commenter (4320) states that the EPA is not justified in its proposed elimination 

of the 0.9 Mg/yr benzene emission threshold in the oil and gas production MACT (subpart HH) 

affecting dehydrators. The commenter believes that the EPA has underestimated costs and 

overestimated the health risks associated with the proposed action. 

Response: As discussed in section VII.A of the preamble to the final rule, we are retaining the 

existing 0.9 Mg/yr benzene compliance option for subpart HH. New and existing large glycol 

dehydration units continue to have the option of complying with the emission reduction 

limitation or reducing actual annual benzene emissions to less than 0.9 Mg/yr. 

Comment: Three commenters (4158, 4229, 4241) request that the EPA clarify that glycol 

dehydration units that accepted a 1 ton (0.9 Mg) per year benzene federally enforceable limit 

under the current subpart HH and HHH rules be continued to be designated as "small glycol 

dehydration units." The commenters explain that, under the current subpart HHH rules, a glycol 

dehydration unit that accepted a federally enforceable 1 ton per year benzene limit is exempt 

from the standards and control requirements of subpart HHH. The commenters state that, under 

the current proposal, the EPA proposes to eliminate the 1 ton per year (tpy) benzene limit 

compliance option. According to the commenters, classification between a large and small glycol 

dehydration unit is basically dependent on a throughput rate and actual emissions being equal or 

greater than 1 ton per year of benzene. The commenters add that large dehydration systems 

would have 90 days from promulgation of the final rules to comply with the 95% control 

requirement or concentration limits. One commenter (4266) argues that, independent of any 

decisions related to small dehydrators, the EPA must restore the 0.9 Mg/yr benzene emissions for 

large dehydrators.

One commenter (4241) requests clarification that a dehydrator that previously had taken 

federally enforceable restriction to meet the 1 tpy “compliance option” qualifies as a “small 

glycol dehydration unit” subject to the new MACT requirements for small dehydrators, rather 

than a large dehydration unit, and that such a dehydrator is subject to the relevant three year 

compliance deadline. One commenter (4229) states that the proposed rule would require existing 

small dehydrators to comply with an emission standard based on a MACT floor determination 

that considered uncontrolled units, and would not mandate emission controls for these units. One 

commenter (4158) opines that, while the intent of the EPA may have been to only classify those 

glycol dehydrators that emit over 1 ton per year of benzene as large, it is not clear whether those 

emission sources that accepted a federally enforceable condition to limit its emissions less than 1 

tpy under current subpart HHH rules would be classified as a large glycol dehydration unit under 

the proposed rule. 
285

Two commenters (4249, 4265) state that existing glycol dehydrators that are already controlled 

to less than 1 ton per year benzene need to be clearly defined as a “small” dehydrator in subpart 

HHH. The commenter provides that it is their understanding that dehydrators that are currently 

exempt from subpart HHH (63.1274(d)(2)), would be classified as “small dehydrators” under the 

proposed revisions to the rule and would be required to comply with the standards and control 

equipment requirements for “small dehydrators.” The commenter requests that the final rule 

clearly indicate that a unit controlled to less than 1 tpy of benzene that is exempt under the 

original June 1999 rule is classified as a “small dehydrator” under the final rule.

Two commenters (4192, 4246) requests that, for glycol dehydrators at major sources, the EPA 

remove the 3 million standard cubic feet per day throughput proposed exemption and retain the 

existing less than 1 tpy benzene exemption, and express MACT floor standards in English units.

Response: As we discuss in the final rule preamble, we are retaining the 1 tpy (0.9 Mg/yr) 

compliance option for large glycol dehydration units under subparts HH and HHH. However, the 

compliance option is unrelated to the subcategorization of these source categories to include 

large and small glycol dehydration units. A small glycol dehydration unit is defined as a unit 

with an actual annual average natural gas flowrate less than 3 MMscf/d (85,000 scmd)(subpart 

HH) or less than 10 MMscf/d (283,000 scmd) (subpart HHH) or actual annual average benzene 

emissions less than 1 tpy. Therefore, glycol dehydration units that have accepted federally 

enforceable conditions to limit emissions to less than 1 tpy and were exempted from control 

under the 1999 MACT standards, are classified as small glycol dehydration units, and are 

required to meet the MACT standards issued in this rulemaking for small glycol dehydration 

units under §§63.765(b)(1)(iii) and 63.1275(b)(1)(iii).

3.3.3.2 Compliance Date for Facilities Currently Relying on the Benzene Alternative 

Compliance Option

Comment: Three commenters (4178, 4185, 4229) request that the EPA extend the proposed 90-

day compliance deadline for large glycol dehydration units that had been using the 1 tpy 

compliance option. One commenter (4178) states that if the proposal goes final, “large” glycol 

dehydration units that became compliant with subpart HH by reducing benzene emissions to less 

than 1 tpy before August 23, 2011 must achieve compliance no later than 90 days after 

publication of the final rule. The commenter believes that this requirement appears to contain an 

internal contradiction in the definition of “large” dehydration unit in that no dehydration unit that 

has less than 1 tpy of benzene emissions is a “large” dehydration unit. Further, according to the 

commenter, in order to comply with subpart HH, many dehydration units will be required to 

install monitoring and possibly additional emission control equipment. The commenter believes 

that it may be difficult for some facilities to obtain and install such equipment within the 90-day 
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time period. The commenter recommends that, in lieu of a 90-day time period, the EPA allow 

180 days in order to ease the burden on facilities and reduce the potential for unnecessary 

enforcement actions by the state. 

One commenter (4229) argues that, if the 1 tpy benzene emission compliance option is deleted, 

90 days is not enough time for units currently complying with that standard to meet new 

requirements. The commenter explains that, in addition to deleting the 1 tpy compliance option 

for large dehydrators, the proposed rule requires that operators using this compliance option meet 

one of the other two compliance options no later than 90 days after the final rule effective date. 

The commenter provides several factors for why they believe more than 90 days to comply is 

warranted.

One commenter (4185) urges the EPA to significantly extend the proposed deadline for large 

glycol dehydration units that presently rely on the “alternative compliance” pathway under 

subparts HH and HHH to comply with MACT standards for benzene emissions. The commenter 

recommends that the EPA provide at least 12 months from the promulgation of the rule, and 

provides suggested revisions to §§63.760(f)(10) and 63.1270(d)(5) changing the compliance date 

from 90 days to 12 months. 

Response: The final rule retains the 1 tpy benzene emissions compliance option in both subparts 

HH and HHH; therefore, it will not be necessary to modify the regulation to extend the 

compliance date for large glycol dehydrators.

3.3.4 Other Comments

Comment: One commenter (4357) states that emissions of methane, monitored over time using 

mobile devices at the fence-lines are good surrogates for other toxic gases that may be emitted. 

The commenter states that specific correlation of HAPS to methane can easily be done for each 

site by collecting gas samples using a summa canister.

Response: We thank the commenter for this information.

Comment: One commenter (4273) states that the EPA should delist all source categories that 

meet section 112(c)(9) criteria and use title V to enforce emission limits and standards as part of 

the delisting. The commenter states that, to the extent the EPA’s risk assessment finds the source 

category or subcategory has low risk, the EPA should delist the source category or subcategory. 

The commenter states that if a source category that poses a low risk to the public is not delisted, 

the EPA may continue to revise the standard based on new technologies, and sources will be 

subject to an endless technology ratchet, uncertainty, and increased costs as new technologies are 

developed. According to the commenter, delisting is appropriate even after MACT standards 
287

have been in place, as section 112(c)(9) states the EPA has the authority to delist categories 

“whenever.” The commenter states that those elements of the MACT standard that might be 

needed to sustain the low risk determination could be established as part of the source category 

delisting decision. The commenter believes these requirements could be enforceable and 

maintained in existing title V permits to ensure the public health protection contemplated by 

section 112(c)(9).

Response: The commenter asks that the EPA delist the source categories at issue here so it can 

avoid additional regulation if the EPA revises the standards in the future if technologies change. 

The commenter has provided no evidence that it can meet the test for delisting set forth in CAA 

section 112(c)(9)(B). That section provides that “[t]he Administrator may delete any source 

category” from the section 112(c) source category list if the Agency determines that: (i) for HAP 

that may cause cancer in humans, “no source in the category (or group of sources in the case of 

area sources) emits such hazardous air pollutants in quantities which may cause a lifetime risk of 

cancer greater than one in one million to the individual in the population who is most exposed to 

emissions of such pollutants from the source (or group of sources in the case of area sources)”; 

and (ii) for HAP that may result in human health effects other than cancer or adverse 

environmental effects, "a determination that emissions from no source in the category or 

subcategory concerned (or group of sources in the case of area sources) exceed a level which is 

adequate to protect public health with an ample margin of safety and no adverse environmental 

effect will result from emissions from any source." 

The commenter has failed to demonstrate that the requirements for delisting in section 

112(c)(9)(i) and (ii) have been met. Our risk analysis identifies sources that exceed a risk of 1-in1 million and as such the source categories at issue, both of which emit carcinogens, cannot be 

delisted. 

Comment: One commenter (4189) states that the proposed rule under both section 112(f)(2) and 

(d)(6) contains gaps in the pollutants (e.g., 1, 3 butadiene, mercury and chemicals used in the 

hydraulic fracturing process), human exposures, and health risks analyzed. The commenter 

believes the EPA needs to assess the health risks from all dangerous pollutants emitted by oil and 

gas facilities, as shown by the scientific literature, known to be part of the chemical composition 

of oil and gas, or detected in air monitoring conducted by community groups and others near oil 

and gas facilities. 

Response: The commenter did not identify or provide any information regarding any specific 

HAP from the oil and gas source categories that we failed to consider in our risk review. In the 

preamble to the proposed rule, we discuss our approach for selecting the emissions data used in 

the risk assessment (i.e., we use emissions data from a variety of sources and review these data to 

ensure the emissions sources are in the Oil and Natural Gas Production or Natural Gas 
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Transmission and Storage MACT source categories). While our facility-wide emissions files do 

contain emissions for 1,3 butadiene and mercury, we determined in our review that those 

emissions are from sources outside these two MACT categories. The commenter did not provide 

any data to contradict this determination.

3.4 Technology Review

3.4.1 General Comments on the Technology Review Methodology

Comment: One commenter (4457) states that CAA section 112(d)(6) requires the EPA to revise 

its standards in accordance with section 112(d)(2)-(3), (6) and the EPA has failed to update the 

existing MACT standards to meet the CAA section 112(d)(6) requirement by, at minimum, 

matching the emissions levels that sources are achieving, and considering setting an appropriate 

beyond-the-floor standard. According to the commenter, the EPA’s failure to update the existing 

MACT standards is especially problematic because the original MACT calculation was flawed, 

because there are “developments” in technology, practices, and processes, and sources have 

achieved lower levels of emissions “in practice” than the current MACT standards. The 

commenter adds that the EPA fails to satisfy CAA section 112(d)(2)-(3) as there is evidence, 

including evidence in the record from the 1999 MACT determination, that, due to improvements 

in technology, many sources have “achieved” a level of “actual” HAP emissions that is below 

the existing MACT standard and the standards proposed by the EPA. The commenter asserts that 

the EPA’s analysis indicates the amount of emissions that are “allowable” under the existing

MACT standard far exceed what the EPA calls “actual” emissions and may be “up to 50 times 

greater than actual emission levels” because many oil and gas facilities have achieved greater 

emission reductions than the EPA’s prior standard anticipated. The commenter argues that the 

CAA requires any section 112(d) standard to meet section 112(d)(2) requirements, including 

those standards set under section 112(d)(6). The commenter states that if as a result of 

“developments in practices, processes and control technologies” the EPA’s old MACT standards 

no longer comport with section 112(d)(2)-(3), the agency must revise them “as necessary” to 

bring them into compliance and that section 112(d)(6) requires the EPA to ensure its standards 

continue to satisfy section 112(d)(2)-(3) as practices, processes and control technologies develop.

One commenter (4457) states that section 112(d)(6) serves as an ongoing ratchet to continually 

require the EPA to update standards to keep pace with new technology in order to decrease

emissions. The commenter believes that the CAA is intended to be a technology-forcing statute 

that drives industry to continue finding new ways to reduce air pollution. In particular, according 

to the commenter, the MACT regulatory regime is structured to push polluting industries to 

control emissions to the greatest degree possible. The commenter states that the review and 

revision provision is a key method of implementing the Act’s technology-forcing objective. The 

commenter adds that where there are developments in technology, practices, and processes 
289

demonstrating that greater emissions reductions are achievable and sources have achieved 

significantly lower level of emissions in practice than the current MACT standards, the EPA is 

required to revise its standards in accordance with CAA section 112(d)(2)-(3), (6).

The commenter states that a revision to the existing standard is especially necessary under 

section 112(d)(6) if that prior standard was not established in a manner that complies with the 

requirements of the Clean Air Act. The commenter reports that, since the adoption of the Oil and 

Natural Gas Production MACT, the D.C. Circuit has specifically rejected a number of practices 

employed by the EPA to set MACT limits; including but not limited to: (1) requiring that MACT 

limits be achievable by all sources; (2) basing the standard on an evaluation of control 

technology performance rather than plant performance; (3) adopting “no control” MACT limits 

where active pollution controls were not in use in a subcategory; (4) employing regulatory limits 

where actual performance data are available; and (5) rejecting MACT floor technologies and 

limits based on cost or feasibility. The commenter claims the EPA has recognized its obligation 

to reconsider earlier-set standards where its prior approach resulted in “no control” MACT 

floors. Similarly, according to the commenter, because the EPA employed improper analysis in 

setting the initial MACT standards for oil and gas source categories, as discussed in the Buckheit 

Report, this demonstrates a particular need to update the standards in this rulemaking. 

Moreover, the commenter asserts that the D.C. Circuit has affirmed the EPA’s approach in other 

rulemakings to “reset[] the MACT floors in order to correct its own errors.” Med. Waste Inst. & 

Energy Recovery Council v. E.P.A., 645 F.3d 420, 424 (D.C. Cir. 2011) (HMIWI). The 

commenter asserts that, in HMIWI, the court disagreed with Petitioner’s arguments that (1) the 

“CAA only authorizes a one-time establishment of floors based on the level of emission control 

‘achieved in practice by the best controlled similar unit’ for new units, and at ‘the average 

emissions limitation achieved by the best performing 12 percent of units in the category’ for 

existing units;” (2) that if the EPA sets standards more stringent than those set during the original 

MACT, it must “consider cost and other factors listed in the statute—either as part of an initial 

standard-setting process or as part of the five-year review;” and (3) that in resetting the MACT 

floor, EPA cannot rely on data collected after the original MACT was set. Id. at 424-25. Instead, 

the commenter reports that the court concluded that the EPA was not required to “proceed from 

the data set it had employed in the initial setting of the floors” because its approach was 

“unsupportable,” e.g., it “did not reliably approximate the emissions levels achieved in practice 

by best performing units.” Id. at 425-26. The commenter states that, as explained in HMIWI, 

emissions levels set in a new rule, in which the EPA resets the floor, are “properly characterized 

not as ‘beyond-the-floor,’ or as a revision conducted as part of the five-year review, but as the 

floor setting that is the initial step in establishing emissions standards. See 42 U.S.C. § 

7429(a)(2). According to the commenter, the former requires consideration of the costs of 

compliance, but the latter does not.” HMIWI, 645 F.3d at 426. The commenter asserts that the 

EPA’s original MACT calculation for both oil and gas subcategories is unsupported and 
290

sufficient information exists demonstrating that facilities are achieving greater reductions in 

HAPs than in the existing and proposed rule.

The commenter opines that the situation here is distinguishable from the facts in NRDC v. EPA, 

529 F.3d 1077, 1084 (D.C. Cir. 2008) (HON), in which the court explained that recalculating the 

floors was not necessary because “petitioners have not identified any post-1994 technological 

innovations that the EPA has overlooked.” NRDC, 529 F.3d at 1084. According to the 

commenter, the HON Court expressly declined to decide whether the EPA was required to 

recalculate floors where, as here, there have been developments in practices, processes, and 

control technologies. The commenter states that, as noted below and discussed further in the 

attached Reports by Sahu and Buckheit, for these source categories, there are such 

“developments.” Therefore, the commenter opines that the EPA cannot rely on the HON case to 

evade its duty to satisfy section 112(d)(6).

The commenter states that, consistent with the HON decision, assuming that its section 112(d)(6) 

holding is relevant here, section 112(d)(6) requires the EPA to recalculate the MACT floor when 

there have been advances in technology, practices, and processes, and when there is information 

showing that greater emission reductions have been “actually achieved.” 

One commenter (4457) states the EPA’s failure to update the existing MACT standards is 

especially problematic because the original MACT calculation was flawed, because there are 

“developments” in technology, practices, and processes, and sources have achieved lower levels 

of emissions “in practice” than the current MACT standards. The commenter adds that the 8-year 

MACT review also fails to satisfy CAA section 112(d)(2)-(3) as there is evidence, including 

evidence in the record from the 1999 MACT determination, that, due to improvements in 

technology, many sources have “achieved” a level of “actual” HAP emissions that is not only 

below the existing MACT standard, but also below the standards proposed by EPA in the 

proposed rule. The commenter asserts that, consistent with the HON decision, assuming that its 

section 112(d)(6) holding were relevant here, section 112(d)(6) requires the EPA to recalculate 

the MACT floor when there have been advances in technology, practices, and processes, and 

when there is information showing that greater emission reductions have been “actually 

achieved.” 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 believes the EPA overlooks the potential lower emissions that sources are achieving 

by failing to use more recent data.

The commenter (4457) states that the EPA must update the MACT floor and consider setting a 

beyond-the-floor-standard for large glycol dehydrators. The commenter also states that the EPA 
291

must update the MACT floor and consider setting a beyond-the-floor standard for storage vessels 

with PFE, and set an adequate MACT standard for leak detection.

Response: Section 112(d)(6) requires the EPA to “review, and revise as necessary (taking into 

account developments in practices, processes, and control technologies), emission standards 

promulgated under this section no less often than every 8 years.” 

As EPA has explained on several prior occasions, section 112(d)(6) does not require MACT

standards to be recalculated. See 70 FR at 20008 (April 15, 2005); 529 F. 3d at 1084. The EPA 

is not reopening that issue here, or otherwise reconsidering its interpretation of section 112(d)(6). 

Moreover, the argument that EPA must recalculate floors in conducting a 112(d)(6) review was 

rejected by the D.C. Circuit in the HON opinion. See 529 F. 3d at 1084 (“It is argued that EPA 

was obliged to completely recalculate the maximum achievable control technology-in other 

words, to start from scratch. We do not think the words ‘review, and revise as necessary’ can be 

construed reasonably as imposing any such obligation.”). We thus disagree with the commenter’s 

assertion that the HON Court’s ruling provides only that CAA section 112(d)(6) does not require 

re-calculation of MACT floors in instances where there have been no developments in practices, 

processes, or control technologies. In fact, the Court was quite clear on this point, and declined to 

rule only on whether it was appropriate for the EPA to consider costs and risks in conducting 

CAA section 112(d)(6) reviews, as the issue was rendered moot by the litigants’ failure to 

preserve it. Accordingly, we did not, as the commenter requests, re-calculate the MACT 

standards that we developed in the 1999 rule as part of our section 112(d)(6) review.

Moreover, to the extent the commenter is arguing that section 112(d)(6) mandates that the EPA 

correct any deficiency in an underlying MACT standard when it conducts the “technology 

review” under that section, we disagree. We believe that section 112 does not expressly address 

this issue, and the EPA has discretion in determining how to address a purported flaw in a 

promulgated standard. Section 112(d)(6) provides that the Agency must review and revise "as 

necessary.” The “as necessary” language must be read in the context of the provision, which 

focuses on the review of developments that have occurred since the time of the original 

promulgation of the MACT standard and thus should not be read as a mandate to correct flaws 

that existed at the time of the original promulgation. 

In several recent rulemakings, we have chosen to fix underlying defects in existing MACT 

standards under sections 112(d)(2) and (3), the provisions that directly govern the initial 

promulgation of MACT standards (see National Emission Standards for Hazardous Air 

Pollutants From Petroleum Refineries, October 28, 2009, 74 FR 55670; and National Emission 

Standards for Hazardous Air Pollutants: Group I Polymers and Resins; Marine Tank Vessel 

Loading Operations; Pharmaceuticals Production; and the Printing and Publishing Industry, 

April 21, 2011, 76 FR 22566). We believe that our approach is reasonable because using those 

provisions ensures that the process and considerations are those associated with initially 

establishing a MACT standard, and it is reasonable to make corrections following the process 
292

that would have been followed if we had not made an error at the time of the original 

promulgation. In this rule, we are setting MACT standards under section 112(d)(2) and (d)(3) for 

the subcategory of small glycol dehydration units. These units were left unregulated in the 1999 

NESHAP. We are not, however, finalizing MACT standards for the subcategory of storage 

vessels without the PFE, which also were unregulated in the 1999 rule, because after evaluating 

the available data and comments received, we believe that we need additional data in order to set 

an emission standard for these vessels. Once we obtain additional data, we intend to set standards 

for the subcategory of storage vessels without the PFE pursuant to section 112(d)(2) and (d)(3).

Further, whether or not section 112 (d)(6) is “technology forcing”, the EPA retains very 

significant discretion in balancing relevant factors in determining whether it is “necessary” to 

revise the existing technology-based MACT standards. Sierra Club v. EPA, 325 F. 3d 374, 378 

(D.C. Cir. 2003). In reviewing section 112 (d) (2) standards, and determining whether to revise 

them is “necessary” under section 112 (d)(6), the EPA may take into consideration cost and 

feasibility when evaluating developments in practices, processes, and control technologies. 

Indeed, it is reasonable that any such “review” consider the same factors which the EPA is 

required to consider under section 112 (d)(2) – cost, non-air environmental impacts, potential 

impacts on energy usage among them. 

As discussed in the preamble to the proposed rule as well as in this response to comment 

document, we found no significant developments in practices, processes and control technologies 

for reducing emissions from large glycol dehydrators and storage vessels with the potential for 

flash emissions for Subpart HH sources. With regard to Subpart HHH, we found no significant 

developments in practices, processes and control technologies for reducing emissions from large 

glycol dehydrators. Accordingly, we are not revising these standards under section 112(d)(6). 

For Subpart HH, the EPA conducted a technology review evaluating various options for 

controlling HAP emissions from equipment leaks. As described in our analysis, we evaluated 

advancements in controlling this emission source since the original standards were promulgated, 

including the emission reduction potential and associated cost effectiveness of these 

advancements. As a result of our review, we revised the leak definition for valves to 500 ppm at 

natural gas processing plants, thus requiring the application of the leak detection and repair 

requirement at this lower detection level.33 

Comment: One commenter (4457) states that the EPA’s technology analysis suffers from a 

number of flaws, not the least of which are its failure to cast a wide enough net in evaluating 

control options – including practices, processes, and technologies that have achieved greater 

 

33 Memorandum from Brown, H., EC/R Incorporated to Nizich, G. and Moore, B., EPA/OAQPS/SPPD/FIG. 

Technology Review for the Final Amendments to Standards for the Oil and Natural Gas Production and Natural Gas 

Transmission and Storage Source Categories. April 17, 2012
293

emission reductions – and its dismissal of options with little or no analysis or grounds. The 

commenter states that the EPA should have considered the following: the use of desiccant 

dehydrators for at least some portion of the source categories; the use of control options 

demonstrated by the Natural Gas STAR program; technologies and practices in BACT 

determinations, including greater control efficiency levels; technologies and practices used in the 

EPA’s own refinery enforcement actions including more stringent leak detection and repair; 

researching vendor literature and discussed options with vendors regarding newer technologies 

and improvements to old technologies that make them more cost-effective and more efficient; 

evaluating the requirements and programs to address such emissions in various states such as 

California, Colorado, and Wyoming, including stronger leak detection and repair requirements 

and improved control technology efficiency; and considered the additional and similar options 

outlined in the Paranhos summary (EPA-HQ-OAR-0505-0016). The commenter asserts that the 

EPA’s failure to consider these options is arbitrary and capricious. 

One commenter (4457) also states that the EPA provides no summary or analysis of Natural Gas 

Star developments that should inform the rule proposal. According to the commenter, the EPA’s 

docket memoranda on the technology reviews state that “[n]ew practices, processes, and control 

technologies were reviewed from the Natural Gas STAR program...” but no further analysis 

appears in the docket. The commenter reports that the EPA’s docket memo contains a summary 

of the RBLC data but no summary of Natural Gas Star program information and no indication 

when the RBLC was searched. The commenter states that Attachment A to their report includes a 

Table providing a summary of Natural Gas Star program information found on EPA’s website. 

The commenter asserts that the EPA’s conclusory assertion that the Natural Gas Star program 

information was “reviewed,” is not supported by the record. 

The commenter (4457) further states that the EPA recognizes that its prior rulemaking could not 

have included examples of emissions reduction approaches that have been demonstrated via the 

Natural Gas STAR program, as the EPA noted that “for glycol dehydrators, many of the 

practices, processes, or control technologies listed by the Natural Gas STAR program were not 

identified and evaluated during the original MACT development.” Instead of evaluating these 

approaches, however, the commenter contends that the EPA improperly seeks to minimize their 

relevance. The commenter states that the EPA’s emphasis on the potential limitation of control 

device applicability for dehydrators is irrelevant and contrary to the goals and requirements of 

section 112. According to the commenter, the EPA cannot reject a technology development 

because it fails to “work for all glycol dehydrators...” The commenter states that the purpose of 

section 112(d) is to drive technology forward, and advance the standards by following 

developments in technology. For example, the commenter believes that the use of optimized 

glycol circulation rates, the use of flash separators, and even the replacement of glycol 

dehydrators with desiccant dehydrators will not be carefully evaluated by sources as control 

options unless the current rule properly evaluates their application. According to the commenter, 
294

it is likely that the use of these technologies would result in far lower emissions than what the 

EPA has proposed, and that the performance of these technologies will help set the MACT 

standards for new sources. Further, the commenter states that it is unclear how the EPA 

considered the flash tank separator option in the MACT technology analysis. 

Response: The technologies cited by the commenter were considered under our section 

112(d)(6) review (76 FR 52784; EPA-HQ-OAR-2010-0505-0062 ).34 For glycol dehydrators, 

most of the emission control practices identified in the Natural Gas STAR program are 

considered to be new and unproven practices that may not be applicable to all production or 

transmission facilities. Only one of the technologies identified in the Natural Gas STAR 

literature, a glycol dehydrator with a desiccant dehydrator, may result in zero HAP 

emissions. However, this technology cannot be used for natural gas operations that operate at 

high temperature, high volume, or low pressure. Therefore, this technology was not considered 

to be a development under section 112(d)(6) for glycol dehydrators for the oil and natural gas 

production or natural gas transmission and storage source categories. The commenter provided 

no data to refute these findings. We also point out that our analysis of the RBLC database (based 

on a July 2011 extraction of the RBLC database) did not identify any practices, processes, or 

control technologies applicable to the emission sources in these categories that were not 

identified and evaluated during the original MACT development, therefore we did not consider 

them under our section 112(d)(6) review.

Comment: One commenter (4457) states that the EPA failed to conduct a comprehensive 

evaluation of advances in control technologies for storage vessels. The commenter contends that 

the EPA must examine advances in vapor recovery unit technology and reconsideration of 

floating roof technology for tanks containing liquids that do not have the potential for flash 

emissions. As described in the Buckheit Report provided by the commenter, the commenter 

states 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, the commenter states that 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 (Michigan, Consumer’s Energy). 

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 adds 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 

 

34 Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce, U.S. EPA, titled Technology Review for the 

Final Amendments to Standards for the Oil and Natural Gas Production and Natural Gas Transmission and Storage 

Source Categories. Dated April 17, 2012.
295

record. The commenter states that the EPA must provide a basis for its decisions and 

conclusions.

Response: In response to comments, we re-evaluated the cost effectiveness of increasing the 

level of control from 95 percent to 98 percent. We found that the controls required to achieve 98 

percent were not cost effective.35 In addition, we also received information from other 

commenters (see section 3.5.1) on the performance of these combustion control devices that 

brings into question their ability to meet 98 percent control and therefore, we are not increasing 

the 95 percent control requirements for storage vessels.

3.4.2 Actions Taken Based on the Technology Review

Comment: One commenter (4266) requests that the EPA clarify and modify the video recording 

requirements required in the Alternative Work Practice (AWP) to Detect Leaks from Equipment 

(§60.18(g)) by amending rule language to clarify that video records will identify regulated 

equipment via a defined area grouping, not by a recording of each equipment component. The 

commenter recommends that the EPA also evaluate how the video data will be used and whether 

a complete video recording is really needed. The commenter believes that OGI has the potential 

to be useful for difficult or unsafe to monitor components. However, in order to make it work in 

the field, the commenter states that an extended or conditional repair schedule is needed for 

difficult to access and unsafe to access components, with the final repair falling under the delayof-repair provisions. 

Response: The proposed rule did not include any revisions to the Alternative Work Practice 

requirements in §60.18(g), so the commenter’s requests are not within the scope of this 

rulemaking. The EPA notes for informational purposes that this issue was identified by the 

American Petroleum Institute in their February 20, 2009, request for administrative 

reconsideration of the AWP provisions, and the EPA is currently considering this request 

separately from this rulemaking. 

Comment: One commenter (4159) states that Congress intended that EPA use risk criteria as the 

only “sensible” approach in interpreting when additional controls are necessary under section 

112(d)(6). Therefore, the commenter contends that the EPA erred in its section 112(d)(6) 

determination for the Oil and Gas Production source category by basing its decision primarily on 

a cost-per-ton comparison of control options. The commenter believes that once EPA conducts 

its residual risk review and determines that emissions from a source category present an 

acceptable risk with an ample margin of safety, EPA has discretion to find further revisions not 

 

35 Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce, U.S. EPA, titled Technology Review for the 

Final Amendments to Standards for the Oil and Natural Gas Production and Natural Gas Transmission and Storage 

Source Categories. Dated April 17, 2012.
296

“necessary” under section 112(d)(6). The commenter contends EPA should evaluate further 

controls under section 112(d)(6) only in terms of their incremental cost and their incremental 

potential to reduce risk. 

Another commenter (4273) agrees with this position, stating that Congress intended that the EPA 

use risk criteria in interpreting when additional controls are necessary under section 112(d)(6), 

which requires the Administrator to review, and revise emission standards “as necessary.” The 

commenter states that in the ONG production source category, the EPA incorrectly bases its 

proposed decision on cost estimates without evaluating the incremental health risk benefit of the 

new controls against the incremental costs of such controls. The commenter states that 

comparing cost-per-ton estimates of different controls does not provide sufficient information 

regarding whether the controls would have any discernible benefit on public health, even with 

the EPA’s multiple conservative risk assumptions. The commenter states that implementing the 

technology review decisions absent an analysis of risk is likely to result in endless changes in 

control technology, pointless regulatory uncertainty, and increases in capital and operating costs 

with no measurable public health benefit. The commenter believes that the EPA should evaluate 

further controls under section 112(d)(6) only in terms of their incremental cost and incremental 

potential to reduce risk.

Response: Pursuant to section 112(d)(6), the EPA proposed that there were no developments in 

practices, processes or control technologies for large dehydrators and storage vessels with the 

PFE for Subpart HH and no developments in practices, processes or control technologies for 

large dehydrators for Subpart HHH. The EPA is finalizing those conclusions today. The 

commenter argues that were we to find a development in practices, processes or control 

technologies we can only require such development if the development causes a material 

reduction in risk. In the commenter’s view, considerations of cost alone are not sufficient to 

require a control under section 112(d)(6). We disagree. CAA section 112(d)(6) does not 

mandate consideration of risk in the determination of whether revised standards are 

“necessary"36. The “core requirement” of CAA section 112(d)(6) is the existence or nonexistence of developments in practices, processes, and control technologies, not a public health 

or risk-based determination . NRDC v. EPA, 529 F. 3d 1077, 1084 (D.C. Cir. 2008). CAA 

section 112(d)(6) is also a continuation of the technology-based section 112 (d) standard-setting 

process, again indicating that the determination is not primarily based on risk-based 

considerations. Consequently the EPA does not believe that a revised CAA section 112(d)(6) 

 

36 Because the meaning of “necessary” is ambiguous and “varies with context . . .[,] dueling over dictionary

definitions is pointless, for it fails to produce any plain meaning of the disputed word.” Cellular Telecomms. &

Internet Ass’n v. FCC, 330 F.3d 502, 509-10 (D.C. Cir. 2003). The Supreme Court has directed that “a statutory

reference to ‘necessary’ must be construed in a fashion that is consistent with the ordinary and fair meaning of the

word,” and EPA’s interpretation of “necessary” is entitled to Chevron deference if it is “rationally related to the

goals of the Act.” AT & T Corp. v. Iowa Utils. Bd., 525 U.S. 366, 388 (1999).
297

standard is “necessary” only if justified based on public health/risk considerations. We did 

identify developments in practices, processes or control technologies in relation to the equipment 

leak requirements at natural gas processing plants in 40 CFR part 63, subpart HH, and as such, 

are lowering the leak definition for valves at natural gas processing plants to an instrument 

reading of at least 500 ppm. We found this revision to be reasonable from a cost perspective and 

are thus requiring this revision under section 112(d)(6).37 

3.4.2.1 Revise Leak Definition for Valves in Subpart HH

Comment: One commenter (4457) states that, in establishing the subpart HH standards for 

equipment leaks, the EPA identified the worst expected performance of those plants that 

employed a broadly defined class of equipment leak prevention, detection and repair processes, 

rather than the performance achieved by the best performing facilities. The commenter contends 

that several aspects of the MACT floor analysis for existing subpart HH MACT standards were 

inadequate. 

According to the commenter, the EPA failed to set the MACT floor at a level as stringent as that 

set by the subpart KKK program. The commenter states that the subpart KKK leak detection 

program applies to all components in VOC service, thus exempting components servicing 

streams with less than 10 percent VOC content, while the subpart HH rule adopted by the EPA 

provides an exemption for all components servicing streams with less than 10 percent volatile 

HAP content. This exemption, according to the commenter, just as the VOC exemption in the 

NSPS rules, is provided without any evaluation of the impact on emissions, level of control, or 

rule effectiveness. 

The commenter (4457) also states that the EPA carried over to part 61, subpart V (and thereafter 

to part 63, subpart HH) a number of exemptions and deferred monitoring and repair options that 

are artifacts of the part 60 NSPS program that is permitted to consider cost, while the MACT 

floors may not. 

Response: To the extent that the commenters are addressing the leak detection requirements in 

the original subpart HH, such comments are untimely. If the commenters are requesting that the 

EPA recalculate the MACT standards established in 1999, we point out that we are under no 

obligation to revisit previous MACT determinations under section 112(d)(6). See response to 

section 3.4.1. The proposed rule did not re-open the original MACT standards for equipment 

leaks. Instead, for equipment leaks, we evaluated whether there had been any developments in 

practices, processes and control technologies under our 112(d)(6) review and as the result of our 

 

37 Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce, U.S. EPA, titled Technology Review for the 

Final Amendments to Standards for the Oil and Natural Gas Production and Natural Gas Transmission and Storage 

Source Categories. Dated April 17, 2012
298

review, we are requiring a lower leak definition for valves to an instrument reading of at least 

500 ppm.

Comment: One commenter (4457) states that the EPA proposes to lower the leak definition for 

valves to an instrument reading of at least 500 ppm, which is an improvement, but could be 

stronger and the commenter points to the Buckheit Report in their comment submittal for further 

rationale. The commenter (4457) states that, at minimum, the new source MACT LDAR 

program should not be less stringent than the Bay Area Air Quality Management District 

(BAAQMD) rules that currently cover 5 refineries with over 200,000 components. The 

commenter states that BAAQMD’s Regulation 8, Organic Compounds, Equipment Leaks does 

not provide an exemption for streams with less than 10 percent VOC content. The commenter 

contends that the EPA has not attempted to quantify the impact of its exemption on source wide 

emission rates. The commenter argues that Regulation 8 applies to leaks of TOCs, including 

methane, whereas the proposed Federal rule excludes methane. According to the commenter’s 

analysis, if one assumes that the gas stream at a natural gas processing plant is 95 percent 

methane, then a detection limit of 500 ppm, excluding methane, is equivalent to a detection limit 

of 10,000 ppm, including methane. The commenter then asserts that the BAAQMD LDAR rules 

effectively detect HAP at 5 ppm. Thus, according to the commenter, in terms of detecting leaks 

of VHAP, the proposed Federal detection limit is approximately 100 times higher than the 

existing BAAQMD detection limit because the Federal detection limit does not require detection 

of the entire emission stream in order to find potential HAP leaks.

The commenter adds that the BAAQMD limit on the number of components awaiting repairs is 

0.3 percent for valves, 0.025 percent for valves with major leaks (leaks greater than 10,000 ppm, 

including methane) and 1.0 percent for pumps and compressors. The commenter states that it 

also requires mass emission testing for non-repairable components with high leak rates and 

places an emission limit of 15 lbs/day on non-repairable components. The commenter adds that 

by comparison, the South Coast Air Quality Management District limit is 0.5 percent for valves 

and 1.0 percent for pumps. 

One commenter (4189) states that the EPA must require greater emission reductions based on 

recent improvements in practices, processes, and technologies. The commenter contends that 

California has stronger leak detection and repair standards than what the EPA has proposed. 

While local standards in California (specifically in the Bay Area, South Coast, and Ventura air 

districts) require facilities to fix leaks, the commenter states that the EPA’s standard allows 2% 

of equipment to leak forever. According to the commenter, the EPA must remove this loophole. 

Response: The EPA appreciates the comments on the proposed equipment leak requirements. 

However the commenter did not provide sufficient information for the EPA to determine that the 

Ventura County APCD LDAR program as described in the Buckheit Report would result in 
299

greater HAP reductions. We conducted a technology review to assess lowering the leak 

definition for valves to the 100-ppm level used by BAAQMD.38 We evaluated the incremental 

cost effectiveness between the proposed subpart VVa-level of control (a leak definition of 500 

ppm) and a leak definition of 100 ppm. According to our analysis, the incremental cost 

effectiveness was $42,800/ton of HAP. We do not consider this to be cost effective. In our 

technology review, we also evaluated the BAAQMD program for number of components 

awaiting repair.39 We determined that the HAP emission reduction associated with the 

BAAQMD regulation is 0.539 tpy HAP and the cost effectiveness ranged from $43,600 to 

$219,000 per ton HAP. We do not consider this to be cost effective. As a result, the final rule 

requires the subpart VVa-level of control for valves, with a leak definition of 500 ppm. 

Comment: One commenter (4266) states that it is not feasible to expect existing facilities to be 

able to be in compliance instantaneously upon promulgation. The commenter contends that upon 

promulgation of the final rule, it is expected that at an existing facility, a great number of valves 

which were previously not a leaker would suddenly become a leaker. The commenter states that 

an adequate supply of maintenance personnel and valve parts necessary to repair that many 

leakers within the time frame allowed in the rule is very questionable. In certain cases, according 

to the commenter, the needed personnel and/or parts would simply not be available. The 

commenter prefers to keep the 10,000 ppm leak definition. However, if the leak definition is to 

drop down to 500 ppm, then the commenter believes that additional time to comply should be 

allowed, at least a year for existing facilities, and 180 days for new facilities to implement work 

practice requirements.

One commenter (4219) notes that the proposed subpart HH requirements would apply both to 

new and to existing facilities. The commenter states that existing facilities, however, should not 

be expected to immediately be in compliance with the proposed new and much more stringent 

requirements. For example, the commenter asserts that the proposal in subpart HH to lower the 

leak threshold for valves to 500 ppm would cause sites to devote a significant amount of 

manpower and equipment to repairing the valves that had become regulated “leakers” overnight. 

In many cases, the commenter claims the needed resources would not be available despite the 

best efforts of the owner or operator. The commenter adds that compliance with the proposed 

new requirements would involve a substantial amount of effort and time for procuring new 

equipment, as well as engineering, design, and installation. In no case should immediate 

compliance be required.

 

38 Memorandum from Brown, H., to Nizich, G. and Moore, B., EPA/OAQPS/SPPD/FIG. Technology Review for the 

Final Amendments to Standards for the Oil and Natural Gas Production and Natural Gas Transmission and Storage 

Source Categories. April 17, 2012.

39 Memorandum from Brown, H., to Nizich, G. and Moore, B., EPA/OAQPS/SPPD/FIG. Technology Review for the 

Final Amendments to Standards for the Oil and Natural Gas Production and Natural Gas Transmission and Storage 

Source Categories. April 17, 2012.
300

Response: We agree that the proposed subpart HH requirements for existing and new sources 

will require time to repair the valves that are identified as leakers based on the lower leak 

definition, and that the number of valves determined to be leakers following the initial LDAR 

monitoring session could be significant. Therefore, subpart HH has been revised to allow 

existing sources up to 1 year following publication of the final rule in the Federal Register to 

achieve compliance. New sources must be in compliance on [60 days after the date of 

publication in the Federal Register] or startup, whichever is later.

We believe the 1 year compliance period is needed at existing natural gas processing plants since 

these facilities typically have several thousand of equipment components, and over one thousand 

valves, many of which are subject to the LDAR provisions in subpart HH. It is conceivable that 

many valves, not previously identified as leakers, will be classified as leakers under the lower 

500 ppm leak threshold in the final rule. We agree with the commenter and are allowing the 1 

year compliance period so companies have sufficient time to both assess the leak status of their 

valves on schedule with the rest of the facility under its LDAR provisions (typically quarterly), 

and make the necessary repairs to valves now determined to be leaking. We do not believe new 

sources require any additional time for compliance since the number of leaking components at a 

new facility should be less than at an existing plant.

Comment: One commenter (4193) proposes that the leak threshold for natural gas processing 

plants should be 5,000 ppm rather than 500 ppm. The commenter believes the 500 ppm threshold 

is not appropriate as natural gas processing plants have a substantially lower density of 

components requiring monitoring compared to chemical plants and refineries. In addition, the 

commenter states that natural gas processing plants are often operated by a minimum number of 

staff or remotely so they do not typically have the required maintenance personnel onsite, 

requiring them to rely on scheduling roving technicians or contractors in order to perform the 

initial attempt at repair, and then to monitor the repaired components, as required. The 

commenter contends that these circumstances would add considerably to the resource burden 

including time spent to reach facilities, need to spend extra time at facilities in order to 

implement a more extensive monitoring program, and additional logistics planning and training. 

A second commenter (4246) also does not support the 500 ppm leak definition. 

One commenter (4192) notes that the EPA lowered the subpart HH leak definition for valves to 

500 ppm. The commenter does not support a 500 ppm leak definition because the justification 

for achieving 10,000 ppm in the original 1984 KKK preamble is still valid today. The 

commenter notes that in the January 20, 1984 Federal Register to the KKK program, the EPA 

stated on page 2643 “...EPA is unable to conclude that a leak definition lower than 10,000 ppm 

would provide additional emission reductions...”.
301

Response: As explained in the preamble to the proposed rule and in the TSD, we evaluated four 

options for LDAR programs for equipment leaks as part of our technology review under section 

112(d)(6) for subpart HH. 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 the cost of the four identified control options for equipment leaks 

and found that lowering the leak definition for valves to an instrument reading of at least 500 

ppm was cost effective (see EPA-HQ-OAR-2010-0505-0062). Since the commenter did not 

question our reasoning or costs as presented in the preamble and the TSD, nor did the commenter 

provide quantitative information on the claimed increased burden, we are not changing the 500 

ppm leak definition for valves as provided in the final rule.

Comment: One commenter (4246) supports the EPA’s proposal to “Revise 40 CFR §63.769(b) 

for clarification of the equipment leak provisions in 40 CFR §63, subpart HH relative to source 

applicability if that source is already required to control equipment leaks under either 40 CFR 

part 63, subpart H or 40 CFR part 60, subpart KKK.” However, the commenter requests that the 

EPA include a MACT subpart HH exemption provision for sources already in compliance with 

equipment leak controls under 40 CFR part 60, subpart OOOO.

Two commenters (4192, 4262) note that the EPA proposes to revise §63.769(b) to clarify that the 

equipment leak provisions in subpart HH do not apply to a source if that source is required to 

control equipment leaks under either subpart H or subpart KKK. The commenters ask that the 

EPA add that a source that complies with equipment leak controls under 40 CFR 60, subpart 

OOOO is also exempt from the equipment leak provisions of subpart HH. 

The commenters (4192, 4246) add that §63.760(g)(1) should be revised to read: “After the 

compliance dates specified in paragraph (f) of this section, ancillary equipment and compressors 

that are subject to this subpart and that are [delete: also subject to and] controlled under the 

provisions of 40 CFR §60, subpart KKK [add: or subpart OOOO], are only required to comply 

with the requirements of 40 CFR §60, subpart KKK [add: or subpart OOOO.]” The commenters 

explain that this will provide owners and operators that are not subject to NSPS Subparts KKK 

or OOOO, but apply those LDAR requirements, flexibility to implement those requirements in 

lieu of the Subpart HH LDAR provisions.

Response: We have revised §63.769(b) to provide that sources complying with the LDAR 

requirements in 40 CFR part 60, subpart OOOO are deemed to be in compliance with the LDAR 

requirements in subpart HH. However, since the valve leak definition in subpart HH has been 

revised to 500 ppm we have removed the similar provision in §63.769(b) for sources controlled 

under 40 CFR part 60, subpart KKK because that subpart has a 10,000 ppm leak definition for 

valves and is no longer equivalent to subpart HH LDAR provisions. As a result, the language 

cited by the commenters in §63.760(g)(1) has been deleted in the final rule.
302

Concerning the comment to exempt sources complying with equipment leak provisions in 40 

CFR 63, subpart H and 40 CFR 60, subpart OOOO, we have included regulatory text that 

provides that sources that are in compliance with subpart OOOO are deemed to be in compliance 

with the LDAR requirements of subpart HH provided they meet the periodic reporting frequency 

specified in subpart HH (i.e., semi-annual vs. annual).

Comment: Two commenters (4246, 4266) state that §63.769(c) may apply not only to large 

natural gas processing plants that are subject to subpart KKK but also to smaller natural gas 

processing plant units where certain streams might be in VHAP service, which are currently not 

subject to subpart KKK per the intent expressed in §63.769(b). Therefore, the commenters 

believe that the EPA’s analysis overestimates the potential for emission reductions by lowering 

the leak definition for valves to 500 ppm. Thus, according to the commenters, imposing a lower 

leak definition for valves at both new and existing natural gas processing plants is not warranted 

in terms of exposure reduction from plant operations. The commenter notes that the risk benefit 

from the lower leak definition has not been demonstrated by the EPA especially for smaller 

natural gas processing units. The commenters recommend that the EPA retain the leak 

definitions for equipment leaks as currently promulgated in subpart HH to prevent added 

compliance confusion and high costs to industry without demonstrated significant risk 

reductions.

Response: We believe the commenter mistakenly attributed our revision of the leak definition 

for valves to our risk review under section 112(f)(2) of the CAA. This is incorrect, as we revised 

the leak definition as part of our technology review analysis under section 112(d)(6). As we 

described above, we determined that revising the leak definition to 500 ppm was cost effective 

for valves. Since the commenters did not provide any information to dispute our analysis, we are 

not changing the revision to the leak definition for valves in the final rule. 

3.5 Other Proposed Actions

3.5.1 Alternative to Use Manufacturer’s Testing Results for Certain Enclosed Combustion 

Control Devices

Comment: One commenter (4191) suggests that the EPA reset the subpart HH and HHH 

destruction efficiency for combustion devices from 98 percent to 95 percent. The commenter is 

concerned that basing the assumption of 98 percent control on manufacturer testing may not be 

valid, as, according to the commenter, these units operate under widely varying field conditions, 

including variations in fuel gas, ambient temperatures, and ambient pressures, among others. In 

addition, the commenter states that natural gas operations often are located in rural areas, at un-
303

manned stations, that commonly rely upon weekly or less frequent monitoring of the combustion 

device to verify operation. The commenter states that, while the combustion units may be 

capable of achieving 98 percent destruction efficiency, the actual control efficiency may differ if 

the unit is not consistently monitored to ensure proper operation. The commenter explains that 

their State’s policy allows for 95 percent destruction efficiency from combustion devices used at 

oil and gas sources, absent supplemental site-specific information approved by them which 

indicates that a higher destruction efficiency is appropriate. The commenter reports that they can 

provide the EPA with test data upon request.

Response: We received compelling information (i.e., source test data) from the commenter on 

the performance of combustion control devices located at oil and natural gas production 

facilities, controlling emissions from storage vessels and glycol dehydrators. The data brings into 

question the ability of these combustion control devices to reliably achieve that 98 percent 

control cannot be achieved in the field. Therefore, we have lowered the control efficiency for 

manufacturer tested combustion control devices to 95 percent in the final rule.

Comment: Two commenters (4192, 4246) support the EPA’s proposal to adopt an alternative 

performance test for non-flare combustion control devices. 

One commenter (4320) believes that the EPA should expand its proposed reliance on enclosed 

combustion device (ECD) manufacturer testing instead of requiring significant and potentially 

frequent performance testing of devices in the field by owner/operators, particularly for tanks. 

The commenter recommends that the EPA also allow for reduced or waived performance testing 

requirements in cases where ECDs currently in use are planned for removal due to the planned 

consolidation of tank batteries and their associated ECDs. The commenter currently plans for

consolidation for its operations in the Eagle Ford Shale, which would render the expense and 

burden of field testing of all currently deployed or soon to be deployed ECDs much less 

beneficial in terms of demonstrating compliance going forward. 

Response: As proposed, §63.772(e)(3)(vi) allows 3 years from the publication date of the final 

rule for existing sources to complete a performance test. Enclosed combustion devices planned 

for removal before that time would incur no costs for performance testing. In addition, sources 

have the option to use a manufacturer tested model of control device which carries no additional 

performance testing requirements for the life of the unit.

Comment: One commenter (4457) states that the EPA should not allow a manufacturer-only test 

for combustion devices. According to the commenter, such testing cannot anticipate local 

conditions that may adversely affect the performance of such devices. In addition, the 

commenter stated that the EPA, State regulatory agencies, and people who live near these 

sources need a way to verify ongoing compliance.
304

Response: As we stated at proposal, we believe that testing of certain combustion control 

devices in the field is not practical, thus we provided the option for the unit to be tested at the site 

of manufacturing. The commenter did not provide any information to contradict our belief that 

field testing is not practical. Therefore we are retaining the option for manufacturer testing of 

combustion control devices.

Comment: One commenter (4263) states that “fuel gas” and “inlet gas flow” to a combustion 

control device are different parameters. The commenter (4263) recommends replacing the term 

“fuel” with “inlet gas” in §§63.1282(g)(4)(i), (g)(4)(iii), (g)(4)(iii)(A) and (g)(4)(iii)(B).

One commenter (4263) recommends that the EPA delete §63.1282(g)(4)(iii)(B)(3) and consider 

deleting §63.1282(g)(4)(iii)(B) altogether. The commenter states that §63.1282(g)(2) states that 

“[p]ropene (propylene) gas shall be used for the testing fuel.” The commenter asserts that it is 

not necessary therefore to analyze the inlet gas for benzene and sulfur compounds. Also, 

according to the commenter, the EPA has not proposed performance standards related to the 

composition of the inlet gas, so the analysis of the inlet gas is not useful, other than to 

demonstrate that propylene was used.

One commenter (4263) argues that the determination of the volumetric flowrate from the 

combustion control device outlet using the methods referenced or described in §63.1282(g)(5) (i) 

and (ii) is not relevant to a demonstration that such a device achieves the performance 

requirements in §63.1282(g)(7), which is based on outlet pollutant concentrations. The 

commenter recommends that the EPA delete §63.1282(g)(5) (i) and (ii) and correct paragraph 

numbers.

Response: The EPA has modified the usage of the term “fuel” to be consistent with the term 

“inlet gas.” We have further modified the manufacturer’s certification test procedure to eliminate 

analysis for sulfur compounds and reduce the burden of the inlet gas sampling and analysis. The 

EPA will continue to require flow rate measurement for manufacturer’s performance testing.

Comment: Several commenters (4104, 4263, 4266) note that §63.1282(h)(3) and §63.772(i)(3) 

require monthly visible emissions tests using Method 22 of 40 CFR 60, Appendix A. Two

commenters (4104, 4266) state that monthly testing is excessively burdensome and not needed to 

assure combustor compliance because continuous monitoring of combustion control ignition is 

already required. One commenter (4104) maintains that the rule should be revised to eliminate 

visual emissions tests, or performed at uced frequency and duration. Two commenters(4104, 

4266) state that tests should be required every 6 months with an allowance for less frequent 

testing for units that routinely pass the visible emissions test. One commenter (4263) 

recommends a quarterly frequency with a duration of no more than 5 minutes. Two commenters
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(4104, 4266) believe that, at a minimum, similar relaxed testing requirements for a compliant 

unit should be added. According to one commenter (4104), if visible testing is retained, this 

would apply to some existing small dehydrators that may require control to meet the MACT 

floor emission standard. The commenter (4104) states that the EPA has not considered the 

associated compliance costs and additional analysis is warranted to justify visible emissions (and 

other) testing requirements in the proposed rule for newly affected small dehydrators.

Response: The EPA disagrees with the commenters’ assertion that a quarterly five minute 

observation is sufficient to determine appropriate control device operation. While we do agree 

that quarterly observations are appropriate given the distances between, and remote locations of, 

many facilities in this sector, we hold that the observation period per control device shall be 

maintained at a maximum of one hour per observation, while the control device is known to be 

combusting waste gas.

Comment: One commenter (4104) states that §63.1282(h)(4)(iii) requires the replacement of 

fuel nozzle(s) and burner tubes after one failed visible emissions test. The commenter states that 

the EPA should not stipulate specific equipment replacement or maintenance practices. The 

commenter notes that simple procedures (e.g., cleaning) may suffice, and other actions may be 

unnecessary and wasteful, or possibly not address the problem. The commenter contends that

these requirements should be deleted and the final rule should state that operators must perform 

maintenance and/or replace equipment as needed to restore combustion control device 

functionality. One commenter (4266) suggests the same changes be made to §63.772(i)(4)(iii).

Response: The EPA agrees with the commenter and has removed the requirement to replace the 

fuel nozzles(s) and burner tubes after the first Method 22 failure from the sections in subparts 

HH and HHH.

Comment: One commenter (4230) notes that the proposed rules allow sources to use a flare to 

control emissions from the affected storage vessels in accordance with NSPS §60.18 or MACT 

§63.11(b). The commenter notes that subpart HH and new NSPS subpart OOOO specify when 

performance tests (e.g., 180 days) must occur; however, these regulations do not specify when a 

flare compliance demonstration must occur. The commenter states that the MACT General 

Provisions in §63.11(b) requires Method 22 visible emission compliance demonstration and, 

depending on the flare compliance demonstration type, requires testing to demonstrate exit 

velocity (i.e., Method 2) and concentration (Ci) testing (i.e., Method 18 and ASTM D1946). 

Also, according to the commenter, §63.772(e)(2)(1) requires sources using a flare as a control 

device to conduct Method 22 visible emission readings. The commenter requests guidance and 

clarification as to when the initial flare compliance demonstration/testing must occur for these 

sources. 
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Response: The criteria specified for flares in the General Provisions (i.e., for NSPS §60.18(c)

and for MACT §63.11(b)) must be met upon operation of the flare. This includes all required 

calculations and associated testing specified under those sections. A source using a flare to 

comply with subpart HH would have to comply with the Notification of Compliance Status 

provisions in §63.772(d)(2) for flares. Since this report is due within 180 days of the applicable 

compliance date, the initial compliance demonstration would have to be completed within that 

period. 

Comment: One commenter (4263) states that the EPA should revise §63.772(e) to exclude flares 

from the requirements to conduct a performance test in accordance with §63.772(e)(3) and 

provides suggested regulatory language. The commenter explains that flares are subject to 

provisions of §63.772(e)(2).

Response: The EPA disagrees with the commenter and maintains that flares operated to meet the 

requirements of §§63.771(d)(1), (e)(3)(ii) or (f)(1) must meet the requirements of §63.772(e)(3). 

The EPA believes the existing language in §63.772(e)(1)(i) and (e)(2)(ii) is clear regarding the 

requirements for flares and no revisions are necessary.

Comment: One commenter (4263) states that the EPA should revise §63.772 (e)(3)(v) to apply 

only to small glycol dehydration units that use a control device to comply with the limits set out 

at §63.765(b)(1)(iii) and provides suggested regulatory language. The commenter explains that 

the cited paragraph only applies to small glycol dehydration units that are equipped with a 

control device, as referenced by §63.772(d)(1).

Response: The section the commenter is referring to, §63.772(e)(3)(v), only applies to control 

devices that are used to comply with the BTEX limit specified in §63.771(f)(1).

Comment: One commenter (4263) states that the EPA should revise §63.772(e)(3)(i)(B) and 

§63.772 (e)(3)(v) to provide correct citations/references and provides suggested regulatory 

language. The commenter explains that the cited §63.765(b)(1)(iii) specifies BTEX emission 

limits, not total HAP concentration limits, and §63.771(f)(1) does not specify BTEX emission 

limits.

Response: The commenter is correct that §63.771(f)(1) does not specify a BTEX limit. The EPA 

will revise the rule language in §63.772(e)(3)(v) to reference §63.765(b)(1)(iii).

Comment: One commenter (4266) notes that many of the revisions to the control equipment 

requirements of §63.771 apply to equipment that is currently required. The commenter adds that 

no provisions have been made to indicate when these requirements were changed. The 

commenter states that the EPA should revise the proposed rule so that the new performance 
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testing requirements apply only to control equipment installed for the purpose of complying with 

this subpart after the effective date of this rule.

Response: The revisions to require performance testing for all control devices except condensers 

was intended to apply to all control devices complying with the provisions of subparts HH and 

HHH. We provided a 3 year compliance period for existing sources in subpart HH in 

§63.772(e)(3)(vi)(A), and in subpart HHH in §63.1272(d)(3)(vi)(A). We have added dates in 

both of these sections specifying which control devices have up to 3 years to conduct the 

performance test or install a unit tested by a manufacturer.

3.5.1.1 Miscellaneous Comments

Comment: One commenter (4191) suggests that the EPA require that the waste gas flow, 

pressure, and temperature range be listed by the manufacturer and monitored by the operator in 

the field to ensure that actual operation is within the specification of the passing test for control 

devices. The commenter further suggests that operators be required to develop a maintenance 

schedule to ensure control devices are operating at manufacturer specifications.

Response: The EPA is revising the final rule to stipulate such flow volumes may be modeled by 

computer software tools that are standard in the industry for such purposes. We are also requiring 

a maintenance and repair log for such devices which must be updated by actions taken following 

the failure of any failed visual inspection, which is to be performed quarterly.

Comment: One commenter (4104) notes that §63.1283(b) requires semi-annual inspections of 

manufacturer performance tested combustion control devices. The commenter states that the 

EPA should not stipulate a specific inspection frequency. Instead, the commenter recommends 

that inspection and maintenance practices should be based on manufacturer specifications or 

industry practices with procedures documented in the required inspection and monitoring plan. 

Another commenter (4266) makes the same comment with respect to §63.773(b).

Response: The EPA believes semi-annual inspections should be required to ensure manufacturer 

performance tested combustion control devices are operating properly. There may be cases 

where a manufacturer does not specify periodic inspections. In those cases, it is important that 

source owners perform periodic inspections. The EPA believes that semi-annual inspections are 

not overly burdensome. A semi-annual visual inspection is sufficient and appropriate for 

manufacturer performance tested combustion control devices.

Comment: One commenter (4266) also notes that §63.773(d)(3)(i)(C) should clarify that a heat 

sensing monitoring device to indicate continuous ignition of the pilot flame is not required for 

flares equipped with electronic ignition systems.
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In addition, one commenter (4104) states that, for combustion control devices performance tested 

by the manufacturer, §63.1283(d)(3)(i)(H)(2) requires a heat sensing monitoring device equipped 

with a continuous recorder that indicates the continuous ignition of the pilot flame. The 

commenter states that this requirement should not apply for control systems with electronic 

ignition systems. 

Similarly, one commenter (4266) notes that §63.772(i)(2) requires that a pilot flame be present at 

all times of combustion control device operation. According to the commenter, this requirement 

is not applicable for combustion control devices equipped with electronic ignition systems. The 

commenter adds that for combustion control devices equipped with electronic ignition systems, 

the rule should add a requirement that these be operational at all times of combustion control 

device operation. The commenter provides suggested regulatory text. 

Response: We do not believe that an electronic ignition system is equivalent to a heat sensing 

monitoring device for either a flare or a combustion control devices tested by the manufacturer 

under subparts HH and HHH. There is not sufficient data at this time to suggest that electronic 

ignition systems on combustion devices are capable of continuously supplying a constant source 

of ignition to keep a flame present on a continuous basis. In addition, for flares, test data for 

which the current standards in §§63.11(b) and 60.18 were written show that operating a flare 

with a continuously lit pilot adds an additional degree of flame stability to the flare itself. 

Therefore, no changes are being made to §§63.773(d)(3)(i)(C), 63.1283(d)(3)(i)(H)(2), or

63.772(i)(2) in response to this comment.

Comment: One commenter (4266) states that the EPA should clarify that the requirements in 

§63.771(d)(1)(i) for enclosed combustion control devices for "sources except small glycol 

dehydration units" (i.e., large dehydration units and tanks) is correctly interpreted as: 

 Operators may comply with the requirements to reduce HAP emissions in accordance 

with §§63.771(d)(1)(i) (A), (B), (C), or (D).

 Operators that comply with the requirement to reduce HAP emissions in accordance with 

§63.771(d)(1)(i)(C) are only required to conduct an initial performance test that 

demonstrates that the combustion zone profile has a minimum temperature of 760°C. 

Response: The commenter is incorrect. Section 63.771(d)(1)(i)(D) is a clarification of A, B or C,

not a standalone requirement. Concerning §63.771(d)(1)(i)(C), the owner or operator must 

perform an initial performance test to determine the performance (control efficiency) of the 

control device at a combustion zone temperature of at least 760°C and must be using the 

combustion zone temperature as an indicator of control efficiency. In other words, the owner/ 

operator must verify the control efficiency achieved at the desired combustion zone temperature 

before that combustion zone temperature can be used as an indicator of control efficiency. 
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Additionally, in order to use combustion zone temperature as an indicator of control efficiency, 

the combustion zone temperature must be at least 760°C.

Comment: Two commenters (4104, 4266) state that "uniform" should be deleted from 

§63.771(d)(1)(i)(C) because “uniform” is not defined in the rule, and the complex interactions of 

flame zone reactions, mixing, and convective and radiative heat transfer preclude "uniform" 

combustion zone temperature profiles. The commenters state it appears that the EPA's intent is 

that the combustion zone profile must have a minimum temperature of 760°C such that there are 

no low temperature pathways for HAPs to escape destruction. 

Response: We agree with the commenters. This section now specifies a minimum temperature 

rather than a uniform temperature. We made similar changes to §63.772(e)(3)(vi)(B)(2).

Comment: One commenter (4266) notes that §63.772(f)(3) states: “For inlet gas flow rate, 

compliance with the operating parameter limit is achieved when the value is equal to or less than 

the value established under §63.772(h).” However, the commenter notes that §63.772(h) only 

applies to manufacturer performance tested combustion control devices and would not apply to 

dehydrators that are not equipped with manufacturer performance tested combustion control 

devices. Another commenter (4104) made the same comment with respect to §63.1282(e)(3)and 

§63.1282(h).

Response: We agree with the commenters and have revised these sections to allow for 

manufacturer or non-manufacturer tested units.

Comment: One commenter (4266) notes that §63.772(i)(1) requires the continuous monitoring 

of the inlet flow rate for manufacturer performance tested combustion control devices, and the 

flowmeter is required to have an accuracy of +/- 2 percent. The commenter asserts that 

flowmeters for this type of low pressure low velocity stream application and service are not 

feasible and demonstration of flow to the enclosed combustion device should rely on appropriate 

models (E&P TANK or process simulation model for tanks, GRI-GlyCalcTM or process 

simulation model for dehydrators) to set volumetric operating parameters for conforming with a 

manufacturers range for a combustion device. The commenter states that a process simulation 

model may be used to establish a lower and upper limit for oil throughput in a storage tank which 

corresponds with a manufacturers Btu operating range for a combustion device. The commenter 

adds that an operator could then use their average production rates, as determined by normal 

production volume accounting methods and frequencies, to ensure they are within this range and 

demonstrate compliance. The commenter requests that the EPA modify the proposed rule to 

eliminate continuous flow metering to control devices and enable the use of appropriate models 

to set limits on normally measured parameters to demonstrate compliance. Given the small size, 

dispersed nature, and large number of units affected by this rule, the commenter contends that 
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these changes would appropriately reduce burden while providing for compliance demonstration 

and monitoring.

Response: We agree with the commenter and have revised §§63.772(i)(1) and 63.1282(h)(1) to 

allow a flow calculation.

3.5.2 Addition of Definition for Flare

Comment: One commenter (4192) supports the definition of flare (“Flare means a thermal 

oxidation system using an open flame (i.e., without enclosure)”), and another commenter (4246) 

suggests adding a definition of “flare” to §63.761.

One commenter (4263) states that the EPA should revise the definition of flare to reflect the 

types of flares evaluated by the EPA in its development of the general control device 

requirements for flares, i.e., those flares that were evaluated as part of the Flare Efficiency Study, 

EPA-600/2-83-052, U. S. Environmental Protection Agency, Cincinnati, OH, July 1983. The 

commenter states that flares do not include ground flares or enclosed combustors. The 

commenter also states that the proposed definition of flare is appropriate, but is too broad and 

goes beyond the meaning of the term flare, as regulated by the general control device provisions, 

part 60 and part 63. 

Response: We agree that the final rule should include a definition for flare, which we provided 

in the proposed rule. However, the definition is intended to clarify which flares must follow the 

requirements in §63.11 and which can rely on manufacturer’s testing. Thus, we did not modify 

the definition to reflect all the types of flares evaluated by the EPA.

3.5.3 Monitoring, Recordkeeping and Reporting

Comment: One commenter (3529) believes that the notification, recordkeeping, monitoring and 

annual reporting requirements in the proposed NSPS and NESHAP rules are extremely 

burdensome for operators and for state regulators with limited resources. The commenter states 

that the proposed rules require operators to install expensive monitoring systems with 

questionable environmental benefits. The commenter believes that the proposed rules will have 

devastating economic impacts on small operators. 

One commenter (4358) states that the system of notifications, monitoring, recordkeeping, 

performance testing and reporting requirements for compliance assurance is overly burdensome 

for the small and/or temporary affected facilities that the EPA is regulating.
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Response: We estimate the burden to the industry imposed by the final rule and found that the 

burden was not unreasonable, even for small sources. See the discussion of the cost impacts in 

section XI. of the preamble.

3.5.3.1 Calibration Procedures Associated with Parametric Monitoring

Comment: One commenter (4266) notes that requirements for using an enclosed combustion 

device for HAP control under subpart HH or HHH are specified in §63.771. However, the 

commenter states that operational conditions in the oil and natural gas production sector are very 

different from those experienced at refineries or chemical plants. According to the commenter, 

conditions of intermittent, variable and turbulent flow and variable temperature and pressure 

make it infeasible to perform the test methods in the production field that are typically used in 

refineries or chemical plants. The commenter adds that coupled with the dispersed and remote 

nature of the small sources regulated under this rule, the proposed requirements are not 

appropriate and are unnecessarily burdensome. 

The commenter (4266) requests that the requirement in §63.771(d)(1)(i)(A) should be modified 

to require reduction of either TOC or HAP emissions by 95 percent on a volumetric 

concentration basis using a “carbon balance” methodology for analysis of the exhaust stack 

effluent from an “enclosed combustion device” being used as a control device to demonstrate 

reduction efficiency. The commenter suggests test methods and a procedure to determine TOC. 

The commenter provides a table that shows this calculation and outcome for an assumed stack 

effluent composition. The commenter states that the suggested carbon balance methodology is 

similar to that described in EPA’s Technical Report “EPA-AA-SDSB-80-05” Carbon Balance 

and Volumetric Measurements of Fuel Consumption used by the EPA for vehicle testing. 

Response: The EPA agrees that operational conditions in the oil and natural gas sector are 

unique. For that reason, the EPA gives the option for sources to purchase an enclosed combustor 

that has passed a test performed by the manufacturer. The EPA evaluated the “carbon method” 

suggested by the commenter but found that the destruction efficiency measurement should 

remain as it is. The inclusion of CO as an indicator of destruction is not entirely accurate. The 

equation, as the commenter suggests, would make it extremely difficult for a combustion control 

device to fall below 95 percent.

Comment: One commenter (4266) states that the EPA should modify the requirement in 

§63.771(d)(1)(i)(B) of the proposed rule to demonstrate that TOC (as propane – method 25A) 

concentration in the stack exhaust from an enclosed combustion device is less than 200 ppmv 

corrected to 3 percent CO2 in the stack. The commenter notes that using the carbon balance 

methodology described above a 200 ppmv TOC would correspond to slightly above 98 percent 
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destruction efficiency which leaves a wide margin between the alternative of 95 percent 

destruction efficiency. 

The commenter notes that the proposed rule indicates an alternative control device exhaust 

concentration requirement of less than 20 ppm corrected to 3 percent oxygen. According to the 

commenter, combustors typically have carbon dioxide concentrations of approximately 3 percent 

and oxygen concentrations of approximately 16 percent. The commenter states that 20 ppm 

corrected to 3 percent oxygen corresponds to an in-stack actual concentration of approximately 5 

ppm which would likely correspond to a destruction efficiency approaching 100 percent (the 

alternative requirement is 95 percent destruction). The commenter believes this is a simple 

mistake and the correct formulation would be corrected to 3 percent CO2. The commenter states 

that this would be consistent with §§63.772(h)(6)(vi) and 63.772(h)(7)(i)(B), where the proposed 

rule indicates the concentration limits for the manufacturers of combustors conducting a 

performance test and specifies an exhaust concentration requirement of being less than 10 ppm 

corrected to 3 percent carbon dioxide. The commenter notes that this appears inconsistent with 

the 3 percent oxygen correction stated in §63.771(d)(1)(i)(B), where it outlines the general field 

performance test requirements. As stated, according to the commenter, the manufacturers of 

combustors would actually have a less restrictive limit than owners conducting a field 

performance test.

Response: The EPA does not agree with the commenter that CO is equivalent to destruction of 

TOC and we have not modified the calculation of destruction efficiency as suggested. The EPA 

has reviewed O2 /CO2 correction and found that it was referenced appropriately in the rule for the 

referenced combustion controls.

Comment: One commenter (4266) adds that the EPA should modify the requirements in 

§63.772(h) to conform with the carbon balance test methodologies for field performance testing. 

The commenter suggested that the ppmv performance criteria stated in §63.772(h)(7)(i)(B) 

should be modified to 100 ppmv TOC (as propane) corrected to 3 percent CO2, which 

corresponds to approximately 99 percent destruction efficiency and provides ample buffer 

between a manufacturers tests for certification and the required 95 percent destruction efficiency 

for field demonstration. As currently constructed, the commenter states that the manufacturers 

certification testing must show approximately 99.97 percent destruction which is unreasonable 

and certainly not supportable from the standpoint of rule cost effectiveness. 

Response: The EPA has targeted 10 ppmv TOC (as propane) corrected to 3 percent CO2 as the 

benchmark to provide for an ample margin of safety in contrasting a device tested in a controlled 

environment versus a device operating at field conditions. Field gas is neither available nor 

practical for use in manufacturer-testing these devices, and a homogenous fuel such as propene is 

unlikely to present all the combustion challenges that field gas would provide in actual operation.
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Furthermore, field conditions involve greatly varying wind and ambient humidity conditions that 

present further combustion challenges for operation these devices. Given the differences between 

field operation and controlled environment, the EPA has set the bar at a level calculated to 

provide 99 percent confidence in the ability of a manufacturer-tested device to meet the field 

demonstration requirement under a variety of field operating conditions. Lowering the standard 

to the level suggested by the commenter reduces this margin of safety to a level that is several 

times more likely to result in a certified device failing the field demonstration requirement of 95 

percent destruction.

Comment: One commenter (4266) suggests that the EPA should remove §63.772(h)(7)(i)(C) to 

eliminate the consideration of CO concentration in the manufacturers certification testing. By 

imposing a CO concentration, the commenter contends that the EPA is effectively converting the 

destruction efficiency testing to combustion efficiency testing which is not required by nor 

appropriate for the proposed rule.

Response: The EPA disagrees with the commenter and holds that CO measured during the 

manufacturers’ certification test is for the purpose of ascertaining complete destruction of 

organic hydrocarbon compounds.

3.5.3.2 Limit Use of Design Analysis to Condensers

Comment: Several commenters (4104, 4214, 4249) state that the EPA does not provide or 

reference test results, studies, or source data from subpart HHH (or subpart HH) affected sources 

to support what they “have learned regarding control devices and compliance” and the decision 

to remove the design analysis compliance option. The commenters state that if the EPA lacks 

evidence from units currently complying with subpart HHH (or subpart HH) to support this 

decision, such as non-compliant tests from design analysis-compliant control equipment, then the 

final rule should retain the design analysis compliance option consistent with the existing rule.

Response: The EPA believes that periodic testing of affected sources is the best method for 

determining compliance. In the case of enclosed combustors, sources have the alternative option 

to purchase a combustion control device that has been tested (and passed) by the manufacturer.

The EPA believes that periodic testing for other noncondenser controls is appropriate and 

necessary to show compliance.

Comment: One commenter (4039) believes that the EPA should clarify that design analysis is an 

acceptable tool for determining facility emissions status. The commenter states that removal of 

this option will result in the loss of the ability to use design analysis to determine major or minor 

status. If this is the case, the commenter contends that states and permittees would be forced to 

conduct sampling at all facilities using controls solely for the purposes of determining if they are 
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subject to the rule, not only to demonstrate compliance with the rule (assuming that a facility is, 

indeed, subject to the rule.) The commenter requests that the EPA clarify that design analysis 

will remain a tool for determining facility status and that sampling is only required to 

demonstrate compliance with the emission reduction requirements.

Response: The proposed changes that removed the design analysis option for certain control 

devices applies to sources that are subject to the either subpart HH or HHH and does not pertain 

to sources determining their major source status.

Comment: One commenter (4230) raises concerns over elimination of the design evaluation 

alternative and whether the alternative would still be appropriate for demonstrating the flare 

assessment requirements under §63.11(b). According to the commenter, one option would be to 

allow the flare assessment to be based on design principles and GRI-GLYCalcTM emission 

estimates. The commenter adds that then the challenge becomes to assure the proper BTU and tip 

velocities are met under actual operating conditions. From experience, the commenter states that 

this has been addressed by visible emission testing and pilot light records. In West Virginia, the 

commenter states that sources have spent a great deal of money testing dehydration units only to 

find that the test data was questionable due to leaking Method 18 bags and/or questionable audit 

spike results, which is further compounded by trying to capture a representative sample within 

the high moisture content dehydration still vent stream. The commenter says that it seems the 

testing of dehydration units has been plagued with technical difficulties from the start. It was 

noted by the commenter that within the development of the GRI-GLYCalcTM software, GRI had 

to use a total condensation method to verify emissions during their case studies. Therefore, the 

commenter contends that the sampling and analysis methods used by the natural gas industry 

seem to conflict with those prescribed by Method 18. 

According to the commenter (4230), in light of the previously allowed design alternative and due 

to the high water content of these production streams, flares used at minor source dehydrators in 

West Virginia have been allowed to use a design analysis in order to demonstrate compliance 

with the heat content and tip velocity requirement by using GRI-GLYCalcTM predictions. 

However, the commenter states that it was noted that the federal flare provisions actually require 

Method 18 and Method 2 to be utilized as field test methods in order to assess compliance with 

the minimum BTU and tip velocity requirements specified by §63.11(b). As an alternative, if 

field testing of flares remains a priority to assess whether the flare is being operated as designed, 

the commenter requests that the EPA specify when this field testing should be completed as well 

as develop guidance on how this testing can be accommodated by one of the Method 18 options 

or develop a new methodology that can be used to handle the condensibles when obtaining grab 

samples. The commenter states that grab samples are specifically mentioned here since the onsite 

GC analysis required by the alternative ASTM Method D6420-99 (2004) may not be practical in 

all instances.
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Response: It was not our intent to disallow the design criteria under §63.11(b) from being used 

to demonstrate compliance for flares. We have revised §§63.772(e) and 63.1282(d) to clarify that 

the design criteria in §63.11(b) still applies to flares complying with subparts HH and HHH.

Comment: One commenter (4265) requests that the EPA allow a design analysis, as under the 

existing subpart HHH, as a means to demonstrate control device performance for all control 

equipment. The commenter asserts that the elimination of the design analysis for demonstrating 

control device performance for all but condensers in the proposed rule is unsubstantiated. 

According to the commenter, the EPA does not provide sufficient test data or other supporting 

evidence to justify the elimination of this compliance option in the proposed rule.

Several commenters (4104, 4192, 4214, 4246, 4249) state that the EPA should allow a design 

evaluation as an alternative for noncondenser controls.

One commenter (4457) supports periodic testing requirements proposed for all non-condenser 

control devices (and elimination of design evaluation alternative). However, the commenter 

states that the EPA must apply these requirements to all devices, including condensers. The 

commenter contends that the EPA fails to justify not doing so.

Response: Regarding the design evaluation, such a requirement in lieu of a performance test is 

only appropriate for condensers. Emissions from condensers are accurately predictable using 

readily available physical properties information (e.g., vapor pressure data and condensation 

calculations). In most cases, one may not even need to conduct emissions testing to determine 

actual emissions using such data for the compounds of interest. For example a requirement that 

“the temperature at the outlet of the condenser shall be maintained at 50°F below the 

condensation temperature calculated for the compound of interest using the reference equation” 

(e.g., NIST Chemistry WebBook at http://webbook.nist.gov/chemistry/) is sound.

For other types of control technologies such as carbon adsorption systems and combustion 

devices, the ability to predict emissions depends on data developed by the vendor and such data 

may not reliably result in an accurate prediction of emissions from a specific facility. There are 

variables (e.g., A/F ratios and waste constituents for combustion; varying organic concentrations, 

constituents, and capacity issues including break-through for carbon adsorption) that make 

theoretical predictions less reliable. The effects of these site-specific variables on emissions are 

not easily predictable and establishing monitoring conditions (e.g., combustion temperature, 

vacuum regeneration) based on vendor data will likely not account for those variables.

That is not to eliminate entirely the use of vendor data in establishing initial or conservative 

compliance monitoring conditions for carbon adsorption and combustion devices. An alternative 
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requirement is to allow the source owner to establish some initial conditions based on vendorsupplied data (e.g., 50°F above the demonstrated laboratory or pilot model destruction 

temperature) but which must be substantiated and redefined, as necessary, with a performance 

test (e.g., initial, annual, permit term). For carbon adsorption installations, specifically, another 

alternative is to use very conservative capacity factors to assure compliance (e.g., replace 

adsorption material at 50 percent of the predicted capacity/life of the adsorbent). This approach 

combined with a periodic break through check with a VOC analyzer can be an effective 

compliance monitoring approach.

3.5.3.3 Remove Residence Time Requirement for Combustion Control Devices

Comment: Two commenters (4192, 4246) support the EPA’s proposal to remove the 0.5-second 

residence time requirement for combustion control devices.

Response: The EPA agrees with the commenter and has removed the residence time 

requirement.

3.5.3.4 Clarify Location of Temperature Sensor

Comment: Two commenters (4104, 4266) find the proposed language regarding the location of 

a temperature sensor for thermal vapor incinerators (§63.1283(d)(3)(i)(A)) to be poorly written 

and confusing. The commenters state that a literal reading infers that a thermal vapor incinerator 

performance test that does not demonstrate that combustion zone temperature is an accurate 

indicator of performance is not required to install a temperature monitoring device. Further, the 

commenters state demonstrating that “combustion zone temperature is an accurate indicator of 

performance” would require testing over a range of temperatures and correlating performance 

with temperature. According to the commenters, this is not a performance testing requirement in 

the proposed rule nor should it be. In addition, the commenters state that the proposed rule does 

not define or discuss how to determine “a location representative of the combustion zone 

temperature.” To address these issues, the commenters provide proposed revised text for this 

paragraph and for similar text in §63.1283(d)(3)(i)(D) for boilers and heaters used as a control 

device. One of the commenters (4266) recommends making the same types of changes to 

§63.773(d)(3)(i)(A).

One commenter (4266) adds that the phrase “or downstream temperature” that has been added to 

the recommended rule text is because of the practical considerations associated with measuring 

combustion zone temperatures. The commenter states that high temperatures and reactive 

chemical species rapidly degrade in situ measurement devices. The commenter adds that 

equipment properly installed for downstream temperature measurements typically have a much 

longer operational life and provide an accurate indication of combustion conditions. As long as 
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the compliance temperature is in the same location as the temperature measured during the 

performance test, the commenter contends that location provides compliance assurance. The 

commenter also recommends revisions to §63.773(d)(3)(i)(D) to address the temperature sensor 

location issue, previously discussed for thermal vapor incinerators, for boilers and heaters where 

the waste gas is not mixed with or used as the primary fuel.

Response: The EPA agrees with the commenter that the temperature sensor location can be 

downstream of the combustion zone for a boiler or process heater or thermal vapor incinerator, 

as long as the compliance temperature is in the same location as the sensor during the 

performance test. 

3.5.3.5 Revised Temperature Monitoring Device Minimum Accuracy Criteria

Comment: Two commenters (4104, 4266) disagree with the EPA’s proposal to change the 

temperature monitoring device accuracy requirements from +/- 2 to +/- 1 percent of the 

temperature being monitored. The commenters state that the EPA provides no data or analysis to 

support the need for a more stringent accuracy requirement. At typical control device 

temperatures, the commenters state that any change in combustion efficiency and emissions 

caused by a temperature change represented by the difference between 1 and 2 percent accuracy 

is most likely not detectable. Further, according to the commenters, the EPA contradicts the need 

for the rule revision by stating that it believes that current temperature monitoring devices can 

meet the criteria without modification. If current devices are sufficiently accurate, the 

commenters question why there is a need for a new accuracy standard. While stating this is a 

relatively minor issue, the commenters believe it provides another example of the proposed rule 

imposing an administrative burden without good cause. The commenters contend that the 

primary effect of the rule revision would be to impose burden to modify internal procedures 

and/or recalibrate select devices. 

Response: The EPA agrees with the commenters and has removed the stricter temperature 

accuracy requirements from the rule.

3.5.3.6 Recordkeeping, Reporting, and Monitoring Requirements for Carbon Adsorbers

Comment: Two commenters (4104, 4266) state that the current rule flow meter accuracy 

requirement of +/- 10 percent for regenerative-type carbon adsorption systems should be retained 

in §63.1283(d)(3)(i)(F)(1). The commenters state that the EPA has not demonstrated the need for 

a revised flow meter accuracy requirement including how this revision will improve emission 

control, nor demonstrated that the additional cost to replace existing equipment and install 

alternative flowmeters is justified. 
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Response: The EPA agrees with this comment and will keep the 10 percent accuracy 

requirement in the rule.

Comment: Two commenters (4104, 4266) state that the checks of mechanical connections for 

leakage for regenerative-type carbon adsorption systems required by §63.1283(d)(3)(i)(F)(1) 

should be performed every 3 months, rather than monthly, in concert with the required visual 

inspections. Absent moving parts, the commenters contend that the mechanical connections are 

extremely slow to develop leaks and more frequent checks add unnecessary labor and 

recordkeeping burden. One commenter (4266) makes the same comment regarding 

§63.773(d)(3)(i)(F)(1).

Response: We have revised the two sections cited by the commenters to allow quarterly 

monitoring for all components.

3.5.3.7 Parametric Monitoring of Control Device for BTEX Emissions from Small Glycol 

Dehydration Units

Comment: Several commenters (4104, 4170, 4185, 4241) agree with the EPA’s decision that 

BTEX CEMS are not practical due to attributes of the affected sectors – e.g., relatively remote 

locations, unmanned facilities, etc. In addition, the commenters state that BTEX CEMS 

operation and performance are questionable (i.e., not an established technology), emission levels 

are very low, and the benefit from such a high cost compliance assurance approach cannot be 

supported. The commenters state that both capital and ongoing operation and maintenance costs 

would be significant even if the technology was feasible. The commenters add that CEMS 

should not be considered for this rule. One commenter (4185) adds that given the availability of 

an acceptable alternative (parametric monitoring), requiring the use of CEMS on small glycol 

dehydration units is not justified. 

Two commenters (4170, 4185) agree that the parametric monitoring approach that the EPA has 

proposed as an alternative to CEMS is a reliable and cost-effective way of ensuring that BTEX 

controls on small glycol dehydration units are functioning properly. One commenter (4185) 

notes that small glycol dehydration units are in widespread use throughout the natural gas supply 

chain. 

Three commenters (4192, 4193, 4246) believe that CEMS should not be required for small 

dehydrators. The commenters state that small dehydrators are usually in remote locations lacking 

access to electricity, are often exposed to weather that would reduce CEMS reliability, and 

without easy access to qualified personnel to monitor and maintain CEMS devices. The 

commenters state such a requirement would be entirely infeasible.
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Response: We agree with the commenters and have not included CEMS in the final rule.

Comment: One commenter (4266) states that the requirements for continuous monitoring of 

parameters to demonstrate continuous compliance are unnecessarily complex, likely not 

technically achievable in certain instances, and unnecessarily costly. The commenter states that 

the EPA should redraft the performance testing and continuous compliance monitoring 

requirements of the rule to: (1) simplify requirements, include only requirements appropriate for 

the large number and type of dispersed small sources which would be subject to the rule, (2) 

reduce the extensive cross referencing in the testing and monitoring requirements to reduce the 

confusing nature of the proposed rule and lessen the chance that the confusing construction of 

the rule will inadvertently lead to non-compliance incidents through misunderstanding, and (3) 

reduce the unnecessary economic burden.

Several commenters (4192, 4193, 4246) believe that CPMS should not be required for small 

dehydrators. The commenters state that small dehydrators are usually in remote locations lacking 

access to electricity, are often exposed to weather that would reduce CPMS reliability, and 

without easy access to qualified personnel to monitor and maintain CPMS devices. 

Response: The EPA disagrees with the comment that monitoring required to demonstrate 

compliance is unnecessarily complex or costly. Monitoring is vital to ensure compliance with 

these regulations. The EPA acknowledges that some sources are very dispersed and/or have no 

electricity and we designed the monitoring requirements with that in mind.

Comment: One commenter (4263) objects to a requirement for CPMS for vapor combustion 

units because it is reasonable to equip small vapor combustion units with sensing equipment to 

indicate the presence of a pilot flame or auto-ignitor signal, but it is not cost-effective to install 

and operate a continuous recorder or data acquisition system. The commenter states that many 

regulated entities operate numerous vapor combustion devices in certain fields or operating areas 

and the aggregate cost to install a CPMS on each unit would far exceed the benefit. The 

commenter notes that CPMS is not practical or cost-effective for unmanned facilities without 

remote communication. Another commenter (4228) agrees that CPMS may not be feasible at 

remote locations due to lack of electricity and accessibility. The commenter adds that alternative 

manual data logging procedures are needed and should occur on the normal site visitation 

schedule.

Response: It is unclear which type of CPMS the commenter is referring to. There are 

inexpensive ways to ensure that a pilot light is on at all times. A CPMS does not necessarily 

mean that the parameter value needs to be recorded.
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Comment: One commenter (4246) states that the EPA did not include costs associated with 

installing, maintaining, and operating a CPMS. The commenter notes that most storage tanks 

subject to these requirements are located in remote areas without access to sufficient available 

electricity or limited remote transmitting unit (RTU) space. In addition, the commenter states 

that the use of a programmable logic controller (PLC) is often necessary to record, average, and 

analyze data to determine if a threshold has been exceeded. According to the commenter, the 

calibration, maintenance, and repair of a CPMS requires specialized personnel knowledgeable in 

this type of instrumentation and controllers. The commenter adds that it is normally not possible 

for plant personnel to perform these activities during regular visits.

Response: The EPA disagrees with the commenter. Our calculation of the cost and 

environmental impacts of the MACT compliance options for storage vessels (see Docket ID No. 

EPA-HQ-OAR-2010-0505-0046) took into account the cost of CPMS systems for a flare. In 

addition, the Information Collection Request Supporting Statement for subpart HH (see Docket 

ID No. EPA-HQ-OAR-2010-0505-0043) and subpart HHH (see Docket ID No. EPA-HQ-OAR2010-0505-0044) each included CPMS costs.

Comment: One commenter (4263) states that the EPA should amend §63.773(d)(3)(i)(A) to 

provide uniform inspection and monitoring requirements for small vapor combustion control 

devices equipped with a continuous pilot or auto ignition system and provides suggested 

regulatory text. The commenter explains that there are thousands of small vapor combustion 

units used by the industry throughout the U.S. to combust vapors emitted from crude oil and 

condensate tank batteries and glycol dehydration unit process vents. According to the 

commenter, these devices are often located in remote locations where there is no electricity and 

where access can be limited during winter months. The commenter states that the vapor 

combustion units may be equipped with a continuous pilot or an auto-ignition system designed to 

ignite gas/vapor that may be vented intermittently from the controlled equipment. 

The commenter (4263) believes that operators would be obligated to submit a request for 

approval of the selected process parameters to be monitored for each vapor combustion unit, 

which would result in an unnecessary burden on industry and a substantial administrative burden 

on the delegated state or local authorities and the EPA for sites under federal jurisdiction. Given 

that small vapor combustion units are commonplace in the industry, with many thousands of 

units currently in service throughout the U.S., the commenter recommends that the EPA 

promulgate uniform standards for testing, inspections and monitoring for such units. To 

demonstrate performance of these devices, the commenter states that it is sufficient to rely on 

initial performance testing, or manufacturer’s performance testing supplemented with periodic 

inspections or monitoring to document proper operation in conformance with each device’s 

design.
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Response: The EPA believes that only in certain cases (those proposed in the rule) is periodic 

testing not necessary. In all other cases, periodic performance testing is necessary to ensure 

compliance with these regulations. Monitoring and inspections are good indicators of 

performance for combustion control devices, but they are not fail-safe. We have edited the rule 

language to take into account ignition systems other than those with a pilot flame.

Comment: One commenter (4263) adds that the EPA should amend §63.773(d)(3)(i)(H) to 

remove the requirement to install a continuous monitoring system that measures gas flow rate at 

the inlet to the control device and provides suggested regulatory text. The commenter explains 

that the inlet gas flow rate to the control device is not an indicator of performance. The 

commenter adds that control devices should be properly sized for the intended use. Performance 

is demonstrated by the manufacturer’s performance test and periodic monitoring or inspections 

documenting that the device is operated properly in conformance with its design.

Response: We have added §63.773(d)(3)(i)(H)(1) to allow calculation of the flow rate using 

various process simulation programs. Similarly, section §63.1283(d)(3)(i)(H)(1) has been added 

to subpart HHH.

Comment: One commenter (4191) suggests that waste gas flow, pressure, and temperature range 

be listed by the manufacturer and monitored by the operator in the field to ensure that actual 

operation is within the specification of the passing test for control devices. The commenter 

further suggests that operators develop a maintenance schedule to ensure control devices are 

operating at manufacturer specifications.

Response: The EPA agrees that operators should develop a maintenance schedule or follow such 

a schedule provided by the manufacturer, if available. The EPA communicated with 

flare/combustion control device manufacturers before proposal and learned that some 

manufacturers do not typically specify operating parameters for the control device. Therefore, 

the EPA does not feel it is practical to rely solely on manufacturer-recommended operating 

parameters.

Comment: One commenter (4266) notes that §63.773(d)(1)(iii) requires that the owner or 

operator conduct CPMS equipment performance checks, system accuracy audits, or other audit 

procedures specified in the site-specific monitoring plan at least once every 12 months. The 

commenter contends that the EPA should not stipulate a specific frequency for CPMS checks 

and audits. Rather, the commenter recommends that the appropriate frequency should depend on 

the monitoring parameters and equipment. The commenter recommends that the frequency of 

CPMS checks and audits will be documented in the site-specific monitoring plan, and supported 

by manufacturer recommendations.
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Response: The EPA maintains that performance checks and system accuracy audits be 

completed at least once every 12 months. These types of checks are necessary to ensure that 

monitoring systems are operating properly and accurately.

Comment: One commenter (4457) states that the EPA must also require continuous monitoring 

of glycol dehydrators. According to the commenter, the EPA proposes not to do so due to 

practical concerns for some facilities. The commenter suggests that the EPA could find a way to 

address those on a case-by-case basis, if they arise, rather than weakening the national rule for all 

sources.

Response: The final rule requires CPMS to be installed on all control devices, which by 

definition provide continuous monitoring.

3.5.3.8 Differences in Requirements for Small and Large Dehydrators

Comment: One commenter (4246) states that the control requirements are essentially identical 

for large and small dehydrators. The commenter recommends that there should be a more lenient 

standard for smaller units.

Another commenter (4104) states that rule requirements for small glycol dehydrators should be 

no more stringent than the analogous large glycol dehydrator rule requirement. For small 

dehydrators, the commenter recommends that the EPA should consider less rigorous 

requirements that properly consider relative impacts. The commenter adds that requirements that 

may warrant less rigor for small dehydrators include controls performance testing exemptions, 

monitoring exemptions for certain boilers, recordkeeping, and reporting.

Response: The EPA established the MACT standards for the small dehydrators in accordance 

with section 112(d)(2) and (3), which does not authorize the EPA to take into account the 

stringency of other standards and/or loosen the standards based on such comparison.

3.5.3.9 Information Submittal Using the Electronic Reporting Tool (ERT)

Comment: One commenter (4457) supports the requirement for electronic reporting of all initial 

and periodic test results and suggests that it is vital for the EPA to require prompt public 

reporting on the Internet of test results. One commenter (4457) supports the EPA’s proposal for 

electronic reporting as vital to strengthen the EPA, state, and citizen enforcement, and provide 

prompt information transparency for local communities near oil and gas facilities. As the public 

has a right to all collected reports under the CAA, the commenter states that the EPA must 

require immediate disclosure to the public on the Internet, without the need for any person to 

submit a FOIA request for such a report.
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One commenter (4266) believes electronic reporting should not be mandatory and should only be 

voluntary. Even with the ERT, the commenter contends that paper notification, test plans, and 

reports may still be required to satisfy individual state requirements. The commenter does not 

advocate duplicate effort and until state requirements for redundant reporting have been 

eliminated it is premature to consider mandatory electronic performance test reporting. The 

commenter states that the added burden for preparing and inputting data into the ERT is 

cumbersome and the cost has not been adequately addressed.

Response: 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 ERT. 

Please see sections VIII.C and IX.G of the preamble for further discussion of the ERT.

3.5.3.10 Miscellaneous Comments

Comment: Two commenters (4192, 4246) refer to §63.765 which reads: “(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.” According

to the commenters, the equation to calculate the BTEX emission limit cannot be used until data 

is available, which in turn requires the unit to be operated for a period of time before the 

emission limit is established. The commenters believe this is a backward approach that is likely 

to lead to non-compliance in certain cases. The commenters state that the EPA should provide a 

way of determining an emission limit prior to operation, or waive non-compliance during the 

operating period used to establish the BTEX emission limit. The commenters state that control 

requirements are essentially the same for large dehydrators and small dehydrators. According to 

the commenters, there should be an advantage to being a smaller unit. Also, the commenters state 

that as the gas gets leaner, it becomes more difficult for a unit to meet the 95 percent standard.

Response: We disagree that a period is required to excuse or waive non-compliance while data 

is collected on actual operation of the unit. Prior to operation of the unit, the owner or operator 

should have information regarding expected BTEX inlet and throughput to calculate the emission 

limit.

Comment: One commenter (4104) requests that the EPA confirm or clarify their interpretation 

of §63.1281(d)(1)(i). 

 Operators may comply with the requirements to reduce HAP emissions in accordance 

with §63.1281(d)(1)(i)(A) or (B) or (C) or (D).
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 Operators that comply with the requirement to reduce HAP emissions in accordance with 

§63.1281(d)(1)(i)(C) are only required to conduct an initial performance test that 

demonstrates that the combustion zone profile has a minimum temperature of 760°C. 

One commenter (4104) notes that operators that comply with the requirements to reduce HAP 

emissions in accordance with §63.1281(d)(1)(i)(D) are not required to conduct a performance 

test because this compliance option is an operating standard and does not have a numerical 

component. The commenter states that §63.1281(f)(1)(i) provides requirements for enclosed 

combustion control devices for small glycol dehydration units, and is restrictive because it lacks 

compliance options parallel to §63.1281(d)(1)(i) (C) and (D).

According to the commenter (4104), confusion results from the failure to define how to 

demonstrate “a uniform combustion zone temperature.” The commenter states that a minimum 

temperature target measured at a representative location is all that should be required. Therefore, 

the commenter suggests adding the initial performance testing requirements in 

§63.1282(d)(3)(vii) to investigate combustion zone temperature and provides suggested 

regulatory text.

Response: The commenter is incorrect. Section 63.1281(d)(1)(i)(D) is a clarification of A, B or 

C, not a standalone requirement. Concerning §63.1281(d)(1)(i)(C), the owner or operator must 

perform an initial performance test to determine the performance (control efficiency) of the 

control device at a combustion zone temperature of at least 760°C and must be using the 

combustion zone temperature as an indicator of control efficiency. In other words, the owner op 

operator must verify the control efficiency achieved at the desired combustion zone temperature 

before that combustion zone temperature can be used as an indicator of control efficiency. 

Additionally, in order to use combustion zone temperature as an indicator of control efficiency, 

the combustion zone temperature must be at least 760°C.

Concerning the use of “uniform combustion zone temperature,” we agree with the commenter. 

This section now specifies a minimum temperature rather than a uniform temperature. We made 

similar changes to §63.1282(e)(3)(vi)(B)(2).

Comment: One commenter (4266) requests that compliance options parallel to options 

§63.771(d)(1)(i) (C) and (D) and appropriate for small dehydrators be added to §63.771(f)(1)(i).

Response: The compliance options of §63.771(d)(1)(i)(C) and (D) are equivalent to 95 percent 

control. Under §63.771(f)(1)(i), the source may have to perform at a higher control efficiency 

than 95 percent to comply with the applicable BTEX limit. Therefore, the combustion zone 

temperature monitoring option is not appropriate for source complying with §63.771(f)(1)(i).
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Comment: Several commenters (4192, 4219, 4246) urge the EPA to ensure that the use of GRIGLYCalcTM or other approved models/process simulators is allowed in order to meet the control 

requirements for dehydrators contained in subparts HH and HHH. The commenters contends that 

such methods tend to be relatively inexpensive and they have been commissioned and approved 

by the EPA in the past.

One commenter (4263) states that the EPA should revise §63.772(b)(2)(i) and §63.1282(a)(2)(i) 

to allow for the use of ProMax® , AspenTech HYSYS®, or other process simulation software 

programs for estimating vent emissions from glycol dehydration units. The commenter provides 

suggested regulatory text. The commenter notes that subpart W of the Greenhouse Gas Reporting 

Rule, §98.233, provides for the use of process simulation computer programs in calculating 

emissions from glycol dehydration unit process vents, sweetening units and tanks. The 

commenter states that subpart W specifically lists AspenTech HYSYS® as an example of a 

program that may be used. The commenter adds that ProMax®, currently version 3.2, is also 

commonly used by both regulatory authorities and industry in calculating emissions from oil and 

gas industry equipment, including dehydrators, tanks and sweetening units. The commenter notes 

that results of process simulations using PROSIM, the predecessor of ProMax®, compared very 

favorably with measured emissions, as reported by the American Petroleum Institute.

Response: We are not making any changes to the final rule based on these comments. The EPA 

completed a study40 that indicated there was an acceptable correlation between stack test results 

and emissions calculated using GRI-GLYCalcTM such that these calculations could be used for 

CAA emissions determinations. We have no such information on the other models suggested by 

the commenter. 

Comment: One commenter (4263) states that the EPA should revise §63.772(d)(2) to reference 

paragraph (b)(2) for the GRI-GLYCalcTM procedure (i.e., remove redundancy), clarify that GRIGLYCalc should be the primary alternative and make technical corrections. The commenter also 

states that the EPA should revise §63.1282(c)(2) to reference paragraph (a)(2) for the GRIGLYCalc procedure. The commenter provided suggested regulatory text. The commenter 

clarified that this is because uncontrolled emissions from the still vent of a glycol dehydration 

unit are comprised primarily of water vapor with smaller fractions of BTEX and other 

hydrocarbons. According to the commenter, the water vapor in the still vent stream interferes 

with traditional Method 18 sampling and analytical methods, which is the reason GRI-GLYCalc 

is commonly accepted for quantifying emissions from glycol dehydration unit process vents. The 

 

40 Memorandum from Jones, Larry G., U.S. EPA, to Mobley, J. David, U.S. EPA, Glycol 

Dehydrator Emissions Test Report and Emissions Estimation Methodology. April 13, 1995. 

Docket ID No. EPA-HQ-OAR-2004-0383-0034.
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commenter stated that most, if not all, owners and operators of small (and large) glycol

dehydration units will choose GRI-GLYCalcTM for calculating emissions. 

One commenter (4263) adds that direct measurement may be an alternative, but the traditional 

methods for measuring volumetric flow rate and mass emissions of BTEX from still vents 

(Methods 1 through 4 and 18) will present challenges in obtaining accurate results, given the 

water content and very small diameter of the vent pipe. Also, the commenter stated that if 

Method 18 is used, the water fraction of the sample will have to be condensed and analyzed 

separately. The commenter stated that the GRI-GLYCalcTM alternative should be listed as the 

primary alternative, consistent with paragraph (b)(2) of §63.772. Also, the commenter added that 

the last sentence of the proposed §63.772(d)(2)(iii) should be removed. When BTEX mass 

emissions are determined using GRI-GLYCalcTM, according to the commenter it is not necessary 

or required to conduct Method 18.

Response: We do not believe any changes are necessary based on this comment. The GRIGLYCalcTM option is clearly stated and we believe it would serve no useful purpose to move it to 

the first option, regardless of whether the commenter believes it would be the most chosen 

option. Concerning the comment on conducting a Method 18 analysis, the commenter has 

misread this section. We are requiring only that the GRI-GLYCalcTM data for the HAPs listed in 

Method 18 be summed, not that a Method 18 test has to be performed. 

Comment: One commenter (4266) notes that in §63.772(e)(3)(iii)(B)(4) the proposed rule refers 

to using GRI-GLYCalcTM 3.0 or higher for determining the mass emission rate of TOC and HAP 

at the inlet to a control device. The commenter believes this is confusing because it refers to 

GRI-GLYCalcTM 3.0 or higher but then later in the same paragraph it refers to EPA Methods 18 

and 25A, which of course are testing methods. The commenter also requests that 

§63.772(e)(3)(iii)(B)(4) be modified to clearly allow use of GRI-GlyCalcTM to determine the 

mass emission rate of TOC and HAP at the inlet to a control device.

Response: The section referred to by the commenter was not part of the proposed changes; 

therefore, we cannot make changes to it in this final action. However, we clarify for the 

commenter that the referenced section does indeed state that GRI-GLYCalcTM can be used to 

determine the emissions at the inlet to the control device. Also, as stated in the response to the 

previous comment, this section does not require a Method 18 or 25A test.

Comment: One commenter (4266) states that the test protocols, requirements, and 

methodologies specified in the rule are unnecessarily complex, likely not technically achievable 

in certain instances, and unnecessarily costly. The commenter states that the EPA should redraft 

the performance testing and continuous compliance monitoring requirements of the rule to: 

simplify requirements, include only requirements appropriate for the large number and type of 
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dispersed small sources which would be subject to the rule, reduce the extensive cross 

referencing in the testing and monitoring requirements to reduce the confusing nature of the 

proposed rule and lessen the chance that the confusing construction of the rule will inadvertently 

lead to non-compliance incidents through misunderstanding, and reduce the unnecessary 

economic burden.

The commenter (4266) states that they are not attempting to provide a full “mark-up” of the 

current proposed rule language due to the confusing complexity and extensive cross-referenced 

manner of its current construction. The commenter would be willing to draft, or work with the 

EPA to draft, replacement testing and monitoring requirements and rule text. The commenter 

asserts that the replacement requirements must be appropriate for the large number of dispersed 

small sources subject to the rule with the rule text constructed in a straight forward and nonconfusing manner with minimization of the use of cross-references. The commenter believes it is 

likely that cooperating on this issue will yield better results in a quicker time period.

Response: Since we proposed changes to only portions of this section of the rule, we cannot now 

revise the entire section. Therefore, we are unable to make any further changes at this time.

Comment: One commenter (4104) notes that §63.1282(a)(2)(ii) requires the determination of a 

mass emission rate of benzene or BTEX, but only references EPA Method 18, which determines 

concentration of these species. The commenter notes that EPA Method 1 and EPA Method 2, in 

addition to EPA Method 18, are required to measure mass emission rates. The commenter 

recommends that the rule should be reviewed for complete and accurate references to required 

test methods and appropriate engineering units (e.g., units for emission rate or concentration).

Response: The EPA agrees with the commenter and will revise the rule language to reflect this 

comment.

Comment: One commenter (4266) states that the EPA should eliminate the requirements for 

measurement of inlet flow to an enclosed combustion device and outlet flow from an enclosed 

combustion device, as per §63.772(e)(3)(i)(A), or outlet flow from an enclosed combustion 

device, as per §63.772(e)(3)(i)(A). The commenter believes that these measurements are 

unnecessary to accurately determine destruction and removal efficiency (DRE) for the control 

device.

The commenter (4266) adds that requiring Method 2, 2A, 2C, or 2D to determine volumetric 

inlet flow is not appropriate and likely not technically feasible for accurate measurement. The 

commenter clarifies that a waste gas inlet stream to an enclosed combustion device being used 

for control for either a storage tank or a small or large dehydrator will be a low pressure 

(essentially atmospheric) low flow stream with very low velocity which is almost impossible to 
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measure accurately using the specified methods. Rather than attempting to measure such a 

stream, the commenter states that the EPA should specify the use of E&P TANK or a process 

simulation model such as ProSim or HySys to determine the inlet flow and composition of a 

waste gas stream routed to an enclosed combustion device from a storage tank and GRIGlyCalcTM 3.0 or higher dehydrator model or a process simulation model such as ProSim or 

HySys to determine the inlet flow and composition of a waste gas stream routed to an enclosed 

combustion device from either a small or large dehydrator. The commenter explains that 

problems with attempting to measure such a stream are more completely described in 

Attachment H of the comment letter. The commenter notes that the outlet flow from a typical 

enclosed combustion device has the same low pressure, low velocity, and difficulty for 

measurement issues as the waste gas inlet. If the EPA insists on a mass balance approach rather 

than the much simpler and accurate carbon balance approach, the commenter recommends the 

rule enable the use of Method 2B to calculate outlet flow for the combustion device using the 

model output information discussed above to calculate inlet flow and composition to the 

combustion device.

Another commenter (4104) notes that §63.1282(e)(3) states: “For inlet gas flow rate, compliance 

with the operating parameter limit is achieved when the value is equal to or less than the value 

established under §63.1282(h).” However, the commenter points out that §63.1282(h) only 

applies to manufacturer performance tested combustion control devices and would not apply to 

dehydrators that are not equipped with manufacturer performance tested combustion control 

devices. One commenter (4266) makes the same comment with respect to §63.772(f)(3) and 

§63.772(h).

Response: In response to the comments, subparts HH and HHH have been revised to allow the 

inlet flow gas rate to be calculated rather than measured.

Comment: One commenter (4263) states that the EPA should replace the term "fuel" with inlet 

gas in several paragraphs in §63.772 (h)(4), including (h)(4)(i), (h)(4)(iii), (h)(4)(iii)(A) and 

(h)(4)(iii)(B) and in several paragraphs in §63.1282 (g)(4)(i), (g)(4)(iii), (g)(4)(iii)(A) and 

(g)(4)(iii)(B) because fuel gas and inlet gas flow to a combustion control device are different 

parameters. 

Response: The EPA agrees that fuel gas and inlet gas flow to a combustion control device are 

different. The EPA has revised the final rule as appropriate where fuel gas should be renamed to 

inlet gas.

Comment: One commenter (4263) states that the EPA should delete §63.772(h)(4)(iii)(B)(3) 

and consider deleting §63.772(h)(4)(iii)(B) altogether. The commenter adds that the EPA should 

also delete §63.1282(g)(4)(iii)(B)(3) and consider deleting paragraph §63.1282(g)(4)(iii)(B) 
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altogether. The commenter explains that §63.772(h)(2) and §63.1282(g)(2) provide that 

"[p]ropene (propylene) gas shall be used for the testing fuel." The commenter states that it is not 

necessary therefore to analyze the inlet gas for benzene and sulfur compounds. Also, the 

commenter states that the EPA has not proposed performance standards related to the 

composition of the inlet gas, so the analysis of the inlet gas is not useful, other than to 

demonstrate that propylene was used.

The commenter (4263) states that the EPA should delete §63.772(h)(5)(i) and (ii) and correct 

paragraph numbers, and also delete §63.1282(g)(5)(i) and (ii) and correct paragraph numbers. 

The commenter explains that the determination of the volumetric flowrate from the combustion 

control device outlet using the methods referenced or described in paragraphs (g)(5)(i) and (ii) is 

not relevant to a demonstration that such a device achieves the performance requirements in 

(g)(7), which is based on outlet pollutant concentrations. The commenter contends that exhaust 

volumetric flowrate determinations are only relevant to mass emissions calculations.

Response: The EPA agrees that benzene and sulfur compound analysis is not a necessary part of 

the manufacturer’s performance test and has removed those requirements from the final rule. We 

have also reduced the number of inlet fuel samples necessary for the certification testing to 

reduce the cost burden for manufacturers. The EPA is interested in mass emissions measurement 

from these devices as well as concentration based destruction efficiency measurement.

Comment: One commenter (4104) notes that the proposed rule revisions add ASTM D6420–99 

(2004) as an optional method for measuring BTEX emissions from small glycol dehydrators. The 

commenter states that it is not apparent that ASTM D6420–99 (2004) can be used for 

measurements on large glycol dehydrators.

Another commenter (4266) states that is not apparent that ASTM D6420–99 (2004) can be used 

for HAP measurements. The commenter states that the rule should clarify that ASTM D6420–99 

(2004) is applicable for measuring benzene, BTEX, or total HAP emissions from any affected 

source, and it should be clearly indicated that this method provides an alternative to other 

allowed methods in the rule – i.e., Method 18 in 40 CFR part 60, appendix A and any other 

method or data that have been validated according to the applicable procedures in Method 301, 

40 CFR part 63, appendix A.

Response: We have made revisions to the final rules to clarify that ASTM D6420–99 (2004) can 

be used for measuring any HAP compounds from any affected source as an alternative to 

Method 18 or other method validated according to Method 301.

Comment: One commenter (4230) quotes the EPA regarding the statement that "... HAP 

emissions can increase despite decreases in natural gas throughput due to the change in gas 
330

composition" and responds to the EPA’s request for comment regarding the likelihood of this 

occurrence and the data demonstrating the circumstances where it occurs. The commenter 

tabulated a number of wet gas analyses supplied by various companies over the last few years 

and has enclosed this data as Table 1 of the comment letter. The commenter states that the effect 

on emissions was noted to be proportional to the wet gas composition as well as throughput, 

which is demonstrated by a sensitivity analysis enclosed as Table 2. The wet gas composition, 

according to the commenter, clearly changes over time as shown within the data supplied in 

Table 1. The commenter envisions that the BTEX composition within the wet gas is a function of 

well pressure and the dehydrator contactor pressure, or basically the pressure of the knockout pot 

prior to the contactor column. The commenter adds that since the wet gas is typically sampled 

after the knockout pot and prior to the contactor column, the higher pressure results in more 

BTEX components being removed within the knockout liquids and therefore less being sent to 

the contactor column. Additionally, the commenter states that from the perspective of the wells, 

the lower pressure wells, which are typically older wells, would have higher BTEX compositions 

in accordance with Raoult' s Law. According to the commenter, since the gathering lines 

introduce multiple factors such as new wells coming on line and old wells being depleted there is 

no way to predict the overall change of composition coming into the dehydration unit unless the 

stream is sampled periodically. The commenter recommends a requirement for periodic wet gas 

sampling at the point where the gas enters the TEG contactor column for all sources without 

controls.

The commenter (4230) requests guidance on whether new PTE calculations and major source 

determinations should be based on a single new wet gas composition analysis of BTEX 

compounds or an average, representative analyses (if available), and if so, over what timeframe. 

The commenter also asks whether a single new wet gas composition test leading to a major 

source PTE determination would result in a once-in, always-in major source determination, or 

could an average of BTEX results from multiple wet gas composition tests over the 3-year period 

before the major source compliance date be used. The commenter further inquires that, if an 

average can be used, and the resulting average across the 3 year period was less than major, 

would the source instead be considered minor. The commenter points out that subpart HH directs 

that GRI-GLYCalcTM be used to determine emissions from the dehydrator, including actual 

average benzene emissions. The wet gas composition data, according to the commenter, are used 

in the GRl-GLYCalcTM software in accordance with the procedures presented in the associated 

Technical Reference Manual. The commenter explains that inputs to the model must be 

representative of actual operating conditions of the glycol dehydration unit. The commenter 

states that ideally these inputs are annual average values, but site specific data may not be

available and in such cases estimates provided by the facility are instead used. However, the 

commenter believes the regulation also states that parameters used to determine major source 

status are to be based on either the highest measured values or an annual average. The 
331

commenter adds that while the regulatory language implies that enforcement discretion may be 

used, the timeframe over which this determination can be made is unclear.

One commenter (4230) asks whether facilities currently considered to be area sources, but not 

using controls, would also be required to periodically obtain new wet gas composition analysis in 

order to ensure that their past determinations are still accurate over time, and if so, what 

timeframe is recommended. While the wet gas composition is a dynamic property, the 

commenter states that the regulation does not directly require periodic monitoring of this 

property. In West Virginia the commenter states that their experience has been that a facility 

typically triggers area-becoming-major under subpart HH due to a change in the composition of 

the wet natural gas being sent through the dehydrator. The commenter explains that the BTEX 

composition changes over time due to natural variability in wells, varying pressures and levels in 

storage fields, different wells coming on-and-offline, etc. So while no new equipment is added, 

and there is no change in the maximum design throughput of the dehydrator, the commenter 

contends that the change in BTEX composition of the wet natural gas may significantly change 

the actual and potential emissions. Further, the commenter adds that even though the 

concentrations of BTEX compounds in the wet natural gas are very low, and fluctuations may 

appear to be small, the volume of throughput over the year amplifies the effect on actual and 

potential emissions of HAPs from the dehydrator.

One commenter (4039) states that the frequency of re-determining major or area status should be 

set at once per permit term. The commenter contends that this approach is not overlyburdensome for either the permitting agency or the permittee and allows the source to be 

evaluated and appropriately permitted at a set interval based on the results of the determination.

Two commenters (4192, 4246) note that the EPA seeks comment on whether to require 

confirmation that area sources are, in fact, area sources and whether verification calculations 

must be performed on an annual or biannual basis to confirm potential changes in gas 

composition have not resulted in an emissions increase. The commenters note that their members 

perform GRI-GLYCalcTM analysis annually to satisfy emission inventory requirements for larger 

facilities. The commenters support inlet gas sampling and analysis on the dehydration unit every 

2 years. The commenters add that it is not necessary for area sources having a federally 

enforceable permit limit to recalculate PTE already incorporated in the permit.

Response: We have reviewed the data provided by the commenter and agree that facility HAP 

emissions can increase due to inlet gas composition changes over time. We also agree that these 

changes in gas composition can occur independent of natural gas throughput. Therefore, sources 

that make an initial determination that they are an area source for HAP could later on experience 

an increase in emissions that would change its status to a major source. In response to the 

comment, we are adding regulatory text to §63.760(c) to require owners/operators of sources 
332

initially determined to be area sources to conduct determinations each year thereafter if their 

actual emissions exceed 50 percent of the major source threshold (i.e., 5 tons/year of a single 

HAP or 12.5 tons/year of total HAP). The 50 percent threshold is based on the data received 

from the commenter and our belief that sources initially determined to have actual emissions at 

or below 50 percent of the major source threshold (i.e., 10/25) are unlikely to exceed the 10/25 

threshold due to gas composition changes alone. In cases where sources make changes such as 

adding a well(s), or increasing natural gas throughput, they would be required to perform a new 

source determination under §63.10(b)(3) of the General Provisions which specifies the 

following:

. . . If an owner or operator determines that his or her stationary source that emits (or has 

the potential to emit, without considering controls) one or more hazardous air pollutants 

regulated by any standard established pursuant to section 112(d) or (f), and 

that stationary source is in the source category regulated by the relevant standard, but that 

source is not subject to the relevant standard (or other requirement established under this 

part) because of limitations on the source's potential to emit or an exclusion, the owner or 

operator must keep a record of the applicability determination on site at the source for a 

period of 5 years after the determination, or until the source changes its operations to 

become an affected source, whichever comes first. [emphasis added]

3.5.4 Startup, Shutdown and Malfunction

3.5.4.1 Elimination of the SSM Exemption in Subparts HH and HHH

Comment: Three commenters (4104, 4220, 4266) believe that the EPA’s revised SSM 

provisions are impractical, arbitrary and capricious.

Five commenters (4104, 4159, 4246, 4266, 4273) do not agree that the decision in Sierra Club v 

EPA requires the EPA to abolish SSM emissions exemptions from compliance with the 

NESHAP. 

One commenter (4266) asserts that the proposal to eliminate the SSM provisions in the two 

existing rules is not based on an accurate reading of Sierra Club, is not supported by any rational 

explanation as to why the elimination of the SSM provisions is justified, and is arbitrary and 

capricious given that the EPA fails to provide any analysis of why affected sources reasonably 

can be expected to meet the emissions limitations and standards that the Agency proposes to 

apply during periods of SSM. 

Two commenters (4159, 4246) argue that the court vacated the SSM provisions because they 

were based on the “general duty” clause rather than a continuously applicable section 112 
333

standard and that the EPA’s elimination of the SSM exemption is based on an overly-broad and 

incorrect reading of Sierra Club. Commenter 4159 provides case law and statute support for their 

position.

Commenters (4159, 4273) assert that in the SSM decision, the D.C. Circuit vacated the 

application of a “general duty” to minimize emissions during SSM periods for standards 

promulgated under section 112. 551 F.3d at 1027-28. The commenters state that it did so because 

it found that the general duty standard was not a "section 112-compliant" standard. Id (“Because 

the general duty is the only standard that applies during SSM events-and accordingly no section 

112 standard governs these events-the SSM exemption violates the CAA's requirement that some 

section 112 standard apply continuously.”). The commenters argue that the D.C. Circuit did not 

hold that the EPA must apply the same standard for normal operations during SSM periods. In 

fact, according to the commenters, the Court expressly rejected that contention. Id. at 1027 

(“section 302(k)'s inclusion of this broad phrase in the definition of 'emission standard' suggests

that emissions reduction requirements ‘assure continuous emission reduction’ without 

necessarily continuously applying a single standard.”). The commenters state that the EPA has 

not established that the standards for SSM periods are “section 112-compliant,” and, therefore, 

the SSM decision cannot support its proposed actions to remove the SSM provisions for MACT 

standards. 

According to commenters (4104, 4266), the EPA’s proposal “that the standards in these rules 

apply at all times” is not, as the EPA claims, “[c]onsistent with Sierra Club v. EPA.” The 

commenter opines that the decision in that case was grounded in the court’s assertion that section 

112 requires emissions standards to apply at all times. Sierra Club at 1027 (“Congress has 

required that there must be continuous section 112-compliant standards.”). According to the 

commenters, based on this, the court held that the SSM General Provisions do not comport with 

section 112 because, in the eyes of the court, the SSM provisions are not “section 112-

compliant” emissions standards. Id. at 1028 (“Because the general duty is the only standard that 

applies during SSM events — and accordingly no section 112 standard governs these events —

the SSM exemption violates the CAA's requirement that some section 112 standard apply 

continuously.”). The commenters assert that the court did not hold that the EPA is prohibited 

from setting separate standards for periods of SSM. According to the commenters, it simply held 

that standards for such periods must be developed according to the section 112(d) MACT 

process.

One commenter (4104) argues that the Sierra Club decision simply requires the EPA to establish 

some standard(s) under section 112 that will apply during all facets of a facility’s operation –

whether that be an emission standard under section 112(d), or a work-practice standard under 

section 112(h). According to the commenter, it did not, however, overrule the significant preexisting case law that controls how these standards must be developed. Accordingly, the 

commenter believes that the EPA must establish standards for the 1-2 percent of operational 
334

periods that were excluded when the MACT standard was developed; those periods when even 

well-managed technology cannot achieve the mandated control levels. 

Thus, according to the commenters (4104, 4266), the proposal to eliminate the SSM provisions 

from the two source categories (in subparts HH and HHH) subject to this proposal is not 

“consistent” with Sierra Club because there is nothing in that case that supports the conclusion 

that vacatur of the part 63 General Provisions necessarily requires “the established standards in 

these rules [to] apply at all times.” The commenters opine that the EPA’s flawed legal analysis 

provides no support for the proposal to eliminate the SSM provisions in the two rules.

Two commenters (4266, 4273) assert that the EPA is obligated to set standards that are 

“achievable” under section 112(d)(2) of the CAA. 

One commenter (4104) argues that it is axiomatic that limitations based on “demonstrated” or 

“achievable” technology must be attainable with the EPA-designated model MACT technology. 

According to the commenter, by its very terms, the CAA requires that the EPA establish 

emission limits that are “achievable” through the application of MACT-level technology. CAA 

§112(d)(2). According to the commenter, limitations based on MACT must be achievable by the 

technology that the EPA has designated as MACT. See Portland Cement Assoc. v. Ruckelshaus, 

486 F.2d 375, 402 (D.C. Cir. 1973) (“the [Clean Air Act] expressly requires, for the standards 

[the Administrator] promulgates, that technology be achievable”); Marathon Oil Co. v. EPA, 564 

Fed.2d 1253, 1272-73 (9th Cir. 1977) (remanding permits to the EPA because they required 

permittees to meet the standards 100 percent of the time but the permittees could only be 

expected to achieve the standards 97.5 percent to 99 percent of the time with the best practicable 

control technology currently available); FMC Corp. v. Train, 539 F.2d 973, 986 (4th Cir 1976) 

(remanding effluent limitations to the EPA because a properly operating treatment facility could 

be in violation of those limitations on a few occasions).

According to one commenter (4104), the EPA has two viable alternatives for managing those 

periods when even well-operated MACT technology cannot achieve the same emissions as 

during normal, routine operations: (1) it may establish emission standards high enough that the 

reference technology can achieve the standard at all times, even during SSM; or (2) it may set the 

standard at a level that the reference technology can achieve most of the time, and then provide 

an exemption – or alternate standard, per Sierra Club – for those periods in which even a welloperated system cannot achieve the standard. The commenter asserts that, historically, the EPA 

here has chosen the latter approach. 76 FR at 52766. 

According to the commenter, under the proposed subparts HH and HHH NESHAPs, the EPA has 

specifically deleted the exemption for startup and shutdown periods. According to the 

commenter, the EPA bases this conclusion on its belief that the affected equipment can comply 
335

with the relevant standards at all times and under all foreseeable operating conditions, including 

startup and shutdown. See 76 FR at 52766, 52787. The commenter opines that this conclusion is 

incorrect. For example, the commenter states, catalytic incinerators are an allowed control device 

under subparts HH and HHH. During startup, the commenter reports that time will elapse before 

the minimum temperature needed for adequate performance is achieved, and the EPA has not 

considered or evaluated the implications. 

According to the commenter (4104), if the EPA is going to base the regulatory standards on an 

emissions level that MACT technology can achieve only 98-99 percent of the time, the Agency 

must also provide an adequate exemption for the other 1-2 percent of the time, when MACTlevel technology cannot comply.

At the outset, the commenter (4104) provides that non-standard operating conditions involve two 

separate types of events: those that can be foreseen and planned for (e.g., startup and shutdown); 

and those that cannot be foreseen and planned for (e.g., malfunctions). The commenter provides 

that foreseeable events are those events where there are foreseeable operating periods when they 

cannot achieve the same emissions limits as under “normal” operations. For example, the 

commenter states that, a boiler cannot achieve its typical high destruction efficiency until it 

reaches full operating temperature. Similarly, the commenter states that a batch process unit may 

generate emissions at varying rates across its entire operating cycle. The commenter provides 

that the EPA has historically recognized these kinds of foreseeable operating scenarios in a 

number of ways. According to the commenter, to address the situation posed by the boiler, the 

Agency has historically exempted startup and shutdown periods from compliance with emission 

standards. Alternatively, the commenter states, for emissions that vary over a process cycle, the 

EPA may set the emissions rate at the highest level emitted across the cycle, or set an averaging 

time that reflects operations across the entire cycle. According to the commenter, under the 

proposed rules for subpart HH and HHH, the EPA has entirely deleted the startup and shutdown 

exemption. The commenter believes that this leaves owners and operators in an untenable 

situation, in which it will be foreseeable that emissions limits exceedances will occur (and thus 

violations will be found) even though owners and operators are using practices that comply with 

MACT standards.

Response: The EPA disagrees with commenters that state that the EPA’s proposed approach of 

not providing an exemption for the 1-2 percent of the time when even well-managed MACT 

technology will not be able to comply does not comport with the CAA. 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) (emissions 

limitations under CAA section 112 must both continuously apply and meet section 112’s 
336

minimum stringency requirements, even during periods of SSM). Thus, the EPA is required to 

ensure that section 112 emissions limitations are continuous. 

The commenters state that the court vacated the SSM provisions because they were based on the 

“general duty” clause rather than a continuously applicable section 112 standard. The EPA 

agrees that the court found that the “general duty” was not a 112-compliant standard. The EPA 

does not claim that the Sierra Club case constrains its authority to prescribe different standards 

for periods of start and shutdown or for periods of malfunction. However, as explained in the 

preamble to the proposed and final rules, the EPA has determined that section 112 does not 

require that emissions that occur during periods of malfunction be factored into development of 

section 112 standards. The EPA’s rationale for this view is explained in detail in the preamble as 

well. 

With respect to periods of startup and shutdown, the EPA agrees that in some circumstances 

separate standards for such periods may be appropriate. However as explained in the preamble to 

the final rule, “the EPA has taken into account startup and shutdown periods and expects that 

sources will be able to meet emission limits during such periods. We believe that operations and 

emissions do not differ from normal operations during these periods such that it warrants a 

separate standard.” 76 FR 52738, 52787 (Aug. 23, 2011) 

The EPA agrees with the commenter that catalytic oxidizers require a period of time to reach 

optimal operating temperature. While the commenter did not specify a specific warm-up period, 

we believe that normal operating temperature is met in approximately 30-45 minutes. Since 

compliance is determined based on the 24 hour average combustion zone temperature, meeting 

the required compliance temperature should be achievable with a properly functioning device. 

For malfunctions, the EPA recognizes that even equipment that is properly designed and 

maintained can sometimes fail and that such failure can cause a violation of an emission 

standard, but does not agree with commenters that argue that the EPA’s approach to 

malfunctions is flawed. As discussed in the preamble to the final rule, the relevance of the cases 

such as Portland Cement is called into question in light of subsequent case law and the 1977 

amendments to the CAA’s definition of emission standard requiring that such standards be 

continuous. In any event, even if those cases are relevant, as also explained in the preamble to 

the final rule, the EPA‘s overall approach to malfunction events in this rule, including the 

promulgation of an affirmative defense, is consistent with the approach set forth in EPA‘s 1972 

proposed rules cited favorably in Portland Cement in that both the EPA’s approach today and in 

1972 ―impart a construction of "reasonableness" to the standards as a whole and adopts a more 

flexible system of regulation than can be had by a system devoid of "give." Portland Cement at 

399. Portland Cement criticized the EPA regulations that contained no specific provisions to 

address malfunctions and the EPA‘s assertion that malfunctions would be dealt with by the 
337

informal exercise of discretion in the Agency‘s enforcement activities. Those decisions did not 

require exemptions or less stringent standards for malfunction events as the commenter suggests. 

The EPA‘s approach to malfunctions goes further than reliance on the informal exercise of 

enforcement discretion in that it includes regulatory provisions establishing an affirmative 

defense to civil penalties for exceedances of emission limits that are caused by malfunctions. The 

court in Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272 (9th Cir. 1977) held that the EPA must 

formalize its approach to upsets under the Clean Water Act. The affirmative defense does so. 

See, Mont. Sulphur & Chem. Co. v. United States EPA, 2012 U.S. App. LEXIS 1056 (5th Cir. Jan 

19, 2012) (in rejecting industry argument based on Marathon Oil that reliance on the affirmative 

defense was not adequate, court stated “[h]owever, here the EPA does not rely on enforcement 

discretion alone, but specifically promulgates an affirmative defense in the FIP, which clearly 

defines the requirements to avoid penalties.”). But see, Weyerhaeuser v Costle, 590 F.2d 1011, 

1057-58 (D.C. Cir. 1978) (holding that an informal approach is adequate). In fact, the affirmative 

defense comports with the court‘s suggestion in Marathon Oil that the EPA place the burden on 

the permit holder of producing the relevant data and proving that the upset could not have been 

prevented. Id.

Comment: For MACT standards, two commenters (4159, 4273), state that the EPA’s proposed 

revisions to SSM provisions violate the CAA procedural requirements. According to the 

commenters, section 307(d) requires the EPA to provide the public a meaningful opportunity to 

comment on a proposed rulemaking. 42 U.S.C. section 7607(d)(3), (5); see also Kennecott Corp. 

v. EPA, 684 F.2d 1007, 1018-19 (D.C. Cir. 1982). The commenters state that part and parcel of 

this requirement is the EPA’s obligation to provide a statement of basis for its proposed rule. 42 

U.S.C. §7607(d)(3). The commenters argue that the statement of basis must include: (a) the 

factual data on which the proposed rule is based; (b) the methodology used in obtaining the data 

and in analyzing the data; and (c) the major legal interpretations and policy considerations 

underlying the proposed rule. Id. The commenters assert that the EPA’s only purported legal 

basis for these revisions is to make the SSM provisions “[c]onsistent with Sierra Club v. EPA” 

(also referred to as the “SSM Decision”). 76 Fed. Reg. at 52,747. But, according to the 

commenters, the EPA fails to explain how application of the standards for normal operations to 

SSM otherwise meets the requirements of section 112. In addition, the commenters assert that 

the EPA provides no factual support for its proposed changes. As such, the commenter believes 

that the EPA’s proposed rule fails to meet the procedural requirements of the Clean Air Act, and 

the public cannot meaningfully comment on the legal or factual bases for its proposed SSM 

provisions.

Response: The EPA discussed its rationale for its approach to periods of startup and shutdown 

and for its approach to malfunctions in the preamble to the proposed rule at 76 FR 52787 and has 

thus provided commenters with a reasonable opportunity to comment on that rationale. The EPA 

relies on Sierra Club for the elimination of the SSM exemption, not for its decision to require 
338

that during periods of startup and shutdown and during periods of malfunction, sources must 

meet the standards that apply during normal operations. The EPA’s rationale for the standards 

that it set for periods of startup and shutdown and for periods of malfunction is also discussed in 

the preamble for the proposed rule and in the preamble to the final rule.

Comment: One commenter (4104) states that, by the EPA failing to provide an exemption for 

the 1-2 percent of operating modes that cannot meet the standard, the EPA violates not only the 

CAA language, but also the industry members’ constitutional rights to due process, by subjecting 

them to penalties, and even incarceration, for (i) failing to comply with an unattainable standard; 

and (ii) engaging in conduct that the CAA expressly makes legal. The commenter asserts that a 

law that requires an individual to do the impossible leaves an individual no choice but to violate 

the law; because individuals must be given the opportunity to conform their conduct to the law, 

such a law violates due process. See Grayned v. City of Rockford, 408 U.S. 104, 108 (1972) 

(vague laws violate due process in part because they fail to provide individuals a choice of 

whether to obey); Portland Cement Ass’n v. Ruckelshaus, 468 F.2d 375, 398 n.91 (D.C. Cir. 

1973) (“Companies must be on notice as to what will constitute a violation.”); United States v. 

Dalton, 960 F.2d 121. 122-23 (10th Cir. 1992) (individual cannot be convicted for having 

unregistered machine gun when there is no available mechanism for registering machine guns). 

Furthermore, according to the commenter, subjecting affected sources to sanctions for doing that 

which the Act expressly makes legal – continuing to operate their facilities using properlymanaged MACT-level controls – would also violate due process. “To punish a person because he 

has done what the law plainly allows him to do is a due process violation of the most basic sort.” 

United States v. Goodwin, 457 U.S. 368, 372 (1982) (internal quotations omitted). 

Response: The EPA does not agree that failure to provide an exemption violates due process. 

The commenter cites to cases addressing vague laws, yet does not explain or even argue that the 

standards are vague. Further, as the EPA explains above, the EPA’s approach to malfunction 

events is consistent with Portland Cement. United States v Dalton addressed an argument that 

compliance was a legal impossibility and is thus distinguishable from the commenter’s argument 

that it may be technologically infeasible to comply with standards at certain times. The EPA’s 

approach for handling such circumstances is explained at length in the preamble and elsewhere 

in this response to comment document and is reasonable. In any enforcement action, sources that 

truly could not have complied with the standard despite best efforts will have an opportunity to 

assert an affirmative defense to penalties and such opportunity provides due process. In addition, 

if penalty assessment occurs, the EPA and courts consider good faith efforts to comply in 

assessing penalties under section 113(e) of the CAA.

Comment: According to one commenter (4266), the EPA has made no effort to obtain emissions 

information from the two source categories subject to 40 CFR part 63 subparts HH and HHH for 

periods of SSM and provides no other evidence or analysis supporting its assertion that it is 
339

appropriate to apply the existing standards to periods of SSM. Additionally, the commenter 

asserts that the EPA failed to investigate the record data developed during the promulgation of 

the existing standards to assess whether those data are characteristic and representative of 

emissions during periods of SSM. In short, according to the commenter, the EPA simply asserts, 

with no record basis, that the existing standards should apply to periods of SSM. The commenter 

argues that this unsupported assertion provides no basis for extending the existing standards to 

periods of SSM and is therefore facially arbitrary and capricious and provides inadequate support 

for the proposal.

Response: As noted in the proposal preamble, we took into account startup and shutdown 

periods. We believe that the expected startup and shutdown emissions over the averaging periods 

established for the NESHAP are not likely to cause a violation of the standards. We also found 

no evidence that suggested that emissions were higher during startup or shutdown that would 

indicate a need for an alternate standard for these periods and the commenter provided no data or 

basis to show that sources cannot comply with the standards as proposed. Thus we set standards 

based on available information as contemplated by section 112. 

As for malfunctions, as explained in the proposed and final rules preambles, the EPA has 

determined that CAA section 112 does not require that emissions that occur during periods of 

malfunction be factored into development of CAA section 112 standards. As the EPA further 

explained, accounting for malfunctions 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. 

Comment: One commenter (4104) states that the MACT floor for subpart HHH does not 

account for emission deviations during SSM events. According to the commenter, since SSM 

provisions are being rescinded, this issue is relevant not only for the new standards for small 

dehydrators, but also for the large dehydrator standards (e.g., for units already subject to subpart 

HHH). The commenter states that, although the averaging time for compliance dampens 

concerns regarding startup and shutdown emissions, the EPA has an obligation to assess the 

implications from foreseeable events (e.g., inadequate temperature for a catalytic incinerator 

during startup) when developing standards. 

In summary, the commenter (4104) does not believe that the proposed standard is a reasonable 

estimate of the performance of the “best controlled similar unit” under the worst reasonably 

foreseeable circumstances. At a minimum, the commenter suggests that the EPA complete a 

series of GRI-GLYCalcTM model simulations to better assess emissions variability and obtain a 

more robust basis for including variability in the standard.
340

One commenter (4266) asserts that the EPA has failed to account for the costs of a standard that 

does not accommodate malfunctions. According to the commenter, to assure continuous 

compliance, affected facilities have only two choices – install redundant processing and pollution 

control equipment so that operations can continue during a malfunction, or shut down the 

affected facility until the malfunction can be rectified. The commenter states that, in either case, 

affected facilities would incur substantial costs directly attributable to the standard that have not 

been accounted for in the formulation of the rule. The commenter suggests that, for these 

reasons, the EPA should set aside the proposed affirmative defense for periods of malfunction 

and, instead, set a work practice standard for such periods. 

Response: The EPA’s rationale for its approach to malfunctions is discussed in the preamble to 

the proposed rule and this final action. As explained in the preamble, the EPA has determined 

that CAA section 112 does not require that emissions that occur during periods of malfunction be 

factored into development of CAA section 112 standards. We are likewise obligated to set 

standards at a level at least as stringent as the level achieved in practice by the best performing 

sources and costs are not considered in that determination. Further, the commenter does not 

provide support for its conclusion that to assure continuous compliance, sources must either 

install redundant processing and pollution control equipment or shut down the affected facility 

until the malfunction can be rectified. Different sources may employ different strategies to 

address a particular type of malfunction and there are a myriad of different types of malfunctions 

that can occur across all sources in the category.

Comment: One commenter (4273) argues that the D.C. Circuit ruling recognized that the EPA 

may utilize section 112(h) to support SSM-specific standards, which the EPA ignored. The 

commenter opines that the SSM decision indicates that the EPA may justify the general duty 

standard for SSM periods under the alternative provisions of section 112(h). Sierra Club, 551 

F.3d at 1028. 

One commenter (4266) acknowledges (as the EPA has) that it is not feasible to develop an 

emission standard that governs malfunction periods. The commenter provides that section 112(h) 

of the CAA allows the EPA to set work practice standards for situations where “it is not feasible 

in the judgment of the Administrator to prescribe or enforce an emission standard . . .” 

According to the commenter, malfunctions fit within the situations described in the definition of 

“not feasible to prescribe or enforce an emission standard” as any situation where “the 

application of measurement methodology to a particular class of sources is not practicable due to 

technological and economic limitations.” Consequently, the commenter recommends that the 

EPA set work practice requirements to address periods of malfunction. The commenter believes 

that the steps set forth in §63.762(d)(1)(i)-(ix) would constitute an appropriate work practice 

standard for malfunctions, in which case the commenter believes that the notifications specified 

in §63.762(d)(2) should be replaced by a semi-annual reporting requirement. 
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One commenter (3469) recommends that the EPA follow the SSM approach that is used in the 

final NESHAP for Major Sources: Industrial, Commercial, and Institutional Boilers and Process 

Heaters (ICI Boiler MACT); namely, that work practice standards apply during periods of startup 

and shutdown to minimize air pollution emissions, while malfunctions would not be considered a 

distinct operating mode. The commenter reports that, in the ICI Boiler rule, the EPA determined 

that it is not technically-feasible to monitor these periods of startup and shutdown and therefore 

established separate work practice standards for periods of startup and shutdown. The

commenter furthers states that, in the ICI Boiler rule, the EPA requires operators to follow 

manufacturers' specifications for minimizing periods of startup and shutdown. Specifically, the 

commenter states that §63.7530(h) requires that owners/operators of covered ICI boilers 

"minimize the unit's startup and shutdown periods following the manufacturer's recommended 

procedures, if available. The commenter suggests that, if manufacturer's recommended 

procedures are not available, recommended procedures for a unit of similar design for which 

manufacturer's recommended procedures are available must be followed. The commenter asserts 

that a signed statement in the Notification of Compliance Status report would be included that 

indicates startups and shutdowns were conducted according to the manufacturer's recommended 

procedures or procedures specified for a unit of similar design if manufacturer's recommended 

procedures are not available." The commenter believes a similar approach, which requires an 

affected piece of equipment to minimize periods of startup and shutdown and associated 

emissions, is appropriate for oil and gas equipment, recognizing that in most cases emissions will 

be below the applicable NESHAP standards by virtue of the lower emitting fuel. 

Response: The EPA, based upon a comprehensive review of the emission units affected by this 

NESHAP, has determined that there is no demonstrated need for alternate standards during 

startup and shutdown and expects that sources will be able to meet the emission limits during 

such periods. In comparison, in the major source ICI Boiler rule, the EPA determined that it was 

not practicable to apply measurement methodology due to technological and economic 

limitations during periods of startup and shutdown and, therefore, established separate work 

practice standards for these periods. The commenter did not indicate or provide support for the 

position that, for oil and gas equipment, it is not practicable to apply measurement methodology 

due to technological and economic limitations. Further, the operation of boilers falling under the 

major source ICI Boiler rule is not analogous to that of storage vessels and glycol dehydrators 

within the oil and natural gas NESHAP. Boilers are designed to combust various fuels and in 

doing so they destroy organic HAP. In fact, boilers are commonly used as control devices to 

reduce organic HAP. In contrast, neither storage vessels nor glycol dehydrators reduce organic 

HAP, they merely emit HAP, and, in most cases, an add-on control device is required to meet the 

HAP emission standard under the oil and natural gas NESHAP. The control devices employed in 

most cases are vapor recovery units (VRU), enclosed combustion devices and ambient air-cooled 

condensers. Therefore, the startup or shutdown of the emission source should not affect the 
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performance of the control device and is not an issue. Further, startup and shutdown of the 

control device should not be an issue. For a VRU or natural-draft-cooled condenser, the devices 

will perform at the necessary level (i.e., 95 percent) immediately upon startup. Enclosed 

combustion devices are typically units that receive gas from the emission units and combust the 

gas immediately when it contacts the pilot flame. Such devices are either on (i.e., the pilot is lit) 

or off. In the case where a catalytic thermal oxidizer is used as the enclosed combustion device, 

we believe the 24-hour averaging time is sufficient to allow compliance with the standards and 

we have addressed this in more detail elsewhere in this document. Thus, we do not believe that 

different standards are required for periods of startup or shutdown. In addition, no commenter 

provided enough specificity in their comments or emission data that established the need for an 

alternate standard during startup and shutdown.

The EPA does not agree that the Sierra Club decision addresses the question of whether the EPA 

may justify the general duty standard for SSM periods under the alternative provisions of section 

112(h). The decision merely noted that the EPA had not purported to act under section 112(h) in 

establishing the general duty standard.

The EPA’s rationale for its approach to malfunctions is discussed in the preambles to the 

proposed rule and this final action. As explained in those preambles, the EPA has determined 

that CAA section 112 does not require that emissions that occur during periods of malfunction be 

factored into development of CAA section 112 standards. As the EPA further explained, 

accounting for malfunctions would be difficult, if not impossible, given the myriad of 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. The EPA’s rationale for its approach to malfunctions is not based 

on the criteria that must be used to justify a finding that it is not feasible to prescribe or enforce 

an emission standard under section under section 112(h). Section 112 (h)(2) provides that such a 

finding must be based on a determination that “a hazardous air pollutant or pollutants cannot be 

emitted through a conveyance designed and constructed to emit or capture such pollutant, or that 

any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State 

or local law” or “the application of measurement methodology to a particular class of sources is 

not practicable due to technological and economic limitations.” Further, setting work practice 

standards under section 112 presents the same issues as setting numerical emission limits given 

the varied nature of malfunctions. In any event, the commenter has not provided information to 

support that the criteria of 112(h) have not been met.

3.5.4.2 Remove Provision Allowing Shutdown of Control Device During Maintenance or Repair

Comment: One commenter (4266) opines that the EPA should provide an allowance for a 

reasonable period of routine maintenance for the control device. The commenter asserts that 
343

proper operation of a control device includes periodic routine maintenance, and manufacturers of 

control devices typically recommend preventive maintenance on a semi-annual basis. According 

to the commenter, the EPA has stipulated in other rulemakings that standards do not apply during 

planned routine maintenance, other than a work practice standard that such periods shall not 

exceed 240 hours per year and records must be maintained to document such periods. The 

commenter informs the EPA that examples of regulatory provisions for maintenance of the 

control device can be found in §63.119(e)(3) & (4). 

Response: The commenter generally asserts that the EPA should include a maintenance 

allowance provision in this rule, but did not identify any specific process or operational 

limitations or provide any data or explanation to support its assertion. The EPA, therefore, has 

not included such a provision in the final rule. 

Comment: One commenter (4219) reports that shutdowns and startups are periodically required 

for testing and installation of new equipment that can result in increased efficiency and enhanced 

environmental benefit. The commenter asserts that, if owners and operators risked noncompliance during periods of SSM, then they would have a disincentive to install equipment that 

would improve air quality. 

Response: The commenter did not provide an explanation or information to support the claim 

that owners and operators would risk noncompliance during periods of startup and shutdown 

when installing or testing a new control device. The EPA, therefore, has not included alternate 

standards for startup and shutdown in the final rule.

3.5.4.3 Revisions to the General Provisions Applicability Table

Comment: One commenter (4266) states that, given that the SSM exemption in part 63 subpart 

A has been vacated by the courts, they support the EPA’s edits to Table 2 of NESHAP subpart 

HH that render SSM references in the General Provisions not applicable.

Response: The EPA appreciates the commenter’s support.

Comment: One commenter (4104) states that the preamble notes that requirements related to 

SSM events and the need for SSM Plans (SSMPs) are revised because the SSM exemption no 

longer applies. The commenter further states that the part 63 General Provisions (subpart A) 

include requirements related to SSM events and SSMPs, and the EPA requests comment on 

whether linkages have been appropriately addressed. In response to that request, the commenter 

provides that a perfunctory review of the General Provisions and subpart A applicable sections 

(according to subpart HHH, Table 2) indicates that minor additional revisions are needed. The 

commenter asserts that the EPA needs to clean up Table 2 citations because inappropriate 
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references to subpart A sections could imply that documents (e.g., SSMPs), records, or reporting 

are still required. The commenter cites the following relevant subpart A sections as containing 

linkages that should be addressed:

 §63.6(e) citation in Table 2 should explain selective applicability rather than simply 

stating “Yes” (i.e., Table 2 currently indicates that the section applies); 

 §63.8(c)(1)(iii) should not apply; 

 §63.10(b)(2) citation in Table 2 should explain selective applicability rather than simply 

stating “Yes” (i.e., Table 2 currently indicates that the section applies); 

 §63.10(c)(7) – (8) require records related to the previous SSM paradigm and should no 

longer be required.

Response: The EPA appreciates the commenters’ input and made one change to the final rule to 

address a SSM-related linkage/reference issue. Specifically, the applicability of §63.8(c)(1)(iii) 

was changed from “pending” to “No.” All other recommended changes were rejected.

3.5.4.4 Affirmative Defense Provisions

Comment: Three commenters (3469, 4236, 4274) provide general support for the EPA’s 

proposed affirmative defense to civil penalties for exceedances of numerical emission limits 

caused by malfunctions (§63.7575 defining “affirmative defense”).

Response: The EPA appreciates the commenters’ support.

Comment: One commenter (4159) supports the incorporation of the definition of "malfunction" 

in §63.2. That section defines "malfunction" as:

Any 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 which causes, or has the potential to cause, the emission limitations in an 

applicable standard to be exceeded. Failures that are caused in part by poor maintenance 

or careless operation are not malfunctions.

The commenter (4159) asserts that this is a long-established definition that the regulated 

community is familiar with. 

Response: The EPA appreciates the commenters’ support.

Comment: One commenter (4457) asserts that the EPA unlawfully proposes to promulgate an 

“affirmative defense” to penalties due to a malfunction. See 76 FR at 52787-88 (proposing §§ 
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63.761-62, 63.1271-72). The commenter opines that this would create a new loophole in the 

standards and is unlawful. The commenter states that the statute makes clear how the courts are 

to assess civil penalties, whether a case is brought by the EPA or a citizen. 42 U.S.C. § 7413(e). 

The commenter opines that Congress plainly intended citizens to be able to enforce emission 

standards under the CAA using the full range of civil enforcement mechanisms available to the 

government, and, in the HAP context, subject only to the limitation that government not be 

“diligently prosecuting” its own civil enforcement action, CAA §304(b)(1)(B), 42 U.S.C. § 

7604(b)(1)(B). Specifically, the commenter states that the affirmative defense that the EPA 

proposes to allow in case of malfunctions goes directly against congressional intent in two ways. 

First, according to the commenter, Congress expressed a clear intent as to how judges should 

determine the size of civil penalties whenever they are sought and thus Congress flatly barred the 

EPA from limiting when civil penalties can be assessed. See Chevron, U.S.A., Inc. v. Natural 

Res. Def. Council, Inc., 467 U.S. 837, 842-43 (1984). The commenter believes that the EPA acts 

outside of its delegated authority to limit civil penalties available in citizen suits or its own 

enforcement actions in its proposal. Second, the commenter asserts that the proposal will 

impermissibly chill citizen participation, and the ability to win an effective, deterrent remedy, in 

CAA enforcement actions.

The commenter (4457) argues that the CAA grants the EPA minimal discretion that only applies 

to administrative penalties, allowing the EPA to “compromise, modify, or remit, with or without 

conditions, any administrative penalty which may be imposed under [subsection 113(d)].” 42 

U.S.C. §7413(d)(2)(B) (emphasis added). However, according to the commenter, there is no 

similar grant of authority to the EPA to compromise, modify or limit civil penalties that a court 

may impose under section 113(e) or section 304. Section 304(a), 42 U.S.C. §7604(a), grants 

courts the sole authority “to apply any appropriate civil penalties” in citizen suits. According to 

the commenter, the explicit reference to the EPA’s ability to modify penalties in one subsection 

and its absence in the other subsection of the same provision can only be understood as an 

intentional decision by Congress that the EPA may not contravene by rule.

The commenter (4457) believes that an affirmative defense would likely be used on a routine 

basis by polluters seeking to avoid penalties, just as the malfunction exemption was. Thus, the 

commenter believes that the affirmative defense also runs counter to two clearly expressed 

intentions of Congress: (1) the burden it places on citizens makes it less likely that they will 

enforce the Act, see, e.g., Pennsylvania v. Del. Valley Citizens’ Council for Clean Air, 478 U.S. 

546, 560 (1986); and (2) several of the factors at issue in the affirmative defense undercut 

Congress’s intent that citizen suit enforcement should avoid re-delving into “technological or 

other considerations.” NRDC v. Train, 510 F.2d 692, 724 (D.C. Cir. 1974). According to the 

commenter, both result from the technical burden the EPA imposes on citizens with the 

affirmative defense, and both render the defense impermissible.
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The commenter (4457) argues that the EPA has failed to demonstrate any need or rationale 

justification for an affirmative defense to penalties to be written into the regulations and cause 

the harm that will result. According to the commenter, the EPA has discretion to decide what 

cases to prosecute, to consider settlements, and to request civil penalties in a case-by-case 

manner, as long as it acts consistent with the CAA to protect clean air as its top priority, see 42 

U.S.C. § 7401.

The commenter (4457) asserts that, assuming arguendo that the EPA had authority to promulgate 

any type of affirmative defense to penalties for malfunctions; the EPA should also promulgate 

the following provisions:

1. A specific amount of compensatory penalties should apply to each reported 

malfunction (consistent with the CAA). 

2. The EPA must modify the regulations so that the affirmative defense cannot be used by 

a specific facility or company more than once within a set period of time, such as 10 

years. 

3. The EPA must promulgate specific public reporting and notification requirements for 

malfunctions, or any emission exceedance that occurs of which an operator is aware. 

Commenters support EPA’s proposal to require reporting of malfunctions, as a proposed 

revision to §63.1285, but it is important that this information be electronically reported, 

and made publicly available as soon as possible, and that it include all known information 

on emissions so that the public can evaluate associated health risks.

Response: For malfunctions, the EPA is finalizing the proposed affirmative defense language for 

exceedances of the standards that are caused by malfunctions with minor revisions as discussed 

below. As the EPA explained in the preamble to the proposed rule and final rule, the EPA 

recognizes that even equipment that is properly designed and maintained can fail and that such 

failure can cause an exceedance of the relevant emission standard. The EPA is including an 

affirmative defense in the final rule as we have in other recent section 111, 112 and section 129 

rules so as to balance the tension, inherent in many types of air regulation, to ensure adequate 

compliance while simultaneously recognizing that despite the most diligent of efforts, emission 

limits may be exceeded 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) 

(emissions limitations under CAA section 112 must both continuously apply and meet section 

112’s minimum stringency requirements, even during periods of SSM). Thus, the EPA is 

required to ensure that section 112 emissions limitations are continuous. The affirmative defense 
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for malfunction events meets this requirement by ensuring that even where there is a 

malfunction, the emission limitation is still enforceable through injunctive relief. While 

“continuous” limitations, on the one hand, are required, there is also case law indicating that in 

some 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 

Association 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 calls 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 excess 

emissions 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 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. United States 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 1011, 1057-58 (D.C. Cir. 1978) (holding that an 

informal approach is adequate). The affirmative defense provisions give the EPA the flexibility 

to both ensure that its emission limitations 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. 

Further, the EPA’s view is that the affirmative defense is consistent with CAA sections 113(e) 

and 304. Section 304 gives district court’s jurisdiction “to apply appropriate civil penalties.” 

Section 113(e)(1) identifies the factors that the Administrator or a court shall take into 

consideration in determining the amount of a penalty to be assessed only after it has been 

determined that a penalty is appropriate. The affirmative defense regulatory provision is not 

relevant to the amount of any penalty to be assessed under section 113(e) because if a court 

determines that the affirmative defense elements have been established, then a penalty is not 

appropriate and penalty assessment pursuant to the section 113(e)(1) factors does not occur.

In exercising its authority under section 112 to establish emission standards (at a level that meets 

the stringency requirements of section 112), the EPA necessarily defines conduct that constitutes 

a violation. The EPA’s view is that the affirmative defense is part of the emission standard and 

defines two categories of violation. If there is a violation of the emission standard and the source 

demonstrates that all the elements of the affirmative defense are met, only injunctive relief is 

available. All other violations of the emission standard are subject to injunctive relief and 

penalties. The CAA does not require that all violations be treated equally. Further, a citizen suit 
348

claim under section 304 allows citizens to commence a civil action against any person alleged to 

be in violation of “an emission standard or limitation under this chapter.” The CAA, however, 

allows the EPA to establish such “enforceable emission limitations.” Thus, the citizen suit 

provision clearly contemplates enforcement of the standards that are defined by the EPA. As a 

result, where the EPA defines its emissions limitations and enforcement measures to allow a 

source the opportunity to prove its entitlement to a lesser degree of violation (not subject to 

penalties) in narrow, specified circumstances, as the EPA did here, penalties are not 

“appropriate” under section 304.

The EPA’s view is that an affirmative defense to civil penalties for exceedances of applicable 

emission standards during periods of malfunction appropriately balances competing concerns. 

On the one hand, citizen enforcers are concerned about additional complications in their 

enforcement actions. On the other hand, industrial sources are concerned about being penalized 

for violations caused by malfunctions that could not have been prevented and were otherwise 

appropriately handled (as reflected in the affirmative defense criteria). The EPA has utilized its 

section 301(a)(1) authority to issue regulations necessary to carry out the Act in a manner that 

appropriately balances these competing concerns.

The EPA disagrees that the affirmative defense provision will hamper citizen enforcement. First, 

injunctive relief is still available and the threat of penalties would not deter violations in cases 

where all of the conditions of the affirmative defense have been satisfied because the affirmative 

defense criteria ensure that all reasonable steps were taken to prevent a malfunction that causes 

excess emissions.

Further, litigating whether a source has met the affirmative defense will not burden citizen 

groups any more or less than would litigating the appropriate penalty amount in the penalty 

assessment stage of a citizen suit enforcement action, because the section 113(e) penalty 

assessment criteria and the affirmative defense criteria are similar and in fact overlap. For 

example, the requirement that the Administrator or the court consider “good faith efforts to 

comply” is bound to generate the type of fact-intensive disputes that the commenter complains 

of. In addition, several of the affirmative defense criteria are exactly the type of criteria the 

Administrator or Court might consider in determining whether a source made “good faith efforts 

to comply.” For example, to take advantage of the affirmative defense, the source must prove by 

a preponderance of the evidence that, among other things, the excess emissions “were caused by 

an unavoidable failure of air pollution control and monitoring equipment, process equipment, or 

a process to operate in a normal or usual manner” and “could not have been prevented through 

careful planning, proper design or better operation and maintenance practices” and “did not stem 

from any activity or event that could have been foreseen and avoided, or planned for.”
349

Thus, the EPA does not expect the affirmative defense provision to significantly alter the burden 

of bringing a citizen enforcement action. For those cases that do proceed to trial, even in the 

absence of this affirmative defense, sources generally raise equitable arguments to argue for a 

low penalty and citizens often rebut such arguments. Therefore, as a practical matter, the EPA 

does not expect the affirmative defense provision to materially affect the practice of CAA 

enforcement.

The EPA is not adopting commenters’ suggestion with respect to compensatory damages or 

limits on the frequency of use of the affirmative defense. It is not clear that the EPA has 

authority to require the automatic imposition of compensatory damages and even if such 

authority exists, the EPA does not think automatic imposition of damages is appropriate, as it 

would unduly complicate the enforcement process. Ensuring that malfunctions do not recur can 

be handled through imposition of appropriate injunctive relief. In addition, the EPA’s view is 

that it would not be appropriate to limit a source’s ability to take advantage of the affirmative 

defense to one time over a specified period of time such as ten years given that the affirmative 

defense is only available when the source could not have prevented the excess emissions. With 

respect to commenters’ suggested reporting requirements, the reporting requirements in the rules 

promulgated today already require malfunction reporting and the affirmative defense provisions 

require that parties choosing to assert the affirmative defense meet additional malfunction 

reporting requirements. Any such reports submitted to the EPA are publicly-available pursuant to 

CAA section 114.

Comment: One commenter (4266) states that, with regards to malfunctions, the “EPA has 

determined that malfunctions should not be viewed as a distinct operating mode and, therefore, 

any emissions that occur at such times do not need to be factored into development of CAA 

section 112(d) standards, which, once promulgated, apply at all times.” Id. However, according 

to the commenter, the EPA does propose to establish “an affirmative defense to civil penalties 

for exceedances of emission limits that are caused by malfunctions in both of the MACT 

standards,” which would be available if affected sources can prove by a preponderance of the 

evidence that qualifying criteria have been met. Id. at 52788. The commenter opines that, with 

regard to malfunctions, the EPA’s proposal to provide an affirmative defense for periods of 

malfunction is without merit. The commenter refers to and incorporates comments submitted by 

the “SSM Coalition” to the Proposed Standards of Performance for New Stationary Sources and 

Emission Guidelines for Existing Sources: Sewage Sludge Incineration Units docket that provide 

that the EPA’s proposed standards for Sewage Sludge Incinerators explain in detail that: (1) EPA 

must take malfunctions into accounts when setting section 112 emissions standards; (2) the 

proposed affirmative defense is not a permissible substitute for setting emissions standards for 

periods of malfunction; and (3) the proposed affirmative defense is unreasonable and 

impracticable. See Letter to EPA Docket Center (EPA/DC) from the American Chemistry 

Council, et al., Comments on Proposed Standards of Performance for New Stationary Sources 
350

and Emission Guidelines for Existing Sources: Sewage Sludge Incineration Units, Docket ID No. 

EPA-HQ-OAR-2009–0559, at 6-20 (Nov. 29, 2010). The commenter incorporates these 

comments by reference.

Two commenters (4159, 4273) state that the EPA acknowledges that malfunctions are inevitable 

under technology based standards. See 76 FR at 52788 ("EPA recognizes that, even equipment 

that is properly designed and maintained can sometimes fail, and that such failure can sometimes 

cause or contribute to an exceedance of the relevant emission standard."); see also Marathon Oil 

Co. v. EPA, 564 F.2d 1253, 1272 (9th Cir. 1977) (noting even facilities operated in an 

“exemplary” fashion will experience periods of upset where it cannot meet normal operation 

limits); NRDC v. EPA, 859 F.2d 156,206 (D.C. Cir. 1988) (“Lacking infallibility, no pollution 

control technology works perfectly all of the time.”). As such, the commenters believe that the 

EPA must account for emissions associated with malfunctions in setting the applicable standard. 

“A technology-based standard discards its fundamental premise when it ignores the limits 

inherent in the technology.” NRDC, 859 F.2d at 208. The commenters believe that, failing to 

account for these inevitable failures would “in effect hold dischargers to a higher standard of 

technology than that demanded by the Act.” Id. at 207; see also Cement Kiln Recycling Coalition 

v. EPA, 255 F.3d 855, 872 (D.C. Cir. 2001) (noting doubts of legality of technology-based 

standards that would require “sources to comply with standards even during openings of 

emergency safety valves caused by events beyond the sources' control”). The commenters argue 

that, rather than attempt to promulgate section 112-compliant standards, the EPA proposes to 

establish an “affirmative defense” for malfunctions only. The commenters assert that this 

“affirmative defense” is wholly insufficient to meet the EPA’s obligations under section 112 of 

the CAA.

One commenter (4159) states that the criteria outlined in the proposed rule to establish the 

affirmative defense are inconsistent with the proposed definition for “malfunction” and they 

suggest that the criteria be eliminated. The commenter (4159) asserts that the affirmative defense 

criteria are substantially more restrictive than the requirements to show a malfunction under the 

definition, and that these more restrictive criteria would result in only a subset of malfunctions 

being considered eligible for the affirmative defense, if any at all, undermining the purpose of 

the provision. 

The commenter asserts that there is no justification to include criteria to establish an affirmative 

defense against an alleged violation that are more onerous than the requirements of the 

regulations. For example, the commenter asserts that the first affirmative defense criteria listed 

requires a showing that 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 unusual manner; and (B) Could not have been prevented 

through careful planning, proper design or better operation and maintenance practices; and (C) 
351

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; 76 FR at 52814. The commenter states that other criteria require “[a]ll possible 

steps were taken to minimize the impact,” and repairs were made “as expeditiously as possible.”

The commenter opines that these criteria are substantially more restrictive than the requirements 

to show a malfunction under the definition, and these more restrictive criteria would result in 

only a subset of malfunctions being considered eligible for the affirmative defense, if any at all, 

undermining the purpose of the provision.

The commenter (4159) further states that other criteria are more stringent than, or at least 

redundant of, the general duty standard and, again, should be eliminated. For example, the 

commenter states that, the third affirmative defense criteria requires a showing that the 

"frequency, amount, and duration of the excess emissions (including any bypass) were 

minimized to the maximum extent practicable during periods of such emissions" while the eighth 

criteria requires a showing that “the affected source was operated in a manner consistent with 

good practices for minimizing emissions;” e.g., 76 FR at 52814. The commenter provides that 

general duty only requires an owner or operator to operate and maintain any affected source “in a 

manner consistent with safety and good air pollution control practices for minimizing 

emissions.” Id. at 52815. According to the commenter, the listed criteria for establishing an 

affirmative defense may impose a greater burden on regulated entities than would otherwise be 

required by the standards. At a minimum, the commenter opines that they are redundant of the 

general duty standard and may cause undue confusion as to the applicable requirements.

According to the commenter (4159), the EPA provides no explanation for using these onerous 

criteria. The commenter provides that, although the EPA cites to two memoranda addressing the 

EPA's policy on how State Implementation Plans should treat excess emissions during SSM, 76 

FR at 52788, these memoranda are inapplicable to technology based standards. See EPA Mem., 

State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, 

Startup, and Shutdown, at n.6 (Sept. 20, 1999). According to the commenter, for technology 

based standards, the EPA and courts have recognized that the EPA must either (a) consider SSM 

in setting the standards or (b) provide an upset defense. Thus, based on the commenters’ 

arguments, the commenter believes that the EPA must reconsider its SSM provisions, and reissue 

a proposal that provides its full legal and factual support for its determinations as to the 

appropriate standard to apply to SSM periods. 

One commenter (4104) supports inclusion of a malfunction exemption in the proposed revisions 

to Subparts HH and HHH. The commenter asserts that both the CAA and the Constitution 

require an upset defense as part of any technology-based standard. According to the commenter, 

as drafted, however, the proposed defense is far too narrow and restrictive to satisfy the CAA’s 

and the Constitution’s requirements. For example, according to the commenter, the proposed 

rules would excuse only those events that do not “stem from any activity or event that could have 
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been foreseen and avoided, or planned for[.]” 76 FR at 52829. However, the commenter asserts 

that, any number of events may be “foreseen” and “planned for,” but still interfere with a 

facility’s ability to comply with the standards. The commenter cites events such as a power 

failure or natural disaster as examples that may be anticipated, where the facility may have 

developed an appropriate emergency response plan to implement during these periods – yet may 

still find itself unable to comply with the standard, due to events such as lack of power, lack of 

access to the site, flooding, severe weather, earthquakes, mud slides, vandalism or terrorism, or 

upstream upsets that affect the natural gas that arrives at a natural gas transmission facility. 

According to the commenter, for all of the reasons discussed above, these types of foreseeable 

yet unpreventable events must either be reflected in the overall MACT requirements, or excused 

as a malfunction.

Response: The commenter is correct that the SIP SSM policy was not intended for application to 

NESHAP and NSPS standards. The EPA explained that “[b]ecause EPA set these standards 

taking into account technological limitations, additional exemptions would be inappropriate.” 

State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, 

Startup, and Shutdown, at n.6 (Sept. 20, 1999). However, the Sierra Club case held the 

exemptions in the EPA’s NESHAP rules violated the Clean Air Act and thus the EPA’s approach 

to accounting for the limits of technology in developing NESHAP standards has evolved. The 

EPA has determined that for periods of malfunction, inclusion of an affirmative defense is an 

appropriate and reasonable approach to accounting for the limits of technology. With respect to 

the commenter that refers to and incorporates comments submitted by the “SSM Coalition” to 

the Proposed Standards of Performance for New Stationary Sources and Emission Guidelines for 

Existing Sources: Sewage Sludge Incineration Units docket, the EPA believes that those 

comments have largely been addressed above, however, the EPA also responded to the SSM 

Coalition’s comments in the context of that rulemaking and directs commenters to those 

responses as well (Standards of Performance for New Stationary Sources and Emission 

Guidelines for Existing Sources: Sewage Sludge Incineration Units Summary of Public 

Comments and Responses; Docket No. EPA-HQ-OAR-2009-0559-0171). 

The EPA disagrees that the criteria of the affirmative defense undermine the purpose of the 

malfunction definition. The EPA does not intend that an affirmative defense will be available in 

every instance of a malfunction.

The EPA recognizes that some of the criteria for establishing an affirmative defense may be 

redundant of the general duty, but does not agree that such redundancy is a problem. The EPA 

notes that the affirmative defense criteria and the general duty to minimize emissions do not 

operate in the same manner. The general duty is applicable to a source at all times. The 

affirmative defense criteria are only relevant if a source chooses to take advantage of the 

affirmative defense.
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Further, the EPA disagrees with comments that criticize the affirmative defense criteria as being 

overly vague or unduly restrictive and complex. The EPA believes that courts are well equipped 

and often do evaluate and apply the type of criteria set forth in the affirmative defense. Many of 

the conditions were modeled after the conditions of the affirmative defense in the EPA’s SIP 

SSM policy, which several states have adopted into their SIPs. (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)). We do not have any indication that parties to enforcement 

proceedings have had any significant difficulties applying the terms of these SIP affirmative 

defenses. In addition, the EPA’s view is that use of consistent terms in establishing affirmative 

defense regulations and policies across various CAA programs will promote consistent 

implementation of those rules and policies. 

With respect to commenter’s concern that events such as floods or earthquakes that are 

foreseeable and have been planned for would not be eligible for the affirmative defense, the EPA 

believes that malfunctions that are caused by such events and that lead to violations could, 

depending on the circumstances, be eligible for the affirmative defense if the resulting violations 

could not have been prevented whether or not there was an attempt to plan for the event. 

Preparing and having a plan in place that addresses floods generally does not mean that all 

consequences of flooding can be planned for or avoided. 

Comment: One commenter (4266) reports that the revisions around the SSM events have no 

start date. The commenter requests that, if the EPA continues with the affirmative defense 

provisions, that the regulatory text be added/revised to make a clear distinction of when these 

provisions become effective. According to the commenter, without this, agency personnel 

without the knowledge of the regulatory history could try to enforce the provisions around 

affirmative defense and SSM events retroactively. 

Response: The effective date of the SSM revisions is the effective date of the rule.

Comment: One commenter (4226) asserts that the EPA must propose a threshold for the type, 

duration or quantity of emissions that could trigger civil penalties. According to the commenter, 

under the current wording, even the slightest malfunction could result in civil actions. The 

commenter suggests that, alternatively, small/de minimis incidents could be tracked as deviations 

rather than exceedances, and that industry would still track and submit them to the EPA; but the 

affirmative defense and corresponding nine criteria for the affirmative defense would not be 

required. 
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Response: The affirmative defense criteria are not requirements that a source must meet. In an 

action to enforce a violation of a standard caused by a malfunction, a source can choose to assert 

an affirmative defense. The affirmative defense is not relevant to malfunctions that do not result 

in violations of emission standards. 

Comment: One commenter (4159) asserts that the EPA’s proposal to limit the affirmative 

defense to malfunctions only and provides no explanation as to why such a defense is not also 

appropriate for startup and shutdown periods. According to the commenter, the EPA has 

recognized that it may not be possible to meet normally applicable emission limitations during 

startup and shutdown activities, not just malfunctions. 

Response: The EPA is promulgating the affirmative defense for malfunctions only, not for 

periods of startup and shutdown. As explained in the preamble, the EPA believes that 

malfunction events should be treated differently than periods of startup and shutdown, which are 

predictable and routine aspects of a source’s operations. In contrast, the EPA has determined that 

CAA section 112 does not require that emissions that occur during malfunctions be factored into 

development of CAA section 112 standards. Because startup and shutdown periods are part of a 

source’s normal operations, the same approach to compliance with, and enforcement of, 

applicable emissions standards during those periods should apply as otherwise applies during a 

source’s operations. Further, as explained above, periods of startup and shutdown – but not 

malfunctions -- are taken into account when establishing section 112 emissions standards. For 

these reasons, the EPA does not believe it is appropriate to apply the affirmative defense 

provisions to startup and shutdown periods.

Comment: Three commenters (4218, 4258, 4266) state that proving an affirmative defense will 

be close to impossible for malfunctions that occur at many of their facilities because they are 

located in remote areas that are not continually staffed. One commenter (4258) states that some 

sites are only visited by the operator 2-3 times a month, and although telemetry is often used, and 

some site operations will automatically shutdown, some must be visited manually to be shut 

down.

One commenter (4266) states that excess emissions can result from weather conditions or 

gathering system/processing plant outages that are beyond the control of the operator. According 

to the commenter, many well sites are remotely located and most are unmanned facilities. The 

commenter reports that inspection and maintenance visits occur on average anywhere from 

weekly to twice per month, depending on the location and time of year. In some areas, winter 

weather makes it difficult to visit sites causing extended periods between site visits. According to 

the commenter, although telemetry is often utilized for new production well sites to optimize the 

need for operator attention, weather conditions can affect not only the control device (flare 

flameout) but can also affect telemetry which would catch and report such discrepancies. The 
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commenter states that system outages to the gathering system, gas treating plants, or gas 

processing plants occur infrequently but can occur several times during the year. Additionally, 

the commenter reports that these outages immediately result in a stop in production, and wells 

that are equipped to automatically shut down, do so. However, the commenter reports that most 

wells must be visited manually in order to shut down the well and associated equipment. 

According to the commenter, once the system is restored and open to production flow, operators 

must begin the process of visiting the wells to open them back to production and restore 

associated operating equipment and control devices. The commenter recommends that the EPA 

specify how they would consider weather and “system” outages that are beyond the control of 

the upstream operator in a malfunction work practice. 

Response: The commenter has not specified which aspects of the affirmative defense would be 

“close to impossible” to prove, however, the EPA is revising certain criteria of the affirmative 

defense provisions that may ease the burden for owners and operators of remote sources. The 

EPA is eliminating both the immediate notification and 45-day malfunction report requirement. 

Instead, the final rule allows owners or operators seeking to assert an affirmative defense to 

demonstrate, with all necessary supporting documentation (as was required under the proposed 

45-day report), that it has met the affirmative defense criteria by including the report in the first 

periodic compliance, deviation report or excess emission report otherwise required after the 

initial occurrence of the violation of the relevant standard (which may be the end of any 

applicable averaging period). If such compliance, deviation report or excess emission report is 

due less than 45 days after the initial occurrence of the violation, the affirmative defense report 

may be included in the second compliance, deviation report or excess emission report due after 

the initial occurrence of the violation of the relevant standard. This change provides sources with 

sufficient time to demonstrate that they have met the required affirmative defense criteria.

Comment: One commenter (4104) requests that the affirmative defense criteria be modified 

considering the following: 

 Timely notification: The availability of the affirmative defense should not be negated by 

a failure to notify, especially for events that involve small quantities of emissions. 

 Infrequent events: Restricting the malfunction defense to “infrequent” events is legally 

acceptable only if more “frequent” events are excepted under some version of the 

startup/shutdown defense. 

 Off-shift and overtime labor: The requirement to use off-shift and overtime labor should 

be deleted, because it impairs the site’s ability to respond in the manner most appropriate 

under the circumstances. 

 Severe property damage: The word “severe” should be struck. Determining whether 

property damage is sufficiently “severe” to merit application of the defense is highly 

subjective and vague. 
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 Signed operating logs: the EPA should remove the requirement that operating logs be 

signed. Many facilities now use some form of electronic media to document response 

actions; other facilities may use paper records that do not require a signature. 

 Root cause analysis: The requirement to perform a root cause analysis is vague and does 

not put industry on notice of the type of analysis that the EPA will deem sufficient, or the 

time in which such an analysis must be performed. Such an analysis is also unnecessarily 

burdensome and serves no environmental protection purpose for many malfunction 

events where the “root cause” is clearly identifiable (e.g., power outage, hurricane). 

Response: The EPA has considered the commenter’s suggestions associated with specific 

affirmative defense criteria changes. Although not all of the changes were accepted, some are 

reflected in recent changes the EPA has made to these provisions.

 Timely Notification: The EPA has removed the requirement to notify the EPA within two 

days of violation of a standard in order to be able to avail themselves to a claim for 

affirmative defense and instead requires that the affirmative defense report be included in 

the first periodic compliance, deviation report or excess emission report otherwise 

required after the initial occurrence of the violation of the relevant standard (which may 

be the end of any applicable averaging period). If such compliance, deviation report or 

excess emission report is due less than 45 days after the initial occurrence of the 

violation, the affirmative defense report may be included in the second compliance, 

deviation report or excess emission report due after the initial occurrence of the violation 

of the relevant standard .

 Infrequent Events: The EPA believes that if malfunctions occur on a frequent basis that 

the basis for the malfunction more likely falls in the categories of poor design, poor 

operational decision making, or failure to operate a source in a normal manner and has 

retained the word “infrequent” in this criteria element. 

 Off-shift and overtime labor: The EPA believes that rather than impair a sources response 

to a malfunction, the use of off-shift and overtime labor supports the premise that 

urgency is necessary to minimize to the maximum extent practicable all excess emissions 

associated with a malfunction and has retained this language in the criteria. 

 Severe Property Damage: The EPA believes that a bypass of control equipment or a 

process, which results in a violation, should be an exception and not undertaken lightly, 

and has maintained the word “severe” in this criteria.

 Signed Operating Logs: As an alternative, the EPA accepts electronically signed 

operating logs where the format and method of submission meets the regulatory criteria 

and are compatible with the EPA and the delegated authorities’ electronic submission 

systems. Any source submitting records electronically should exercise due diligence to 

assure receipt by the EPA and the delegated authority.
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 Root Cause Analysis: The EPA believes it has provided clear criteria within the 

affirmative defense provisions to support the development of an affirmative defense 

report. The EPA believes that these provisions will result in a minor administrative 

burden, but will result in sources analyzing their violation emissions to reduce or avoid 

those emissions in the future, which is an environmental benefit. A root cause analysis is 

not mandatory and is only required if a source seeks to assert an affirmative defense. 

However, such an analysis is beneficial in resolving or preventing violations and excess 

emissions whether the source seeks to assert the affirmative defense or not. A root cause 

analysis is one example of what constitutes good air pollution control practices to 

minimize emissions. A root cause analysis is not required for every malfunction, as 

specified above, and is only required for those malfunctions for which the source chooses 

to assert an affirmative defense.

Comment: Three commenters (4104, 4159, 4273) state that criteria outlined in the proposed rule 

are significantly more stringent than that provided in the analogous “upset defense” under the 

Clean Water Act, imposing substantial burdens on regulated entities for actions that, by 

definition, are not the fault of the facility. The commenters state that the EPA provides no 

explanation as to why it has chosen to move away from the long-standing upset defense at 40 

C.F.R. §122.41(n), promulgated under the Clean Water Act. The commenters assert that, under 

the CWA, an “upset constitutes an affirmative defense” 40 C.F.R. §122.41(n)(2) and that to 

establish the defense under the Clean Water Act, the following criteria must be met:

 an upset occurred and the permittee can identify the cause(s) of the upset;

 the permitted facility was at the time being properly operated;

 the permittee submitted notice of the upset (required within 24 hours); 

 the permittee took all reasonable steps to minimize or prevent the violation. See 40 

C.F.R. §122.41(n)(3), (l)(6)(i). 

One commenter (4104) specifically recommends that the EPA replace the proposed affirmative 

defense language with the language used at 40 CFR §122.41(n), the upset defense provided 

under the Clean Water Act. The commenter asserts that the language was crafted to cure the 

same statutory and constitutional deficiencies that compel the inclusion of a malfunction defense 

here, see, e.g., Train, 539. F.2d at 986, and so is the most appropriate and efficient mechanism 

for addressing these same deficiencies for subpart OOOO and subparts HH and HHH.

Another commenter (4228) suggests that the EPA should replace the proposed rule malfunction 

defense language with the upset defense provided under the Clean Water Act.

Response: The EPA does not find the commenter’s preference for the affirmative defense under 

the Clean Water Act persuasive enough to deviate from the affirmative defense approach that has 

been used under the CAA for nearly 20 years. While we recognize that certain characteristics of 
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the two approaches are similar, our preference is to adopt an approach that has been practiced 

under the CAA.

Comment: Two commenters (4246, 4266) assert that the provisions of §63.762(d)(1)(i)-(ix) 

would specify a 9-step procedure for determining whether a given malfunction event qualifies 

for the affirmative defense. According to the commenters, in most cases, it would not be realistic 

to complete this determination process within 2 days following the occurrence of the event. The 

commenters state that facilities might therefore tend to routinely submit the 2-day notification in 

order to preserve the potential for an affirmative defense, even in cases which subsequently are 

determined to not qualify. Furthermore, the commenters state that there is no environmental 

benefit that would accrue from this notification, and similar provisions in refinery consent 

decrees do not require it. As proposed, the commenters assert that these notifications would be 

required for the smallest of emission exceedances with no reportable quantity threshold being 

set. The commenters argue that this is contradictory to other EPA reporting rules such as those 

under CERCLA and EPCRA where reportable quantities are established for unauthorized 

releases. The commenters opine that immediate reporting to the EPA serves no beneficial 

purpose. The commenters recommend that, if the EPA insists on a notification requirement, the 

rules should allow at least 15 business days following the occurrence of the event for this 

notification to be submitted.

Three commenters (4218, 4242, 4266) request that the EPA allow malfunction reports to be 

submitted with the semi-annual reports. 

One commenter (4266) states that the rule already requires, at §63.775(e), the submission of 

excess emissions reports on a semi-annual basis, and the EPA has established the semi-annual 

basis as being appropriate for all compliance-related reporting through numerous rulemakings. 

The commenters assert that it would be contrary to the agency’s own assessment of an 

appropriate reporting frequency to arbitrarily require malfunction reports to be submitted within 

30 days.

Another commenter (4242) believes that there is no reason to require a reporting frequency that 

differs from the semi-annual basis. 

Response: The EPA has evaluated some of the affirmative defense criteria, and is revising both 

the immediate notification and 45-day malfunction report. Instead, the final rule allows owners 

or operators seeking to assert an affirmative defense to demonstrate, with all necessary 

supporting documentation (as was required under the proposed 45-day report), that it has met the 

affirmative defense criteria by submittal of the affirmative defense report in the first periodic 

compliance report, deviation report or excess emission report otherwise required after the initial 

occurrence of the violation of the relevant standard (which may be the end of any applicable 
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averaging period). If such compliance report, deviation report or excess emission report is due 

less than 45 days after the initial occurrence of the violation, the affirmative defense report may 

be included in the second compliance report, deviation report or excess emission report due after 

the initial occurrence of the violation of the relevant standard. This change provides sources with 

sufficient time to demonstrate that they have met the required affirmative defense criteria.

Comment: Four commenters (4219, 4245, 4258, 4356) request that the EPA expressly provide 

in the proposed rules that a SIP-approved State affirmative defense program would be sufficient 

to establish the affirmative defense for the Federal rules, or that the EPA defer to the State’s 

exceedance policies and regulations in lieu of the Federal affirmative defense provisions.

Response: Pursuant to the EPA regulations at 40 CFR 63.93, States may seek approval of State 

requirements to substitute for requirements included in final section 112 standards if the State 

requirements are equivalent to the promulgated section 112 standards. States that have SIP 

approved affirmative defense provisions may seek to have those programs apply in lieu of the 

affirmative defense provisions applicable to malfunction periods in the final rule.

3.5.4.5 Did EPA Overlook Any Changes that Should Have Been Made

Comment: One commenter (4222) recommends that the EPA include a statement in §63.752 to 

make it clear that a SSM plan is not required. According to the commenter, currently, the only 

place this is specified is in Table 2 to subpart HH.

Response: The EPA believes that the commenter mistakenly refers to §63.752 (which refers to a 

section under the Aerospace NESHAP) when they meant to refer to §63.762. The EPA has 

eliminated the SSM plan requirements in §63.762 and the final rule contains no SSM plan 

requirement. Thus, the clarification requested by commenter is not necessary. 

Comment: One commenter (4457) supports the EPA’s proposed removal of the “SSM

exemption” that the D.C. Circuit has struck down as a violation of section 112 of the CAA, 42 

U.S.C. § 7412. 76 FR at 52787-88; see Sierra Club v. EPA, 551 F.3d at 1027-28 (holding that 

section 302(k), 42 U.S.C. § 7602(k), defines an emission standard as requiring “continuous” 

control of pollution). However, according to the commenter, although the EPA states that it is 

removing all SSM exceptions from the standard, the EPA proposes to keep a provision allowing 

“one excused excursion” for control devices. See 76 FR at 52824 (40 C.F.R. § 63.773(d)(8)(ii)), 

52839 (40 C.F.R. § 63.1283(d)(8)(ii)). The commenter asserts that this appears to allow sources 

to violate the section 112 standards once “per semiannual period for any reason.” The 

commenter argues that section 112 requires the standards to apply at all times. Sierra Club v. 

EPA, 551 F.3d at 1027-28. Therefore, according to the commenter, the EPA may not lawfully 
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include any “excused excursion” provision, and recommends that the EPA remove all SSM 

exemptions from the rules.

Response: We agree with the commenter. 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.

Comment: One commenter (4245) asserts that SSM emissions will no longer be exempt from 

permitting and control requirements. The commenter states that the noted exemption in the 

proposed regulation from title V (Federal permit) specifically does not apply to emission 

increases triggered by accounting for SSM emissions. The commenter is concerned that, by 

forcing operators to account for SSM emissions as part of their operating emissions “footprint” it 

will shift the permitting, control, monitoring and reporting requirements upward (in the direction 

from permit-by-rule registration to standard permit to major permit). Thus, according to the 

commenter, countless oil and gas facilities in Texas that are presently covered by permit-by-rule 

(most requiring registration due to H2S) will be moved to standard permit requirements and 

many presently covered by standard permit will be pushed upward to major (title V) permit 

requirements. The commenter asserts that this is a tremendous challenge for the Permian Basin 

in Texas, which is constrained with respect to sour gas handling and processing capacity. The 

commenter asserts that the EPA’s proposal to require the inclusion of SSM emissions will have 

the effect of vastly expanding the scope of regulatory requirements for small oil and gas 

producers. According to the commenter, it will also create, on a wide scale, circumstances where 

operators cannot physically comply with emission standards due to real limitations in gas 

gathering systems, thus forcing them to curtail or shutdown their operations. 

Response: The changes that we proposed to the startup, shutdown and malfunction (SSM) 

provisions of the Oil and Natural Gas Production MACT do not affect how a source determines 

whether it is a “major source” and, therefore, required to obtain a title V operating permit.41 

Rather, the proposed changes simply propose to eliminate the exemption in the original Oil and 

Natural Gas Production MACT, which provides that sources do not need to comply with the 

emission standards in the rule during periods of SSM, and thus require compliance with the 

standards at all times. Removing that exemption does not alter how the source or a permitting 

authority determines a source’s potential to emit (PTE) or whether the source is required to 

obtain a title V operating permit. 

With respect to commenter’s suggestion that EPA leave the regulation of SSM emissions to the 

respective state agencies, EPA notes that in accordance with the decision in Sierra Club v. EPA, 

551 F.3rd 1019 (D.C. Cir. 2008), EPA is required to establish emission standards under section 

 

41 As a general matter, area sources that are subject to subpart HH are exempt from the requirement to obtain a title 

V operating permit.
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112 that apply at all times, including during periods of startup, shutdown or malfunction. Thus, 

EPA cannot defer the regulation of SSM emissions to state agencies.

3.5.5 Applicability and Compliance

Comment: One commenter (4219) states that owners and operators of large glycol dehydrators 

should be given 3 years to come into compliance with the new 95 percent reduction standard. 

The commenter argues that the proposed requirement to comply within 90 days of rule 

finalization would be unreasonable. 

One commenter (4266) states that the 90-day compliance time for large dehydrators is 

insufficient if the 0.9 Mg/yr benzene compliance option is removed. The commenter believes 

that the EPA’s rationale for eliminating the 0.9 Mg/yr benzene limitation is severely flawed and 

expects that the EPA will restore the 0.9 Mg/yr benzene limitation after consideration of these 

comments. However, if the EPA does not restore this alternative limitation, the commenter 

argues that the EPA must extend the compliance date to the same 3-year period proposed for 

newly regulated small dehydrators and storage vessels without the potential for flash emissions. 

Another commenter (4192) recommends the following revision to §63.760(f)(10): “Each large 

glycol dehydration unit, as defined in §63.761, that has complied with the provisions of this 

subpart [add: on or] prior to August 23, 2011 by reducing its benzene emissions to less than 0.9 

megagrams per year (1 TPY) must achieve compliance no later than [delete: 90 days] [add: 3 

years] after the date of publication of the final rule in the Federal Register, except as provided in 

§63.6(i).”

Response: In both the final rule for subpart HH and subpart HHH, we have retained the 0.9 

Mg/yr compliance option, and these comments are no longer applicable.

Comment: Two commenters (4192, 4246) express concern for sources whose HAP emissions 

increase despite decreasing natural gas throughput due to changes in gas composition and the 

impact on compliance timelines. The commenters note that the proposed rule appears to allow no 

time to achieve compliance under §63.760(f) when this occurs. The commenters recommend that 

EPA should add a new provision, §63.760(f)(11), that reads, “[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 or after the date of publication of the final rule in the Federal Register due to a 

change in the extended analysis of the gas must achieve compliance no later than 3 years after it 

becomes a major source, except as provided in §63.6(i).”
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Response: We believe the commenters suggestion to add a section under §63.760(f) to address 

the compliance date for production field facilities that later increase their emissions to major 

source levels is not necessary. The proposed language in §63.760(f)(9) references production 

field facilities that are impacted by the change in criteria specific to storage vessels and the 

resulting major source determinations. We expect that existing area sources under subpart HH 

will perform a major source determination based on the revised criteria. Those facilities that 

remain area sources after applying the revised criteria, and other area sources not impacted by 

the revised criteria, will use the criteria of §63.760(f)(1) and (2) as well as, §63.6(c)(5) to 

determine whether they comply with the new or existing source standards for major sources.

This requirement remains unchanged with the amendments. We have not made any changes in 

response to these comments.

Comment: Commenter (4246) suggests several revisions to §63.760(f) to maintain consistency 

with NSPS Subpart OOOO and for internal consistency. 

Response: We have reviewed the suggested changes and do not believe they are necessary. We 

remind the commenter that while consistency between the NSPS and NESHAP is desirable, the 

rules have different objectives that will at times necessitate differences.

Comment: One commenter (4266) notes that the EPA has made allowances for new compliance 

dates for specific types of equipment that have new or revised compliance requirements because 

of the proposed revisions (§63.760(f)(7)-(10)). However, the commenter contends that other 

proposed revisions do not appear to have new compliance dates associated. The commenter 

asserts that this practice may have the unintended consequence that the new text may be 

interpreted as having retroactive compliance requirements. 

Response: We have reviewed the compliance date provisions in the final rule and have found 

them to be clear in that no retroactive compliance requirements are created.

3.5.5.1 Calculating Potential to Emit

Comment: One commenter (4263) suggests that in §63.760 (a)(1)(i)(B), the EPA should delete 

"prior to 1999" and provide for potential to emit determinations. The commenter explains that 

production facilities that have experienced a decline in production after the period allowed by 

§63.760(a)(1)(i) should be able to determine maximum “potential” production rates based on a 

“5-year lookback” approach, which has been adopted by some state agencies. For the same 

reason, the commenter recommends that the EPA should also update the outdated language in 

§63.1270(a)(2), referenced by the amended paragraph (a) of §63.1270, to provide for potential to 

emit determinations based on historical throughput levels. The commenter adds that the EPA 

should delete reference to the use of throughput "prior to June 17, 1999" for major source 
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determinations to accommodate newer facilities that may nevertheless experience declining 

throughput levels.

Response: The provisions to which the commenter recommended revision were not reopened for 

notice and comment in our proposed rule. The requested revision is therefore outside the scope 

of this rulemaking.

Comment: One commenter (4039) states that GRI-GlyCalcTM model inputs should use the best 

available values rather than prescribed values. The commenter notes that the proposal seeks to 

change the circulation rate input to use a default of the design maximum. The commenter states 

they have extensive experience using this model and have found that the most significant input 

variables to the model are (ranked from most sensitive to least sensitive): (1) wet gas analysis, 

(2) lean glycol recirculation rate, (3) contactor temperature and pressure, (4) dry gas moisture 

content, and (5) lean glycol water content. To arbitrarily set the circulation rate at the design 

maximum is not warranted, according to the commenter, and will lead to falsely high emission 

results. The commenter states that if other, more representative values are available they should 

be used in preference to the design maximum. The commenter explains that more representative 

values would include the actual circulation rate and the optimal glycol recirculation rate based on 

the water content of the stream. 

One commenter (4191) states that they have found emissions of HAP from glycol dehydrators 

are impacted by changing gas composition. However, the commenter also states that the effect of 

the glycol circulation rate on HAP and VOC emissions is much stronger. The commenter states

that they do not have specific data that a changing gas composition could lead to increasing HAP 

emissions, even as the gas throughput decreases. However, according to the commenter, HAP 

emissions are likely to increase as the glycol circulation rate increases, even as gas throughput 

decreases. To account for changing gas composition, the commenter requires an annual extended 

wet gas analysis be completed for input into emissions estimating software such as GRIGLYCalcTM, HYSYS or ProMax.

Two commenters (4192, 4246) support using the maximum rate of the glycol circulation pump 

for PTE calculations.

Response: As stated in the proposal (76 FR 52788), the change is being made to clarify, rather 

than change, what is required in a major source determination under §63.2 of the General 

Provisions.

3.5.5.2 Revisions to Definition of Facility and Applicability Criteria
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Comment: Two commenters (4056, 4266) believe that the apparent expansion of the source 

category for the Oil & Gas NESHAP creates an overlap with other regulations, such as the 

Organic Liquid Distribution (OLD) NESHAP (40 CFR part 63, subpart EEEE), subpart HHH, 

and NSPS subpart Kb. The commenter believes that this apparent expansion is unnecessary and 

will create regulatory confusion. One commenter (4266) adds that, under the proposal, it would 

seem some sources currently regulated under subparts HHH and EEEE might no longer be 

subject to those rules and instead would be subject to subpart HH on the basis that only one 

NESHAP applies to any individual source. One commenter (4056) requests that the EPA retain 

the current language in §§63.760 and 63.761 regarding the point of custody transfer for liquids to 

clearly show demarcation between the end and beginning of the source categories. According to 

the commenter, equally important is that there will be no impact on the environment if the EPA 

maintains the status quo since the crude oil transportation sources beyond the traditional oil and 

gas production sector are already “affected sources” under an existing NESHAP. One 

commenter (4056) describes sections in the proposal preamble and rule that contribute to this 

confusion. 

Response: We do not believe we have expanded the source category as the commenter contends. 

The source category has remained the same, while the final rules apply to additional emission 

sources within the source category. We disagree that there are apparent overlaps with the rules 

cited by the commenter, but remind the commenter that the original rule provided guidance at 

§63.760(g) for overlap with other equipment leak regulations. 

Comment: Two commenters (4192, 4246) recommend revising the applicability provision in 

§63.760(e)(2) to state: “A major source facility, [DELETE prior to the point of custody transfer], 

with a facility-wide actual annual average natural gas throughput less than 18.4 thousand 

standard cubic meters per day [ADD (i.e., 650,000 SCFD)] and a facility-wide actual annual 

average hydrocarbon liquid throughput less than 39,700 liters per day [ADD (i.e., 10,500 

gallons/day).” 

Response: The section cited by the commenter was not part of the proposed changes and cannot 

be revised at this time. In addition, the requested deletion of the custody transfer reference would 

not be appropriate since the criteria specified in this section is intended to apply to production 

field facilities only and not all sources subject to subpart HH.

Comment: One commenter (4266) notes that, although oil and natural gas are measured at and 

pass several “accounting transfers” (such as lease accounting for royalty purposes, and gathering 

and gas plant balance for product loss and shrinkage purposes), products often are not transferred 

from the production operator until the product is loaded onto trucks or into a pipeline to leave the 

field. Additionally, the commenter notes that using the last point before the oil or natural gas 

leaves the production field allows the NSPS and NESHAP regulations to use the same regulatory 
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demarcation between the production and transportation sectors, as specified in CAA section 

112(c). The commenter believes this rulemaking should clearly define which point of custody 

transfer is intended for this dividing point. The commenter recommends that this dividing point 

be the last point of custody transfer before the crude oil or condensate leaves the production field 

and enters the transportation industry. According to the commenter, this would most closely 

match the original intent of the custody transfer definition in the final NSPS subpart K and the 

common practice of the oil and natural gas industry.

The commenter (4266) adds that there is unnecessary ambiguity in the applicability of the 

proposed rules with respect to storage vessels. The commenter believes the rules need to clearly 

specify the boundaries of the source category, identify the affected facilities within that source 

category, and specify which of the affected facilities are subject to the control requirements. The 

commenter states that part 60 subpart Kb and part 63 subparts HH, HHH, and EEEE each 

describe the boundary between the oil and natural gas production sector and the transportation 

sector as being where oil or natural gas is transferred from production or producing operations to 

“pipelines or any other forms of transportation.” The commenter points out that the original 

version of subpart HH specifies that applicability is limited to storage vessels located prior to the 

point of custody transfer to pipelines or other forms of transportation. The commenter contends 

that the proposed revisions to §63.760(a)(2), however, would remove that point of demarcation, 

and instead specify that the rule applies to facilities “prior to the point where hydrocarbon liquids 

enter either the Organic Liquids Distribution (Nongasoline) or Petroleum Refineries source 

categories.” The commenter believes this wording has the apparent intent of preserving the 

boundary between the production field and the liquids distribution system, but the reference 

becomes circular in that the OLD MACT rule (subpart EEEE) specifies that it excludes facilities 

subject to part 63 subpart HH (see §63.2334(c)(1)). 

The commenter (4266) also notes that the revisions to subpart HH would result in each rule 

excluding the affected facilities of the other, but neither rule defining the boundary between the 

source categories. In order to preserve a specified boundary, the commenter recommends that the 

wording of §63.760(a)(2) should continue to specify the point of custody transfer as the 

demarcation between the production field and transportation sectors. Further clarity would be 

achieved, according to the commenter, by replacing the former definition of “custody transfer” 

with the following suggestion: §63.761 [ADD TEXT: Custody transfer means the last point of 

custody transfer of crude oil, condensate, or natural gas before it leaves the production field or 

basin and enters pipelines or any other forms of transportation. Typical custody transfer points 

include truck loading facilities or pipeline metering stations for crude oil or condensate, and the 

tail gate of natural gas processing plants or pipeline metering stations for natural gas.] 

Response: We recognize the commenter's concerns regarding references that do not clearly 

identify the applicability between different subparts. To avoid concerns/confusion about where 
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OLD MACT and MACT HH apply, we are removing the references to the OLD MACT and 

refinery source categories proposed under §63.760(a)(2). The reference to the point of custody 

transfer however, will not be added back to §63.760(a)(2) as suggested by the commenter since 

we believe that reference is only needed in the definition of facility in §63.761.

Therefore, we are reinstating the references to custody transfer in the definition of facility in 

§63.761 so that facility boundary within the oil and natural gas production source category is 

clearly defined. We believe that these changes, along with the exemption contained in the OLD 

MACT under §63.2334(c)(1), for oil and natural gas operations, ensure that the OLD MACT 

does not apply at facilities subject to subpart HH and eliminates any circular references.

Comment: Two commenters (4192, 4246) offer a slightly different version of a “custody 

transfer” definition: Custody transfer means the transfer of hydrocarbon liquids or natural gas: 

after processing and/or treatment in the producing operations, or from storage vessels or 

automatic transfer facilities or other such equipment, including product loading racks, to 

pipelines or any other forms of transportation. For the purposes of this subpart, the point at which 

such liquids or natural gas [delete: enters] [add: exits] a natural gas processing plant is a point of 

custody transfer.

Response: The custody transfer definition, along with the references to certain custody transfer 

points in subpart HH, are intended to serve several purposes: 1) the custody transfer point where 

natural gas enters the natural gas processing plant marks the point where the emission 

aggregation limitations at production field facilities no longer applies; 2) the custody transfer 

point where natural gas exits the natural gas processing plant serves to identify where subpart 

HH no longer applies (i.e., subpart HHH applies downstream of that point). Along with the 

definition of facility, the EPA believes these terms are sufficient and no changes have been made 

in response to these comments.

Comment: One commenter (4217) believes the EPA must withdraw the proposed change to the 

major source definition under §63.760. The commenter believes that such a significant change 

requires an adequate opportunity for review and comment of MACT subpart DDDDD. If the 

EPA revises the definition of a major source in MACT subpart HH to include all storage vessels, 

then the commenter contends that this also impacts major source determinations made under at 

least NESHAP subpart DDDDD for owner and operators of an industrial, commercial, or 

institutional boiler or process heater that is located at a major source. For ONG facilities, the 

commenter points out that the major source definition in subpart DDDDD references the 

definition in subpart HH. The commenter states that the potential revision of a major source 

definition in subpart HH is both a procedural and practical problem for owners and operators of 

ONG production facilities that are currently minor sources according to the subpart HH major 

source definition. 
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Response: It is not uncommon for one rule to cross reference a requirement in another rule. The 

EPA is not required to consider all potential impacts to other rules that cross reference a 

provision in a rule before revising such provision. As the commenter correctly notes, any such 

potential impact may be evaluated through review of the subpart that provides the cross 

reference. In this case, the commenter may petition the EPA to re-evaluate whether the cross 

reference in subpart DDDDD remains appropriate in light of this final rule.

3.5.5.3 Other Clarification Changes

Comment: Two commenters (4192, 4246) state that the current subpart HH provides that a 

major source retains that status permanently, even if it reduces its emissions below the major 

source threshold. The commenters state that this policy of “once-in-always-in” discourages 

sources from undertaking major HAP emission reductions, and should be eliminated for MACT 

subpart HH — as EPA proposed in Docket No. EPA-HQ-OAR-2004-0094 (see National 

Emission Standards for Hazardous Air Pollutants, General Provisions, 72 FR 69 (Jan. 3, 2007). 

This change in policy would, according to the commenter, present a tremendous incentive for 

owners and operators to reduce their emissions to less than 1 tpy benzene and maintain those 

emissions at a low level.

Another commenter (4104) describes the history of this policy and notes that as more major 

source NESHAPs are amended to add emission standards for smaller units, the incentive to avoid 

the part 63 administrative burden by achieving area source status becomes more pronounced. 

However, the commenter notes that the OIAI policy precludes pursuing such an approach, so 

facilities will remain major source emitters. The commenter agrees that the EPA should adopt a 

new policy that would also provide additional motivation to pursue innovative technologies or 

processes that reduce emissions. According to the commenter, the OIAI policy limits the benefit 

to operators that would like to pursue emission reductions and stifles innovation.

Response: The commenter seeks revision to the Agency’s OIAI policy. The OIAI policy was is 

a subject of this rulemakeing and was not mentioned in the proposed rule. Accordingly, the EPA 

is not addressing this comment in the final rule. 

3.5.6 Other Comments

Comment: One commenter (4178) states that they have a General Permit program for small 

sources in certain categories such as Oil & Gas. According to the commenter, many facilities are 

currently permitted under General Permits for Oil and Gas Facilities or General Permits for Area 

Source NESHAP Facilities. The commenter states that some of these sources will become major 

according to subpart HH or HHH. The commenter contends that they will be required to review 
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whether the general permits can be revised or if the facilities will be required to have new 

synthetic minor or title V permits.

Response: We appreciate the commenter’s insight. We recognize that changing the definition of 

associated equipment to exclude all storage vessels as opposed to only storage vessels with the 

potential for flash emissions, may cause some facilities that were area sources to become major 

sources. These facilities may have additional permitting requirements at the state level, which 

may increase the burden on state regulatory agencies. In the ICR for the final rule (available in 

the docket along with the Supporting Statement), we took into account the additional burden on 

state agencies for area sources that subsequently become major sources.

Comment: Two commenters (4192, 4246) suggest revising the definition of “produced water” 

by deleting the words, “...after extraction” to eliminate confusion between extraction from the 

well from extraction from a cryogenic unit.

Response: The provision to which the commenter recommended revision was not reopened for 

notice and comment in our proposed rule. The requested revision is therefore outside the scope 

of this rulemaking.

Comment: Two commenters (4246, 4263) state that the EPA should clarify that the definition of 

BTEX includes isomers of xylene because total xylene is represented by three isomers referred to 

as meta- (m-xylene) para- (p-xylene) and ortho- (o-xylene) xylene.

Response: We direct the commenters’ attention to Table 1 of the existing rule which lists these 

isomers of xylene.

Comment: One commenter (4266) maintains that the following changes are needed to clarify 

terminology related to glycol dehydrators. In the NESHAP boiler definition, the commenter 

recommends that the rule must clarify that glycol reboilers are not boilers. Also, the commenter 

and one other commenter (4263) recommend that the rule should clarify that condensers which 

are part of a glycol system prior to a control device should not be considered control devices. 

According to the commenters, the EPA uses the term “condenser” multiple times in the rule 

when describing control devices and requirements. The commenters note that it is not uncommon 

for a condenser on a dehydrator vent stream to precede a flare or other combustion device. The 

commenters explain that a key purpose of this condenser is to remove water vapor. Since the 95 

percent HAP emission reduction is met by the flare or combustion device, the commenter states

that it is not reasonable to consider the condenser as a control device in this situation and require 

all the associated monitoring, recordkeeping, and reporting requirements. The commenter 

requests that only condensers that are the final control device, or condensers used to help achieve 

the 95 percent control efficiency, be classified as control devices. 
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Response: While we appreciate the commenters’ insight, this issue was not raised during 

proposal and represents more than an administrative change, so we are unable to address it in this 

action.

Comment: One commenter (4246) states that many of the revisions to the control device 

requirements of §63.771 apply to equipment that is currently required. The commenter contends 

that the proposed revisions fail to specify when these requirements are to be applied. The 

commenter recommends that the EPA should revise the proposed rule to indicate new 

performance testing requirements only apply to control equipment installed following the 

effective date of this rule.

Response: We have revised §§63.772(e)(3)(vi)(A) and 63.1282(d)(3)(vi)(A) to specify that a 

control device installed prior to August 23, 2011 has until 3 years after the publication date of the 

final rule in the Federal Register to either conduct a performance test on the control device or 

replace it with a manufacturer tested unit.

Comment: Commenter (4263) states that in the nomenclature for Equation 1 in §63.765, the 

units for the BTEX emission limit are not properly defined. The commenter recommends 

changing equal sign (=) to hyphen (-).

Response: We appreciate the commenter’s thorough review and have made appropriate 

corrections in the final rule. 

Comment: One commenter (4266) notes that the EPA makes no provision in either subpart HH 

or subpart HHH to limit applicability to either one or the other of the rules. The commenter 

claims that many of the provisions in the two subparts overlap with one another; therefore the 

EPA must clarify applicability to reduce confusion, duplicative requirements and reporting.

Response: Subpart HH applies to sources in the oil and natural gas production sector, and 

subpart HHH applies to sources in the natural gas transmission and storage sector. The point of 

custody transfer where natural gas exits the natural gas processing plant defines the point at 

which subpart HH provisions no longer apply, and the provisions of subpart HHH apply. We 

believe that the final rule provides sufficient clarification as to which rule applies to each 

emission source.

3.6 Miscellaneous Comments on NESHAP Amendments

Comment: One commenter (4174) states that the EPA should not impose the proposed 40 CFR 

63 subparts HH and HHH provisions for facilities located over water bodies and/or located in the 
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wetland areas of Louisiana as there is no "public" to be exposed in these remote areas. The 

commenter states that emission reductions have already occurred, if the facility was subject, due 

to the existing rules. The commenter further states that additional requirements and costs to add 

facilities to often "space-limited" platforms are not justified.

Response: We have no authority under the CAA to make such an exemption.

Comment: One commenter (4320) states that §63.772(e)(1) implies that control devices are 

exempt from testing for all affected sources except small dehydrators, which puts the largest 

burden and focus on the smallest sources. The commenter states that it does not appear that 

condensers that are part of glycol systems qualify as emission control devices. 

Response: We disagree with the commenter’s conclusions. Section 63.772(e) (i) – (e)(vi) lists 

specific parameters under which control devices are exempt from the requirements to conduct 

performance tests and design analyses. The commenter provides no rationale for the comment 

regarding condensers as part of glycol systems qualifying as emission control devices.

Comment: One commenter (4320) states that they spent the short duration of the comment 

period evaluating the manpower required to comply with the proposed NSPS and NESHAP rules 

and created an organized and accurate prediction of the first year and ongoing labor burden 

created by the rule proposals. According to the commenter, the first year effort to comply with 

the rules, as proposed, is believed to require at least 3 man-years. Ongoing effort, according to 

the commenter, after the first year, is expected to exceed 1 man-years per year. The commenter 

expressed hope that the EPA will consider making the changes proposed in this letter and in 

other comments. 

The commenter (4320) states that they already have much of the capital emission reduction 

technology already built into its ongoing operations. The commenter states that the compliance 

resource demand is where the commenter will experience the greatest impact from this 

rulemaking. Aside from the labor burden cost, the commenter states that they will also be 

required to install parameter monitoring instrumentation and software and conduct a significant 

amount of emission testing if the rules are not changed.

According to the commenter (4320), new instrumentation and software costs are expected to 

exceed $650,000 the first year and will likely exceed $200,000/year for successive years. 

Likewise, the commenter estimates that testing in the first year will approach $850,000 the first 

year and will be approximately $250,000/year for successive years.

The commenter (4320) claims that they already conducts the majority of the emission reduction 

measures required by the proposed rules. According to the commenter, the costs described above 
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are created by activities that are required to "prove" compliance. The commenter states that they 

believe there are much more efficient ways to adequately demonstrate compliance, as detailed 

throughout their comments.

Response: We believe that the final rule requires the minimum amount of compliance resources 

that are necessary to demonstrate compliance. We direct the commenter to the discussion of the 

cost impacts of the final rule in section XI of the final rule preamble.

Comment: One commenter (4191) recommends that a 500 parts per million leak rate be added 

to the section regarding closed-vent system requirements, as is used in existing closed vent 

system requirements for glycol dehydrators subject to subpart HH. 

Response: The commenter is referring to the requirement in §63.771(c)(2) that closed-vent 

systems must be designed and operated with no detectible emissions. This paragraph was not 

part of the changes in the August 23, 2011 proposal; therefore, no substantive changes have been 

made to this paragraph in the final rule.
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4.0 Cost, Environmental, Energy and Economic Impacts

4.1 Economic Impacts

Comment: Several commenters (2245, 3528, 3350, 4160, 4168, 4209, 4215, 4231, 4245, 4254, 

4255, 4267) believe that the proposed rules are too burdensome and would harm the fragile U.S. 

economy by diverting resources into compliance and away from production. The commenters 

often indicate that this will suppress domestic production and increase reliance on foreign 

sources of energy. In contrast, one commenter (4240) counters that industry growth and rigorous 

clean air regulations can go hand in hand.

Two commenters (4231, 4254) state that a Small Business Administration report shows that 

regulations cost American businesses $1.75 trillion annually, about $280 billion from 

environmental regulations. The commenters believe that at a time of slow economic growth and 

high unemployment, much of those regulatory resources would be better spent invested in a 

productive capacity to grow jobs and the economy rather than compliance with low-benefit 

regulations. One of the commenters (4254) adds that small businesses play an especially 

important role in the oil and gas industry, where they take the risks and lead on innovative 

methods.

One commenter (2245) states that for the foreseeable future, the cornerstone of an effective U.S.

climate change policy and energy policy will be natural gas. The commenter asserts that given 

the precarious state of the national economy, it is unjustifiable to increase the cost of delivering 

natural gas. Another commenter (4215) states that the ONG sector is a major source of domestic 

jobs, and that the sector is depended upon by the manufacturing sector, home heating and electric 

utilities, the merchant power sector and, ultimately, America’s consumers.

Five commenters (3528, 4168, 4255, 4267, 4269) believe that the proposed rules will cause some 

wells to become uneconomic, with negative economic impacts and little environmental benefit. 

One commenter (3528) believes that placing additional administrative regulations on marginally 

economic oil and gas wells may cause some wells to be shut-in, reducing energy production and 

eliminating jobs, with little to no environmental benefit. The commenter adds that the cost of 

energy production will rise as a result of complying with these new regulations. One commenter 

(4267) notes that the State of New Mexico receives $2.9 billion in taxes annually from oil and 

gas, and states that every well that is not drilled and every marginal well that is shut in as a result 

of this regulation is an immediate loss to the state.

One commenter (4168) states that implementation of the proposed rules will likely render many 

oil and gas exploration, production and development projects uneconomic, which will diminish 

oil and gas revenues received by the State of Texas and have a negative impact on funding for 
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lower (grades K through 12) and higher (University of Texas and Texas A&M University 

Systems) education in Texas. The commenter believes that given the current economic 

conditions, every effort should be made to enhance revenue sources for public education in a 

fiscally and environmentally reasonable manner.

One commenter (3350) indicates that because the NSPS applies only to new natural gas wells, 

the rule may cause operators to undertake fewer projects. The commenter adds that the rule 

creates an inadvertent economic incentive for sources to continue using outdated, less-efficient 

equipment rather than incurring new costs and regulations to change.

In a dissenting view, one commenter (4240) states that the experience in Wyoming and Colorado 

shows that the ONG sector has grown in the presence of strong standards. The commenter 

indicates that his organization has examined several metrics illustrating trends in the oil and 

natural gas sectors which show that both Colorado and Wyoming have experienced growth in 

those industries while meeting state air regulations, and in some cases, higher growth than both 

the U.S. overall and other states without such regulations. The commenter adds that while this 

analysis does not quantify the impact of the regulations, (since it is not known what sort of 

growth these states might have seen in their absence), it does provide evidence that industry can 

thrive in the presence of these regulations. Based on the analysis, the commenter concludes that 

the EPA’s proposed rules are not likely to impair the industry’s growth; they will, instead, reduce 

the environmental impacts of that growth.

Response: The EPA does not believe that the final rules are overly burdensome or will harm the 

U.S. economy. We agree with the comment indicating that the experience in Wyoming and 

Colorado illustrates that the ONG sector can thrive in the presence of environmental regulations.

For the final rule, we carefully considered the comments received on all aspects of the proposed 

rules. While our approach and methodology for establishing the final standards remained the 

same, we made several changes to make the final rules 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. These changes are discussed in more detail in the preamble to 

the final rule and in the other sections of this document. The final 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.

We used the National Energy Modeling System (NEMS) to estimate the impacts of the final 

NSPS on the U.S. energy system. The NEMS is a publically available model of the U.S. energy 

economy developed and maintained by the Energy Information Administration of the U.S. DOE 
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and is used to produce the Annual Energy Outlook, a reference publication that provides detailed 

forecasts of the United States energy economy.

We disagree with the commenters’ belief that the rules will “suppress domestic production and 

increase reliance on foreign sources of energy” or will cause operators to drill fewer wells. Using 

NEMS, EPA estimates that the number of successful gas wells drilled in 2015 will increase by 

66 (0.35 percent) and the number of successful oil wells will be unchanged under the NSPS 

when compared to the baseline. Additionally, domestic natural gas production and domestic oil 

production will remained unchanged in 2015, when compared to the baseline. Net imports of 

natural gas and oil will remain unchanged in 2015, when compared to the baseline.

We agree with the commenter who states that the oil and natural gas sector “is depended on by 

the manufacturing sector, home heating and electric utilities, the merchant power sector, and 

ultimately, America’s consumers.” We note that using NEMS, EPA estimates that delivered 

natural gas prices are expected to remain unchanged in the residential, electric power, and 

transportation sectors in 2015, when compared to the baseline. The EPA estimates small 

increases of 0.12 percent and 0.20 percent in the commercial and industrial sectors in 2015, 

respectively, when compared to the baseline.

Emission controls required by the final rules 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 (i.e., storage vessel controls) also captures 

saleable condensates. The revenues from additional natural gas and condensate recovery are 

expected to offset the costs of implementing the final rules. The revenue from additional natural 

gas product recovery will also lead to increased revenues from taxes and royalties.

After considering the economic impact of the final rules on small entities for both the NESHAP 

and NSPS, EPA’s analysis indicates that these rules will not have a significant economic impact 

on a substantial number of small entities (or “SISNOSE”). The number of significantly impacted 

small businesses is unlikely to be sufficiently large to declare a SISNOSE. Our judgment in this 

determination is informed by the fact that many affected firms are expected to receive revenues 

from the additional natural gas and condensate recovery engendered by the implementation of 

the controls evaluated in this RIA. As much of the additional natural gas recovery is estimated to 

arise from completion-related activities, we expect the impact on well-related compliance costs 

to be significantly mitigated. 

For more information on the estimated economic, small entity, and energy effects, please refer to 

the economic impact analysis for the final rules. The analysis is available in the RIA, which is in 
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the public docket for the rulemaking. The RIA describes in detail the empirical basis for the 

EPA’s assumptions and characterizes the various sources of uncertainties affecting the estimates.

Comment: One commenter (2245) states that the administrative costs of the proposed rules 

cannot be justified by the projected VOC reductions from interstate pipelines and storage 

facilities. According to the commenter, the threatened capital and operating costs of the proposed 

standards are substantial for this sector, but the threatened administrative costs — monitoring, 

accumulating monitored data, preparing reports, maintaining archives and facilitating internal or 

external audits — are even more daunting and unnecessary. The commenter contends that 

interstate natural gas pipeline and storage companies already have powerful commercial 

incentives to avoid losses in transit, and they have long been addressing the very issues covered 

in the proposed operating standards through current practices. 

Response: The EPA believes that the final rules for the transmission and storage segment of the 

ONG sector appropriately balance the costs imposed with the benefits achieved. We note that the 

final NSPS makes clear that this segment is not subject to the standards for compressors or 

pneumatic controllers, so the final rule will impose no control or administrative costs for such 

equipment at facilities in the transmission and storage segment. The final NSPS does apply to 

storage vessels in this segment, but the final rule bases applicability of the control requirements 

on VOC emissions at a level equal to or greater than 6 tpy which we have found to be cost 

effective. In addition, the final rule has streamlined the MIRR requirements for storage vessels to 

reduce the associated burden for sources. See the related sections of this document for more on 

the changes that have been made for the final rules.

Comment: Four commenters (2245, 3350, 4209, 4236) question whether the EPA has properly 

addressed the requirements of the RFA, Executive Order 12866 and/or Executive Order 13563.

One commenter (2245) believes that imposing the proposed rule on natural gas transmission and 

storage contravenes Executive Order 13563, which directs Federal agencies to propose or adopt a 

regulation only upon a reasoned determination that its benefits justify its costs, and to tailor their 

regulations to impose the least burden on society (including, to the extent practicable, the costs 

of cumulative regulations). The commenter contends that contrary to Executive Order 13563, 

imposing the proposed regulations on interstate natural gas pipeline and storage companies 

would reduce VOCs emissions by a minimal amount while imposing huge costs. 

One commenter (4209) believes that the proposed rule will have negative impacts on all oil and 

gas operators, especially small operators/businesses that operate crude oil and natural gas 

marginal wells, and that the proposed rule is fundamentally inconsistent with efforts to protect 

and enhance national security and increase domestic energy production. The commenter does not 
376

believe that the EPA has accurately and thoroughly addressed the RFA or Executive 

Orders 12866 and 13211.

One commenter (3350) contends that the EPA has presented no evidence that it evaluated the 

costs and benefits of regulatory alternatives, such as positive incentives to achieve the desired 

result, as it is obligated to do so under Executive Order 12866. The commenter states that 

Executive Order 12866 directs that “each agency shall identify and assess available alternatives 

to direct regulation, including providing economic incentives to encourage the desired behavior, 

such as user fees or marketable permits, or providing information upon which choices can be 

made by the public.”

One commenter (4236) states that EPA’s RFA certification “that the rule will not have a 

significant economic impact on a substantial number of small businesses, small organizations, 

and small governmental jurisdictions” is based on inaccurate or unsupported cost estimates (as 

discussed in this section and elsewhere in this document). On this basis, the commenter asserts 

that the EPA should reevaluate its compliance with the RFA using accurate estimates. 

Without mentioning the RFA, two other commenters (4356, 4472) state that the EPA has 

underestimated the potential impact on small businesses and has failed to fully consider the 

impacts on stripper oil wells or marginal gas wells in the State of Texas, where more than 

75 percent of all oil wells fall in the stripper well category. One of the commenters (4356) 

believes that the costs for controls and reporting and recordkeeping will disproportionally impact 

small businesses in Texas and across the nation. 

The other commenter (4472) asserts that by lumping them in with all types of small businesses, 

the proposal RIA’s economic impact analysis failed to adequately demonstrate the full impact on 

the category of small businesses whose sole business is the operation of stripper oil wells and 

marginal gas wells, in Texas and many other states with a high percentage of stripper and 

marginal wells and a high percent of small businesses. The commenter disagrees with the results 

of the EPA’s analysis of energy impacts for the proposal, and asserts that imposition of the costs 

of additional regulation on small businesses and stripper/marginal well facilities, without fully 

analyzing the potential impacts to this group (which produces 30 percent of Texas' crude oil) and 

considering the increased costs and delays likely to result because of the scarcity of equipment 

and personnel for hydraulic fracturing treatment of natural gas wells, is likely to result in a 

decrease in domestic oil and gas production.

Response: The EPA believes that it has properly addressed the requirements of the RFA, 

Executive Order 12866 and Executive Order 13563. Our analyses are detailed in the revised RIA 

for the final rule, including an analysis of impacts on small businesses, which is available in the 

public docket for the rulemaking. The RIA describes in detail the empirical basis for the EPA’s 
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assumptions and characterizes the various sources of uncertainties affecting the estimates. The 

RIA shows the results of the cost and benefits analysis for these final rules carried out under 

Executive Order 12866 and Executive Order 13563.

Executive Order 12866 indicated that agencies should consider alternatives to direct regulation 

“to the extent permitted by law and where applicable.” In the proposal for this rule, EPA did 

consider three regulatory alternatives with varying standards. Additionally, EPA views the 

proposed rules as complementary to existing voluntary programs, such as the Natural Gas STAR 

program.

For the final rule, the EPA revised its cost estimates based on the comments received and carried 

out a new analysis of the impacts on small businesses. Based on our analysis of impacts on small 

businesses, the EPA certifies that the rule will not have a significant economic impact on a 

substantial number of small entities. For the final NSPS, we 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, when revenue from additional natural gas product 

recovered is not included, we estimate that 123 of the 127 small firms analyzed (97 percent) are 

likely to have impacts less than 1 percent in terms of the ratio of annualized compliance costs to 

revenues. Meanwhile, four firms (3 percent) are likely to have impacts greater than 1 percent. 

Three of these four 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 11 of the 35 firms (31 percent) that own 

potentially affected facilities 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, none are likely to have impacts of greater than 1 percent in terms of the ratio of 

annualized compliance costs to revenues. 

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, 132 of the 136 small firms (97 percent) in 

the sample are likely to have impacts of less than 1 percent in terms of the ratio of annualized 

compliance costs to revenues. Meanwhile, four firms (3 percent) are likely to have impacts 

greater than 1 percent. Three of these four firms are likely to have impacts greater than 3 percent. 

When revenues from additional natural gas product sales are included, 136 small firms (100

percent) in the sample are likely to have impacts of less than 1 percent. 
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As discussed previously, our analyses show that domestic production of crude oil and natural gas 

is not expected to change by 2015 under the final rules. As noted in the previous response, we 

have revised the final NSPS to clearly indicate which standards in the rule do and do not apply to 

sources in the transmission and storage segment and to streamline the MIRR requirements for 

those affected facilities in this segment.

Given a large fraction of domestic oil and natural gas production is produced from older and 

generally low productivity wells, the EPA examined whether the requirements might present 

impediments to owners and operators of older equipment. The NSPS is a standard that applies to 

new or modified sources. While the requirements may apply to modifications of existing 

facilities, it is important to discuss well completion-related requirements aside from other 

requirements in the rules.

Excluding well completion requirements from the cost estimates, the non-completion NSPS and 

NESHAP requirements (related to equipment leaks at processing plants, reciprocating and 

centrifugal compressors, pneumatic controllers, glycol dehydrators, and storage vessels) are 

estimated to require about $14 million in annualized engineering costs. The EPA also estimates 

that the annualized costs of these requirements will be partly by revenues expected from natural 

gas recovery. The EPA does not expect these requirements to disproportionately affect producers 

with older equipment.

Meanwhile, the REC and emissions combustion requirements in the final NSPS relate to well 

completion activities at new hydraulically fractured natural gas wells and existing wells which 

are recompleted after being fractured or re-fractured. These requirements constitute the bulk of 

the expected engineering compliance expenditures (about $160 million in annualized costs) and 

expected revenues from natural gas product recovery (about $160 million in revenues, annually). 

While age of the well and equipment may be an important factor for small and large producers in 

determining whether it is economical to fracture or re-fracture an existing well, this equipment is 

unlikely to be subject to the NSPS. 

Comment: Five commenters (3350, 3529, 3350, 4231, 4254) state the EPA assumes that only a 

small percentage of facilities currently capture gas and takes credit for the full economic benefit 

of something that many companies are already doing where the operational conditions allow. 

The commenters state it would make no sense for companies to ignore technology that allows 

them to earn higher profits through efficiency. Two commenters (4228, 4254) state that the EPA 

assumes that industry does not flare or control methane emissions unless required by law. The

commenters assert that their company is already flaring most of its methane emissions. The 

commenters state that, based on the methane capture incentives from programs such as the 

Mandatory GHG Reporting rule and other incentive programs such as the EPA Natural Gas 

STAR program, capturing methane is much more common and even profitable than recognized 
379

by the EPA. The commenters further claim that companies have adopted best practices and 

developed internal procedures to improve their application. Thus, according to the commenters,

incremental natural gas VOC emission reductions beyond current practices will be very small, 

and will be limited to the least cost-effective situations not already being implemented by 

industry for economic reasons. Three commenters (4228, 4241, 4251) state that the EPA 

emission reduction analysis for production sector pneumatic controllers does not consider the 

current industry practice of installing low bleed devices whenever possible and consequently 

overestimates the VOC content of emissions from pneumatic controllers in the processing 

segment by an order of magnitude. Three other commenters (4215, 4231, 4254) state that the 

EPA is claiming a net savings of $29 million based on exaggerated estimates of methane 

emissions, taking credit for things that companies are already doing, and not taking account of 

the sizeable costs of compliance. Other commenters (4160, 4245, 4269) state that the EPA 

incorrectly calculates emission reductions as if the industry is unregulated, but State permitting 

programs and SIPs already regulate most of these activities.

Response: The baseline emissions estimates in the RIA for natural gas well completions and 

other emissions sources takes into account emissions reductions conducted pursuant to State 

regulations covering these operations. Based on public comments and reports to the EPA's 

Natural Gas STAR program, the EPA recognizes that some producers conduct well completions 

using REC techniques voluntarily for economic and/or environmental objectives as a normal part 

of business. To account for emissions reductions and costs arising from voluntary 

implementation of pollution controls the EPA used information on total emission reductions 

reported to the EPA by partners of the EPA Natural Gas STAR. This estimate of this voluntary 

REC activity in the absence of regulation is also included in the baseline. More detailed 

discussion on the derivation of the baseline is presented in a technical memorandum in the 

docket, as well as in the RIA.

Comment: One commenter (4160) states that the EPA has not quantified the jobs impacts of 

these regulations. The commenter asserts that the majority of industry players are small 

businesses with little flexibility to react to regulatory costs except by reducing the labor force.

Response: In the RIA, the EPA presented estimates of labor requirements related to the 

compliance actions of the affected entities within the affected sector, but were unable to estimate 

any potential changes in labor outside of the oil and natural gas sector. The RIA analysis 

estimates the employment impacts due to the installation, operation, and maintenance of control 

equipment, as well as employment associated with new reporting and recordkeeping 

requirements. No estimates of the labor used to manufacture or assemble pollution control 

equipment or to supply the materials for manufacture or assembly are included because the EPA 

does not currently have this information. The likelihood of additional natural gas recovery is an 

important component of the market response to the rule, as it is expected that this additional 
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natural gas recovery will reduce the price of natural gas. Because of the estimated fall in prices in 

the natural gas sector due to the final NSPS, prices in other sectors that consume natural gas are 

likely drop slightly due to the decrease in energy prices. This small production increase and price 

decrease may have a slight stimulative effect on employment in industries that consume natural 

gas.

Comment: According to commenter (4240), the natural gas price that the EPA uses to calculate 

the direct financial benefits of the proposed rule are far lower than all other projections. The 

commenter states the EPA must use a realistic gas price in its analysis to accurately value the 

savings that the standards will achieve.

Response: The EPA appreciates that the commenter compiled and shared natural gas price 

forecasts from multiple sources. Our $4/Mcf lower 48 state wellhead natural gas price 

assumption is drawn from the commonly referenced Annual Energy Outlook 2011 forecast. As 

the EPA using the US EIA NEMS modeling system in its impacts analysis, we chose to retain 

the $4/Mcf wellhead price to remain internally consistent as well as to rely upon a commonly 

referenced, publically available modeling source.

Comment: One commenter (4240) states that industry’s failure to voluntarily adopt all of the 

EPA’s proposed controls does not indicate that the cost of control is not reasonable, or that the 

control in question is not correctly included as BSER. The commenter adds that reasons for nonadoption may include that environmental projects do not meet internal hurdle rates to compete 

with core business projects for available capital. Thus, the commenter states, companies may 

forego even profitable projects in favor of, for instance, new well construction, in the absence of 

federal regulation requiring them to take action. The commenter adds that market failures such as 

firms with structure that does not incentivize managers to undertake measures; managers may be 

risk averse or resistant to new technologies, or lack of information on cost-effective measures. 

The commenter states that a large number of natural gas companies, especially small to midsize 

ones, have yet to update their outmoded practices and embrace a culture of efficiency and 

corporate responsibility. The commenter asserts that companies taking part in the Natural Gas 

STAR program represents less than 10 percent of the companies in the sector.

Response: The EPA agrees with the commenter that these may be reasons that industry does not 

voluntarily adopt cost-effective environmental controls. 

Comment: One commenter (3350) notes that the outcome of the cost/benefit analysis for the 

rule is highly dependent on the cost assumed for natural gas, which is difficult to estimate 

accurately because historically it has fluctuated significantly. Although some have argued that 

the current abundant supplies will mitigate such price swings, the commenter asserts that it is 

improper to regulate based on the assumption that producers will maintain a constant state of 
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natural gas production. The commenter states that many of the resources for the natural gas and 

oil production sectors are exchangeable (equipment and labor), and at current pricing levels a 

shift away from natural gas toward oil is already underway with more companies drilling for oil 

than natural gas for the first time since 1995. The commenter contends that more stringent 

regulations on the natural gas industry could have an unintended consequence of raising 

residential energy costs from natural gas by driving up the production of oil, while allowing 

demand for natural gas to catch up with supply. The commenter adds that this also could affect 

other EPA regulations, such as the Boiler MACT, noting that a switch to natural gas may be the 

only option for plants faced with adding expensive control technologies, fuel switching or 

closure.

Response: The EPA agrees with the commenter that the outcome of the cost/benefit analysis is 

highly dependent on the cost assumed for natural gas. For purposes of our analyses, we assume a 

price of $4/Mcf at the wellhead.

Because 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 -$24 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 breakseven from an estimated engineering costs perspective is around $3.79/Mcf. A $1/Mcf change in 

the wellhead natural gas price leads to a $43 million change in the annualized engineering costs 

of the final NSPS. Consequently, annualized engineering costs estimates would increase to about 

$29 million under a $3/Mcf price or decrease to about -$58 million under a $5/Mcf price. For 

further details on this sensitivity analysis, please refer the RIA for this rulemaking located in the 

docket. 

As discussed previously, we used NEMS to estimate the impacts of the final NSPS on the U.S. 

energy system. The analysis did not predict the kinds of price impacts suggested by the 

commenter. Rather, the analysis shows that domestic natural gas production and natural gas 

wellhead prices are expected to remain unchanged in 2015, the year of analysis. Additionally, we 

estimate that delivered natural gas prices will remain unchanged in 2015 in the residential, 

electric power, and transportation sectors, when compared to the baseline. We estimate small 

increases of 0.12 percent and 0.20 percent for the commercial and industrial sectors in 2015, 

respectively, when compared to the baseline. 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 
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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.

Comment: One commenter (4270) believes that the EPA lacks sufficient data to regulate the 

ONG sector at this time. The commenter contends that the emission factors used for compressors 

and pneumatic controllers are not valid, and that it is necessary to first enhance the accuracy of 

emission factors for these sources before proposing emission control strategies with unknown 

consequences. The commenter believes that the cost/benefit analysis is not valid because it is 

based on faulty assumptions. In addition, the commenter notes that the EPA clearly states that it 

lacks the data to provide credible health benefit estimates.

Response: The EPA disagrees that it lacks sufficient data to regulate the ONG sector at this 

time. We acknowledge that some commenters raised valid issues with some of the assumptions 

that we used at proposal. Accordingly, we carefully considered the comments on costs and 

emissions, reexamined our cost and emissions assumptions, revised them as appropriate and 

conducted new cost effectiveness and cost/benefit analyses for the final rules. The regulatory 

costs and emissions for the segments of the ONG sector are discussed, as relevant, in other 

sections of this document. The analyses carried out for the final rule are detailed in the RIA, 

which is available in the public docket for the rulemaking.

While the EPA is not able to quantify health benefits associated with the NSPS and NESHAP 

amendments, this does not imply that there are no health benefits of the rules. We expect that the 

avoided emissions will result in improvements in air quality and reduce health effects associated 

with exposure to HAP, ozone, and fine particulate matter (PM2.5).

Comment: Six commenters (3529, 4209, 4228, 4231, 4281, 4358) believe that the EPA’s 

analysis of costs and benefits did not adequately address the highly variable conditions in the 

industry, which can dictate different technical approaches and have varied economic 

consequences from basin to basin, and even between reservoirs within a basin. One commenter 

(3529) states that the RIA is flawed because it assumed that the industry is monolithic and one 

set of economic circumstances apply to the entire industry. Another commenter (4228) indicates 

that the cost-effectiveness analysis for production should be segregated for different produced 

gas streams, and that average compositions should not be applied industry-wide.

One commenter (4209) contends that oil and natural gas facilities vary significantly across the 

country, with drastic differences in the characteristics of the hydrocarbon liquids and gases 

produced, the volumes initially produced, the production volume drop-off rates, the formation 

pressures, the type and age of equipment at each facility, the economics of each well, the 

locations of wells (most are typically located in remote areas), the availability of infrastructure, 

the availability of consultants and equipment to support compliance efforts, and other like issues. 
383

The commenter implies that the EPA has not accounted for these variations in its risk and 

cost/benefit analysis. 

Another commenter (4281) contends that the EPA did not consider the unique nature of the ONG 

industry in its analyses, pointing out that this industry is different from most other industries in 

that most industries can design and construct a process unit in advance, and have significant 

control over all aspects of its operation, while an ONG operator does not have any control over 

the properties of the petroleum produced from the reservoir, such as composition, temperature, 

pressure and volume. 

Because of the wide variation in the characteristics of each operation, the commenter (4281) 

does not believe that the EPA’s model facility approach adequately described the industry. As an 

example, the commenter notes that the EPA documented that the VOC content in natural gas 

ranges from 0.0 to 52.72 percent by weight, selected a single average natural gas composition 

with VOC content of 18.28 percent by weight as the "average natural gas stream" and used this 

average natural gas stream to calculate cost-effectiveness and justify the selection of control 

options as BSER. The commenter contends that using this method causes the cost of control on 

gas containing low or no VOCs to approach an infinite cost per ton of VOC, which could never 

be considered to be cost-effective. The commenter recommends that the EPA set a de minimis 

VOC content level to exempt low-VOC gas streams to ensure that the control option selected as 

the NSPS would meet the cost-effectiveness criterion of BSER.

Response: The EPA understands that there is variability of gas composition from basin to basin, 

as well as within a single basin. We considered how a VOC threshold for wells would be 

implemented, and what kind of information owners and operators would need in advance of the 

completion operation. It is our understanding that the operators cannot know with certainty the 

composition of the well prior to completion. As a result, we believe a VOC threshold would be 

impossible to implement effectively and consistently and have not included such a provision in 

the final rule. However, we have improved the final rule by including a subcategory of “low 

pressure” wells that will remove over 85 percent of the coalbed methane wells (which may be 

relatively low in VOC content) that would be required to perform RECs.

Comment: One commenter (0604) states that it is the EPA’s duty to impose the Best Available 

Technology regardless of costs to the industry. 

Response: The EPA does not agree with the commenter’s characterization of the requirements 

of the CAA. The CAA specifies how the EPA is to determine the required level of control under 

NSPS and NESHAP programs, and neither is based on “Best Available Technology.” In 

addition, in some cases costs must be considered.
384

Section 111 of the CAA governs the NSPS program. In setting or revising a NSPS, CAA 

section111 (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 non-air quality health and 

environmental impact and energy requirements) the Administrator determines has been 

adequately demonstrated.” We refer to this level of control as the BSER. Note that under this 

regime, costs are clearly to be considered.

Section 112 of the CAA governs the NESHAP program. This is a two-stage program. In the first 

step, the required control level is referred to as the “maximum achievable control technology” or 

MACT. 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 average emission 

limitation achieved by the best-performing 12 percent of existing sources in the category or 

subcategory (or the best-performing 5 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 non-air quality health and 

environmental impacts and energy requirements. Thus, NESHAP standards set at the MACT 

floor cannot consider costs to the industry, but costs are to be considered when evaluating 

standards more stringent than the MACT floor. The MACT standards are to be revisited at least 

every 8 years to see if technology has advanced such that they should be made more stringent.

The second stage of the NESHAP program focuses on reducing any remaining “residual” risk 

according to CAA section 112(f). 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. 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). Thus, the Act does not allow the consideration of costs in setting the level 

of control that represents an ample margin of safety, but it requires consideration of costs to set a 

more stringent standard. 

Comment: One commenter (4222) indicates that the EPA's proposed economic model does not 

accurately reflect conditions in Alaska for return on investment. The commenter notes that most 

Alaskan natural gas sources north of the Brooks Range are stranded gas wells with no access to 

transportation, and there is not yet a traditional commercial market for natural gas on the Alaskan 
385

North Slope. The commenter adds that there may be additional costs that must be incurred in 

Alaska to develop the emissions capture and processing facilities, not to mention the necessary 

transport pipeline systems to make sale of the emissions to distant markets feasible and cost 

effective, if possible at all. The commenter also states that the volume of emissions recovery 

from hydraulically-fractured shale oil wells, which are the current prospects for Alaska, is 

expected to be less than in natural gas wells, and the payback for the capital improvements 

required by this proposed rule may never occur in Alaska as predicted in the RIA. 

Response: Although some wells drilled in crude oil formations may produce associated gas 

along with the oil, without a gas infrastructure present, the EPA does not have sufficient data on 

VOC emissions during completion of hydraulically fractured oil wells to set standards for these 

operations at this time. In the proposed rule, we briefly assessed well completions of 

hydraulically fractured oil wells and did not believe that either REC or a completion combustion 

device is cost-effective for reducing VOC emissions from such operations. We note, however, 

that this brief assessment of oil wells in the proposed rule was based on limited information at 

the time and that more information is needed for us to fully evaluate the VOC emissions and 

control options for these operations. As a result, the final rule will not affect drilling of oil wells, 

and we believe the final rule will satisfactorily address the commenter’s concerns about cost 

effectiveness of oil wells that may have been raised by uncertainty of treatment of oil wells in the 

proposed rule.

Comment: One commenter (4240) states that the EPA’s standard-setting duties and authority are 

derived under section 111 of the CAA, and its decision must be made within the confines of that 

authority – although the EPA must consider the costs of control, it may not base its standardsetting on a broad-ranging cost/benefit analysis. Thus, according to the commenter, the RIA 

prepared by the EPA under Executive Order 12866 may inform the standard-setting process, but 

cannot provide the direct basis for the standards and does not “create any right or benefit, 

substantive or procedural, enforceable at law or equity by a party against the United States....” 

(Executive Order 12866, section 10). 

Response: The EPA agrees with the commenter. The commenter’s description of the statutory 

requirements for the standard-setting process under the NSPS program governed by CAA 

section 111, and the relationship of the RIA prepared pursuant to Executive Order 12866 to that 

process, is correct.
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4.2 Estimated Benefits

4.2.1 Estimated Health Benefits

Comment: Two commenters (4231, 4254) take note of the EPA’s statement in the preamble that 

it did not have time to do air quality monitoring to support the rule. One of the commenters 

(4231) asserts that lack of time does not mean proper procedures can be dismissed; it means the 

rule must be commensurate with the science available at the time of the rulemaking. 

One commenter (4254) asserts that a consent decree cannot foreclose procedural requirements an 

agency is required to take, and that air quality monitoring is necessary to properly justify and 

inform the rule. The commenter states that because it does not have the necessary data to support 

the rule without such monitoring, the EPA should work to produce such data for future 

rulemaking. The commenter believes that the artificial time-frame imposed by the consent decree 

does not mean that the EPA can impose NSPS that have not been adequately demonstrated; the 

EPA must follow the proper procedure and meet statutory requirements to justify and support the 

rule with the best available data.

Response: Both the NSPS and NESHAP are being promulgated based on the technology-related 

requirements of the Act, not the health-related requirements. Thus, the decisions made by the 

EPA for this rulemaking are not dependent on the health benefits that will be achieved, and it is 

not necessary to quantify those benefits to proceed. Nevertheless, we have evaluated the costs 

and benefits of the final rules as required by Executive Orders 12866 and 13563 as best we can 

given time and budget constraints.

As discussed in greater detail in the preamble to the final rule, the NSPS actions that the EPA is 

taking are pursuant to sections 111(b)(1)(B) and 111(a)(1) of the CAA. Section 111(b)(1)(B) of 

the CAA requires the EPA to “at least every 8 years review and, if appropriate, revise” existing 

NSPS. There are existing NSPS for the ONG sector at 40 CFR subparts KKK and LLL, and this 

NSPS rulemaking is the culmination of the review of these NSPS pursuant to CAA 

section 111(b)(1)(B) and a consent decree resulting from litigation to force such a review. 

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 non-air quality health and environmental impact and energy requirements) the 

Administrator determines has been adequately demonstrated,” which we refer to as the “best 

system of emissions reduction” or BSER. Notably, the statute requires that these standards be 

based on the level of control that can be achieved in a cost-effective manner, taking certain other 

specified considerations into account. The health benefits of the reduction in air pollution are not 
387

among the considerations prescribed by the statute. Thus, the health benefits are not 

determinative of the standards, and we do not believe that we are required to quantify the health 

benefits that will be achieved before we can promulgate the final NSPS.

Similarly, as also discussed in greater detail in the preamble to the final rule, the NESHAP 

actions that the EPA is taking are pursuant to the technology-based standard-setting requirements 

of section 112(d) of the Act, not the health-related requirements of section 112(f). Under CAA 

section 112, the NESHAP program is a two-stage program. In the first stage, the required control 

level is referred to as the “maximum achievable control technology” or MACT. The MACT 

“floor” is the minimum control level allowed for MACT standards promulgated under CAA 

section 112(d)(3). 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 average emission limitation achieved by the best-performing 12 percent of existing sources in 

the category or subcategory (or the best-performing 5 sources for categories or subcategories 

with fewer than 30 sources). Section 112(d)(6) of the Act requires us to review existing 

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. 

The second stage of the NESHAP program focuses on reducing any remaining “residual” risk 

according to CAA section 112(f). 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. 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 minimum level at which the standards must be set. This NESHAP rulemaking is the 

culmination of the review of existing MACT standards for the ONG sector at 40 CFR 

subpart HH and subpart HHH pursuant to CAA sections 112(d)(6) and 112(f) and a consent 

decree resulting from litigation to force such a review.

As a result of our review under section 112(d)(6), we have revised 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. Our review under section 112(f)(2) did not result in revision to the standards 

because we determined through dispersion modeling that the MACT standards provide an ample 

margin of safety to protect public health. Thus, the final NESHAP were set as prescribed by the 

CAA, and it is not necessary to quantify the health benefits of the final rules to do so.

The EPA disagrees that an inability to quantify the benefits of a rule implies a flaw in the 

rulemaking process. These rules are expected to achieve important HAP and criteria pollutant 

benefits, but monetization of these benefits is limited by currently available data and methods.
388

For example, monetization of the HAP benefits of reductions in cancer incidences requires 

several important inputs, including central estimates of cancer risks, estimates of exposure to 

carcinogenic HAP, and estimates of the value of an avoided case of cancer (fatal and non-fatal). 

It is likely that the commenter confused monitoring data with modeling data. The EPA 

acknowledges that modeling data to support the quantification of ozone benefits was unavailable 

for this sector. However, it was the lack of data on the location of new well completions, not 

timing, that was the main barrier to modeling. Instead, we provide a qualitative analysis of the 

health effects associated with the HAP and criteria pollutants anticipated to be reduced by these 

rules. Our limited ability to monetize these benefits does not indicate that they are non-existent 

or less important.

The RIA may inform the standard-setting process, but it does not replace the statutorily 

prescribed requirements for setting standards in the NSPS and NESHAP programs. Under 

Executive Order 12866, agencies are required, to the extent permitted by law, “to assess both the 

costs and the benefits of the intended regulation and, recognizing that some costs and benefits are 

difficult to quantify, propose or adopt a regulation only upon a reasoned determination that the 

benefits of the intended regulation justify its costs.”

Comment: Five commenters (3350, 4231, 4246, 4251, 4254) contend that it is inappropriate that 

the analysis carried out by the EPA is based on captured emissions of methane, which is not 

covered by the regulations. According to one commenter (4254), although the regulations are for 

the purported purpose of controlling VOCs and HAPs, the EPA does not articulate the benefits of 

controlling either VOCs or HAPs, but only claims benefits from methane capture. 

One commenter (3350) states that the EPA claims that the reductions in methane will yield about 

$1.6 billion in public health and environmental benefits; however, because methane is not a VOC 

or air toxic—the two types of emissions targeted by the proposed revisions—the decision to cite 

it as a co-benefit is questionable. Even if the co-benefits of methane reductions are cited, the 

commenter believes that the EPA’s analysis is flawed because no sense of proportion or the 

scope of its impact is provided. The commenter contends that the EPA should determine the 

impacts of methane reductions by modeling the temperature impact that the rule would have, and 

that the failure to do so is arbitrary and capricious. The commenter asserts that by reducing U.S. 

GHG emissions by 1 percent, the rule would have a negligible impact on climate.

Response: The EPA disagrees that co-benefits should be excluded from consideration of the 

benefits anticipated by this rule. Accounting for ancillary benefits is standard practice in benefitcost assessment since these benefits are a consequence of the rule, regardless of the rule’s 

intended purpose. As such, the EPA estimates all of the anticipated costs and benefits associated 

with a regulatory action, to the extent feasible, for the purpose of determining the likely impacts, 

not to justify an action. This rule is expected to achieve substantial emission reductions, and 
389

these co-benefits are thus an important category to consider. Our treatment of quantified benefits 

and co-benefits follows guidance set by OMB Circular A-4 and EPA’s Guidelines for Preparing 

Economic Analyses (2010). 

Comment: One commenter (3350) claims that the EPA’s claims of positive health benefits lack 

supporting data, noting that the EPA admits that it is not able to provide credible health benefit 

estimates for the reduction in exposure to HAP, ozone and PM2.5 with the available data. The 

commenter states that supportive data prior to proposing new regulations should be prerequisite, 

and the mere assertion that there will be health benefits is insufficient proof. The commenter 

quotes Executive Order 12866, which states that “each agency shall base its decisions on the best 

reasonably obtainable scientific, technical, economic, and other information concerning the need 

for, and consequences of, the intended regulation,” while Executive Order 13563 states that the 

regulatory system must be based on the “best available science.” The commenter asserts that the 

EPA’s claim of health improvements without credible health benefit estimates violates the spirit

of Executive Orders 12866 and 13563. The commenter concludes that because the EPA does not 

quantitatively assess the health effects, it is prima facie evidence that these regulations will not 

create positive health benefits.

Response: The EPA disagrees with the commenter’s interpretation of these executive orders. In 

fact, both these executive orders clearly direct agencies to consider benefits that are difficult to 

quantify. Specifically, EO 12866 states that “[c]osts and benefits shall be understood to include 

both quantifiable measures (to the fullest extent that these can be usefully estimated) and 

qualitative measures of costs and benefits that are difficult to quantify, but nevertheless essential 

to consider.” EO 13563 states that “[w]here appropriate and permitted by law, each agency may 

consider (and discuss qualitatively) values that are difficult or impossible to quantify, including 

equity, human dignity, fairness, and distributive impacts.” If the EPA were able to fully quantify 

all of the benefits of this rule, the net benefits would be even higher than we have estimated.

The EPA also disagrees that an inability to quantify the health effects implies that there are no 

positive health benefits. The commenter provides no evidence that the emissions reduced by 

these rules do not contribute to health and ecosystem effects. The categories of benefits 

described in the Regulatory Impact Analysis are supported by numerous peer-reviewed scientific 

studies.

As discussed previously, the cost/benefit analysis included in the RIA may inform the standardsetting process, but it does not replace the statutorily prescribed requirements for setting 

standards in the NSPS and NESHAP programs. The final rules were developed based on the 

criteria required under the CAA, which do not require quantified health benefits nor allow their 

direct consideration. Executive Order 12866 requires a cost/benefit analysis and “a reasoned 

determination that the benefits of the intended regulation justify its costs” to the extent permitted 

by law. In the case of these rules, the cost/benefit analysis projects that the rules will be 
390

essentially cost neutral, allowing for such a “reasoned determination” even without quantified 

health benefits. In addition, given resource and time constraints under the court-ordered schedule 

for the rulemaking, we believe that we have based our decisions on the “best reasonably 

obtainable scientific, technical, economic, and other information” as required by Executive Order 

12866 and the “best available science” as required by Executive Order 13563.

Comment: One commenter (4240) states that the EPA must consider non-climate related health 

and public welfare benefits of methane reductions. According to the commenter, while methane 

is not regulated as a precursor to ozone on a regional level, anthropogenic methane contributes 

significantly to background levels of ground-level ozone around the world. The commenter notes 

that ground-level ozone has significant negative impacts on public health and significantly 

reduces the yield of a wide variety of crops.

Response: The EPA agrees with the commenter that reducing VOC and methane emissions 

would reduce ozone concentrations and ozone-related effects on health and welfare. In the 

Regulatory Impact Analysis accompanying the final rule, we have expanded the qualitative 

assessment of ozone benefits associated with these emission reductions.

Comment: One commenter (3350) states that from a policy standpoint, over-regulation of the 

natural gas industry can have adverse effects on the effort to curb CO2 emissions through 

conversion from traditional fossil fuels to cleaner-burning natural gas, which is the most practical 

option in the near term.

Response: While we agree with the commenter that conversion from traditional fossil fuels to 

cleaner-burning natural gas is a practical option for CO2 reductions in the near term, we do not 

agree with the implication that the final rules represent over-regulation of the natural gas 

industry. As discussed in section 4.5 of this document and the RIA for the rulemaking, our 

analysis of the impacts of the final rules on the U.S. energy system shows that domestic natural 

gas production and prices are estimated to remain unchanged in 2015, the year of analysis.

Comment: One commenter (4274) recommends that the EPA move forward with all proposals 

that effectively protect the population from benzene and formaldehyde emissions in the rural 

Marcellus Shale areas, where presently there is no ambient air monitoring system.

Response: The EPA believes that the final NESHAP rules provide effective protection to the 

population from HAP emissions from the ONG industry, consistent with the requirements of the 

CAA. Combustion emissions from compressor engines are not covered by these final rules, so 

formaldehyde emissions from these engines are not within the scope of the analyses conducted 

for these rules. Rules that address combustion emissions from compressor engines include one 

NESHAP (subpart ZZZZ covering reciprocating internal combustion engines, commonly called 
391

the RICE NESHAP) and two NSPS (subpart IIII, the NSPS for compression ignition engines or 

the CI NSPS, and subpart JJJJ, the NSPS for spark ignition engines or the SI NSPS).

Comment: One commenter (4275) supports the proposed rule based on the belief that the rule 

will lead to greater transparency from the industry in the form of accounting for the numerous 

sources of emissions that are currently “invisible” due to the lack of regulation, will provide 

health benefits to those who live close to the thousands of gas facilities covered by this rule and 

will provide an economic benefit to this industry, through the capture of additional product that 

can be sold in the marketplace. The commenter is confident that this innovative industry will be 

able to find a way to comply with this rule while remaining highly profitable. 

Response: The EPA thanks the commenter for his or her support and agrees that the benefits 

listed by the commenter will result from the final rules. Our analysis show that the controls 

required by the final rules are cost-effective, and that across the entire sector the value of 

products recovered by the controls will likely pay for the costs of compliance.

Comment: One commenter (4375) supports all efforts by the EPA to require companies to 

perform reduced emission completions (RECs) of wells. However, the commenter believes that 

in the economic impact assessment the EPA should not stop with an estimate on the change in 

profitability that any company doing the REC would undergo, but should also consider health 

impacts and the broader cost to society that not requiring RECs would cause. The commenter 

states that increased VOC emissions would have a significant, measurable set of impacts on 

public health, from increased hospital visits to premature death. 

Response: The EPA has considered, to the extent possible given available data and analysis 

techniques, the full range of benefits that will flow from the final NSPS REC requirements. We 

were unable to develop credible quantitative estimates of the health benefits, although our 

analysis includes a qualitative discussion of these benefits. The RIA for the rulemaking details 

our economic analysis and cost/benefit analysis for the final rulemaking.

Comment: One commenter (4275) provided reports supporting the claim that RECs on coalbed 

methane completions can help prevent release of hydrogen sulfide and also help global and 

regional air quality.

Response: The EPA agrees with the commenter that these rules could reduce emissions of 

hydrogen sulfide. While hydrogen sulfide has not been listed as a HAP, the Regulatory Impact 

Analysis describes how these rules would affect emissions of this pollutant and directs the reader 

to the EPA’s IRIS database for more detailed information on the health effects, available on the 

Internet at http:// www.epa.gov/iris.
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4.2.2 Estimated Climate Co-benefits

Comment: Although four commenters (3350, 4192, 4246, 4267) disagree with the use of the 

social cost of carbon, a letter authored by 13 organizations (4240) strongly encourages the EPA 

to value methane reduction, specifying that the EPA must account for the methane co-benefits in 

the comparison of the rulemaking’s costs and benefits. The commenters further state that EO 

12866 “calls upon the agency to include ‘quantifiable measures (to the fullest extent that these 

can be usefully estimated),” and that EO 13563 “likewise directs EPA to use the ‘best available 

techniques to quantify anticipated present and future benefits and costs as accurately as 

possible.’” Commenters also reference the Ninth Circuit Court of Appeals decision in Center for 

Biological Diversity v. NHTSA to support its conclusion that the EPA is “obligated to consider” 

methane co-benefits in the rulemaking.

In addition, the commenters recommend that the EPA expand the presentation of information 

about SCC and methane co-benefits as follows:

 Provide the 99th percentile estimates of the social cost of carbon;

 Provide a list of the impacts that are included in the monetized estimates and the impacts 

that are not included; and 

 Provide a clear, tabular demonstration of how it calculated the methane co-benefits.

On the other hand, five commenters (3350, 4231, 4246, 4251, 4254) contend that it is 

inappropriate that the analysis carried out by the EPA is based on captured emissions of methane, 

which is not covered by the regulations. The commenters disagree with use of SCC and 

recommended that the EPA remove all language about it. One commenter (3350) states that the 

EPA claims that the reductions in methane will yield about $1.6 billion in public health and 

environmental benefits; however, because methane is not a VOC or air toxic—the two types of 

emissions targeted by the proposed revisions—the decision to cite it as a co-benefit is 

questionable. Even if the co-benefits of methane reductions are cited, the commenter believes 

that the EPA’s analysis is flawed because no sense of proportion or the scope of its impact is 

provided. The commenter contends that the EPA should determine the impacts of methane 

reductions by modeling the temperature impact that the rule would have, and that the failure to 

do so is arbitrary and capricious. The commenter asserts that by reducing U.S. GHG emissions 

by 1 percent, the rule would have a negligible impact on climate. The commenter (3350) 

concluded that “there is no evidence that [SCC] values are real” and viewed the name “social 

cost of carbon” as a misnomer because “not all greenhouse gases contain the element of carbon.”

Another commenter (4192) asserts that “there is no widely accepted or official regulatory 

method for determining benefits from GHG reductions.” Finally, a third commenter (4267) 

disagrees with the use of “assumptions, estimates and models” to inform the benefits discussion 

in this rulemaking. The commenter also state that the EPA used the four estimates of the social 

cost of methane “to compensate for difficulties in modeling,” but did not identify or discuss 
393

specific concerns about the assumptions, estimates, or models.

Response: The EPA considered both the comments recommending inclusion of methane cobenefits in the comparison of the rule’s costs and benefits and the comments that opposed any 

use of the social cost of carbon, and by implication, the social cost of methane. The EPA 

disagrees that co-benefits should be excluded from consideration of the benefits anticipated by 

this rule. Accounting for ancillary benefits is standard practice in benefit-cost assessment since 

these benefits are a consequence of the rule, regardless of the rule’s intended purpose. As such, 

the EPA estimates all of the anticipated costs and benefits associated with a regulatory action, to 

the extent feasible, for the purpose of determining the likely impacts, not to justify an action. The 

VOC reduction requirements in this rule are expected to also result in substantial methane 

emission reductions, and such co-benefits are an important category to consider for the benefits 

analysis. Our treatment of quantified benefits and co-benefits follows guidance set by OMB 

Circular A-4 and the EPA’s Guidelines for Preparing Economic Analyses (2010).

Regarding the environmental impact of methane emissions, the EPA appropriately addressed the 

proportion and scope of the expected impacts by matching a qualitative discussion of the kinds 

of impacts that result from increased concentrations of greenhouse gases with a quantitative 

monetization of the total value of the climate changes avoided by the reductions (that latter 

quantitative monetization being the more important). The argument by the commenter that a 

reduction of one thousandth of a degree global temperature change “will not have climate 

impacts” is fallacious. The impacts of that mitigation of a thousandth of a degree of warming on 

sea level rise, on the temperature of a heat wave, on air quality, would all be small, but for each 

of those outcomes, there would be an impact of that mitigation, and it would be in the direction 

of ameliorating that change. Using the reasoning of the commenter, there would be no quantity

of temperature change that could have an impact, because any temperature reduction can be 

expressed as the sum of a set of individual smaller reductions. Any individual action in and of 

itself is not expected to solve the whole climate change problem: but solving one thousandth of 

the problem is still valuable, and the social cost of carbon methodology was developed precisely 

for the task of monetizing that value.

The EPA estimated the methane co-benefits in the final rule using the GWP approach because 

directly modeled interagency estimates are not available.42 (Details about methodologies to value 

methane co-benefits are discussed in the next comment/response section). The EPA continues to 

recognize the uncertainties with the “GWP approach” estimates.

 

42 As explained in the RIA, the interagency group did not directly estimate the social cost of non-CO2 GHGs using 

the three models in 2009-2010 and instead set a goal to develop methods to value non-CO2 GHGs. Until then, EPA 

will use the GWP approach, i.e., convert methane to CO2 equivalents using the GWP of methane, then multiply 

these CO2-equivalent emission reductions by the social cost of carbon developed by the Interagency Social Cost of 

Carbon Work Group. 
394

As discussed in the RIA, the GWP is an aggregate measure that approximates the additional 

energy trapped in the atmosphere over a given timeframe from a perturbation of a non-CO2 gas 

relative to CO2. The time horizon most commonly used is 100 years. One potential problem with 

utilizing temporally aggregated statistics, such as the GWPs, is that the additional radiative 

forcing from the GHG perturbation is not constant over time and any differences in temporal 

dynamics between gases will be lost. This is a potentially confounding issue given that the social 

cost of GHGs is based on a discounted stream of damages that are non-linear in temperature. For 

example, methane has an expected adjusted atmospheric lifetime of about 12 years and 

associated GWP of 21 (IPCC Second Assessment Report (SAR) 100-year GWP estimate). Gases 

with a relatively shorter lifetime, such as methane, have impacts that occur primarily in the near 

term and thus are not discounted as heavily as those caused by longer-lived gases such as CO2, 

while the GWP treats additional forcing the same independent of when it occurs in time. The 

GWP also relies on an explicit time horizon and constant concentration scenario, which is 

inconsistent with the assumptions used by the SCC interagency workgroup. Finally, impacts 

other than temperature change also vary across gases in ways that are not captured by GWP. For 

instance, CO2 emissions, unlike methane will result in CO2 passive fertilization to plants.

Recognizing that this rulemaking will achieve non-zero co-benefits through methane reductions, 

the EPA chose to apply the GWP approach and present estimates of the social cost of methane.

The EPA presented these estimates for illustrative purposes and did not compare them to the 

costs of the rule because of the GWP approach limitations. The EPA has determined that this 

approach is consistent with EO 12866, EO 13563, and the Ninth Circuit decision referenced by 

commenters. The EPA has provided a non-zero estimate of the co-benefits of this rulemaking’s 

reduction in methane emissions and has also presented qualitative information about the 

rulemaking benefits that could not be monetized. As discussed above and in the RIA, the EPA 

presented the best available estimates. 

Furthermore, the EPA disagrees with one commenter’s statement that the EPA should not use 

assumptions, estimates, and models in the analysis. First, Executive Order 12866 requires 

agencies “to assess both the costs and the benefits of the intended regulation.” Recognizing the 

need to create consistency in how Federal agencies incorporate the benefits of carbon dioxide 

reductions into rulemakings, the Council of Economic Advisers and the Office of Management 

and Budget convened an interagency work group in 2009-2010 to develop a range of SCC values 

using a defensible set of input assumptions that are grounded in the existing literature. In this 

way, key uncertainties and model differences more transparently and consistently inform the 

range of SCC estimates used in the rulemaking process. The SCC Interagency Work Group 

included active participation and regular input from many agencies and departments, including:

the Council on Environmental Quality, National Economic Council, Office of Energy and 

Climate Change, Office of Science and Technology Policy, the Departments of Agriculture, 
395

Commerce, Energy, Transportation, and Treasury, and the EPA. The work group examined the 

technical literature in relevant fields, discussed key inputs and assumptions for SCC, and 

conducted a modeling exercise that produced SCC estimates. The Agencies were directed to use 

these estimates to incorporate the social benefits of reducing carbon dioxide (CO2) emissions 

into cost-benefit analyses of regulatory actions that have small, or “marginal,” impacts on 

cumulative global emissions.

Second, the EPA disagrees with the statement that there is no evidence that SCC values are real.

The social cost of carbon estimates presented in the RIA were developed from three integrated 

assessment models that synthesize available scientific and economic research and have been used 

in the IPCC assessment. Integrated assessment models are particularly well suited to the 

estimation of SCC because they combine climate processes and economic growth into a single 

modeling framework. See the Social Cost of Carbon TSD for a complete discussion about the 3 

models used to develop the estimates. In addition, the EPA notes that the estimates do not 

include all significant climate changes damages and are therefore underestimates. As a result, the

EPA has supplemented the quantified benefit estimates with a qualitative discussion about 

benefits.

Regarding presentation of the methane co-benefits, the EPA agrees that a clear, tabular summary 

would be useful to the reader and has therefore added a table to the regulatory impact analysis 

(RIA) for illustrative purposes. The RIA for the final rule continues to present a detailed 

explanation about how the EPA calculated the methane co-benefits as well as references to the 

TSD for the social cost of carbon.

Regarding the recommendation to provide the 99th percentile estimates of the social cost of 

carbon, the EPA notes that these estimates are presented in the SCC TSD, “Social Cost of 

Carbon for Regulatory Impact Analysis Under Executive Order 12866 SCC TSD,” (SCC TSD), 

which is referenced in both the preamble and RIA.43 The SCC provides extensive information 

about the SCC estimates and the underlying parameters, which serve as the basis for the 

estimates of methane co-benefits. For example, the SCC TSD shows how SCC values for 2010 

vary across model, scenario, and discount rate; it also presents the distribution of SCC estimates, 

including benefit estimates at the 95th and 99th percentiles for each model. The EPA has 

determined that it is more appropriate to place such detailed technical information in the 

rulemaking’s technical supporting documents, i.e., the SCC TSD, rather than the co-benefits 

section of the RIA, which gives an overview of the calculation as well as a detailed table with the 

methane co-benefit estimates. The RIA also provides references to the SCC TSD for those 

seeking further information about the distribution.

 

43 For SCC TSD, see http://www.epa.gov/otaq/climate/regulations/scc-tsd.pdf
396

The EPA disagrees with the commenter’s statement that the EPA has not responded to repeated 

requests for more information about how the models treat climate change impacts (i.e., which 

impacts are therefore included or excluded from the monetized estimates). Specifically, the EPA 

has published written responses to this same comment in other rulemakings—see Light-Duty 

Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards, 

EPA Response to Comments Document for Joint Rulemaking44 Greenhouse Gas Emission 

Standards and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles,

and EPA Response to Comments Document for Joint Rulemaking45. In short, it is not possible at 

this time to provide a precise list of each model’s treatment (i.e., included, excluded) of climate 

impacts. Instead, the SCC TSD presents a robust discussion of this key analytical issue, e.g., how 

each model estimates climate impacts, the known parameters and assumptions underlying those 

models, and the implications of incomplete treatment of impacts (catastrophic and noncatastrophic) for the SCC estimates. Moreover, the discussion in the SCC TSD underscores the 

difficulty in accurately distilling the models’ treatment of impacts in table-form. Most notably, 

the use of aggregate damage functions—which consolidate information about impacts from 

multiple studies—in two of the models poses a challenge in listing included impacts. For 

example, within the broad agricultural impacts category, some of the sub-grouped impacts are 

not explicitly modeled but are highly correlated to other subcategories that are explicitly 

modeled. Therefore, it may be misleading to identify these kinds of impacts as either “included” 

or “omitted” from the model. Along those lines, impacts may be included in models but not 

directly; the Dynamic Integrated Climate and Economy (DICE) model represents adaptation 

implicitly through the choice of studies used to calibrate the aggregate damage function, and the 

Climate Framework for Uncertainty, Negotiation, and Distribution (FUND) model includes 

adaptation both implicitly and explicitly (see the SCC TSD for details).

The EPA has recognized the need for a thorough review of damage functions—in particular, how 

the models incorporate adaptation, technological change, and catastrophic damages. The EPA 

regards the SCC TSD as a starting point in the inquiry into the models’ treatment of impacts and 

to motivate new research. Accordingly, the EPA partnered with DOE and hosted a series of 

workshops in 2010-2011 to explore the treatment of impacts in integrated assessment models. 

The first workshop focused on conceptual and methodological issues related to integrated 

assessment modeling and valuing climate change impacts, along with methods of incorporating 

these estimates into policy analysis.46 The second workshop reviewed research on estimating 

impacts and valuing damages on a sectoral basis.47

 

44 Docket EPA-HQ-OAR-2009-0472 or see http://www.epa.gov/otaq/climate/regulations/420r10012a.pdf, page 4-

57. 

45 Docket EPA-HQ-OAR-2010-0162 or see http://www.epa.gov/otaq/climate/documents/420r11004.pdf, page 11-

17. 

46 See http://yosemite.epa.gov/ee/epa/eerm.nsf/vwRepNumLookup/EE-0564?OpenDocument

47 See http://yosemite.epa.gov/ee/epa/eerm.nsf/vwRepNumLookup/EE-0566?OpenDocument
397

Finally, the EPA is aware that not all greenhouse gases contain the element carbon and therefore 

uses nomenclature appropriately in the rulemaking documents. As in the proposed rule, the RIA 

for the final rule uses “SCC” to refer to the social cost of carbon dioxide, which is in turn used to 

estimate the social cost of methane. The EPA did not apply the “SCC” label to methane cobenefits; the EPA provided detailed references supporting the estimates.

Comment: A letter authored by 13 organizations (4240) states that the EPA must value methane 

reductions “accurately” and provides recommendations for two methods—(1) direct model 

estimates of the social cost of methane and (2) the GWP approach—to estimate the rule’s 

methane co-benefits. Specifically, commenters recommended the following for each 

methodology:

Direct model estimates of the social cost of methane: The commenter describes Marten and 

Newbold (2011), which used DICE2010 to directly model the social cost of methane, as a “valid 

and analytically supportable method,” and encourages the EPA to include figures calculated 

using their approach.

GWP approach: The commenter states that if the EPA could not use directly modeled estimates 

of the social cost of methane, it should apply the GWP approach. Furthermore, the commenter 

recommends using a GWP of 25, which is the most recent Intergovernmental Panel on Climate 

Change (IPCC) GWP value for methane (Fourth Assessment Report), rather than the 21 estimate 

from the Second Assessment Report. The comment states that the EPA’s justification for using 

the 21 GWP (consistency with the United Nations Framework Convention on Climate Change 

protocol for GHG inventory) is irrelevant. In addition, commenter recommends that the EPA do 

a sensitivity analysis using an alternative 100-year GWP, Shindell et al’s recently published 

estimate of 33.48 The commenter states that Shindell et al’s estimate “improves upon the IPCC’s 

by taking into account positive feedback loops (e.g. methane causing warming which then causes 

permafrost to melt, releasing yet more methane).”49

In addition, one commenter (4104) states that any analysis of methane reductions that considers 

CO2 equivalent emissions should use 21 as the methane global warming potential. 

Response: The EPA has determined that before it can directly model methane in a manner 

consistent with the 2009-2010 interagency modeling exercise, it must first address key modeling 

issues. The most important issue that would require careful consideration as a pre-requisite for 

using direct model estimates is how to represent non-CO2 cycles in DICE. A challenging issue in 

 

48 D.T. Shindell, G. Faluvegi, D.M. Koch, G.A. Schmidt, N. Unger, S.E. Bauer (2009) "Improved Attribution

of Climate Forcing to Emissions," Science 326 716 718,

49 See attachment to letter EPA-HQ-OAR-2010-0505-4240, page 8.
398

estimating the social cost of non-CO2 GHGs is that the integrated assessment models vary in 

how they represent the atmospheric chemistry for these gases. DICE in particular poses a 

challenge because it does not directly model the atmospheric gas cycle for any GHG other than 

CO2. Instead, it jointly represents all non-CO2 GHGs through a single net radiative forcing 

vector. The other integrated assessment models, PAGE and FUND, directly represent the 

atmospheric chemistry for several non-CO2 GHGs (noting that for PAGE not all gas cycles, such 

as methane, were used in the analysis).

There are options to incorporate a defensible cycle for methane in the DICE model, such as 

supplementing DICE with changes in radiative forcing estimates from MAGICC, a climate 

model that incorporates important interactions between various gases in the atmosphere.50 This 

modification, however, would differ from the methodology established by the 2009-2010 

Interagency Work Group. 

As stated above, the EPA applied the GWP approach to the final rule and used the value of 21 

for the GWP. The EPA disagrees that maintaining consistency with GHG inventory reporting is 

irrelevant to the Agency’s assessment of this rule’s methane co-benefits. The EPA is obligated to 

comply with the international reporting standards under the UNFCCC when submitting, on 

behalf of the US government, the national GHG inventory to the UNFCCC each year. In light of 

this international obligation, the EPA chose to use GWPs published in the Intergovernmental 

Panel on Climate Change Second Assessment Report (IPCC SAR) (based on a 100-year time 

horizon) in the US Greenhouse Gas Reporting Program (USGHGRP) because they allow 

comparability of data collected under this program to the national GHG inventory. Given that oil 

and gas industry stakeholders are required to report to the EPA under the US GHGRP, we 

believe it is appropriate to present this rule’s methane co-benefits in a way that is consistent with 

how methane emissions are currently reported and presented to the public under the US GHGRP. 

In addition, the EPA has reviewed the comments recommending use of alternative GWPs, in 

particular Shindell et al’s recent estimate of 33 for a 100-year GWP of methane. First, the EPA 

notes that the positive feedback loop cited by the commenters is not methane specific, and is 

therefore not included in Shindell et al's GWP for methane. Rather, the novel element of Shindell 

et al’s work is the treatment of methane impacts on sulfate formation: methane emissions 

consume the hydroxyl radical, which reduces the amount of hydroxyl radical that is available to 

oxidize sulfur dioxide into sulfate, resulting in less cooling, and therefore greater warming from 

methane. Second, as noted above, the EPA uses the 100-year GWP approach recommended by 

the IPCC, consistent with the UNFCCC reporting requirements. The EPA believes it would be 

 

50 For example, see a working paper by Marten and Newbold (2011) at 

http://yosemite.epa.gov/EE/epa/eed.nsf/WPNumber/2011-01?OpenDocument. 
399

inappropriate to use alternative GWP estimates in the analyses, even in sensitivity analyses, that 

have received relatively less scrutiny than those cited in the IPCC reports.

Comment: An attachment to the letter authored by 13 organizations (4240) identifies

recommendations to improve the social cost of carbon estimates. The commenter makes

recommendations to the EPA regarding use of integrated assessment models and discount rate 

selection. In addition, this commenter requests that the EPA present 12 longer-term 

recommendations for SCC to the interagency group.

Recommendations to the EPA: Regarding models, the commenter recommends that the EPA use 

updated versions of DICE, FUND, and PAGE, which have become available since the 2009-

2010 interagency exercise. The commenter also recommends that the EPA modify the structure 

of the FUND, specifically, “reduce CO2 fertilization benefits in the FUND model in proportion 

to methane’s decomposition into CO2 before being re-run. If it is not possible to structurally 

adjust the fertilization levels within the time frame of the ruling, the EPA should either a) 

estimate the CO2 fertilization effect separately, and subtract its value accordingly from the SCC 

or b) exclude FUND from the SCC estimates used to calculate methane reduction benefits.”

Regarding discount rates, the commenter recommends that the EPA use a lower rate, specifically 

0.7 percent. The commenter stated that this is the long run average yield on 6 month U.S. 

Treasury Notes and “a better measure of a risk-free asset than the long term yield on U.S. 

Treasury Bonds used by the Working Group, because it carries much less inflation risk.” The 

commenter also noted that OMB Circular A-4 has recommended a lower bound sensitivity value 

for intergenerational discounting of 1 percent and suggested that the EPA include this rate in its 

analysis. The commenter states that if the EPA does not use a 0.7 percent rate, the Agency 

should “use a set of discount rates that take into account long run uncertainty in interest rates. 

The commenter states the range should include Weitzman, and the UK Greenbook (zero time 

preference), declining discount rate schedules...in addition to the Newell-Pizer estimate.”

Recommendations for the Interagency Group: The commenter presents the following 

recommendations for the interagency group to consider in exploring and updating the social cost 

of carbon estimates:

1. Risk aversion: Incorporate risk aversion into the next revision of the SCC.

2. Catastrophic impacts: To better capture high and potentially catastrophic damages, adopt 

Weitzman’s (2009) suggestion of “extending the grid” in the Monte Carlo simulations 

(i.e. increase the number of, and value for, low probability catastrophic damages).

3. Catastrophic impacts: For catastrophic outcomes that affect the entire globe, use a 

damage value implied by Weitzman’s (2009) analysis: the value of a statistical life (VSL) 

multiplied by the global population. 
400

4. Model changes: Following the PAGE model, integrate a general “adaptation” function 

into all models that can vary by level, speed, and cost; inform lower bounds by a review 

of adaptation measures (or lack thereof) being taken for climate damages that have 

already begun.

5. Model changes: To the extent that different sectors of the economy are modeled in the 

IAMs, modify the “damage functions” to allow for cross-sectoral impacts.

6. Model selection: Ensure that the Working Group’s models, especially FUND, more 

accurately capture agricultural impacts; to the extent that this is not possible, CO2

fertilization benefits should be reduced to reflect what net impacts would be if it were 

possible to account for all effects.

7. Equity weight: Equity weight within generations, using the different established 

methodologies available (i.e., do a sensitivity analysis using different methods).

8. Equity weight: Use one global value for the value of a statistical life (VSL), i.e., do not 

vary the value by income or the expected number of life years remaining (as is currently 

done in some models).

9. Non-use values: Develop a multiplication factor(s) for non-use values, and apply them to 

appropriate use values included in the integrated assessment models.

10. Monitor science and economic developments: Dedicate full-time Working Group staff to 

collecting, reviewing, and assimilating new climate science and economic modeling 

findings on an ongoing basis, so that revisions to the SCC can be accomplished more 

quickly.

11. Monitor science and economic developments: Establish an EPA web page posting these 

new findings, and provide links to relevant research papers.

12. Scenarios: Review current research on worse-case emissions growth scenarios and make 

sure the research is consistent with the scenarios used by the Working Group.

Response: The EPA appreciates the commenter’s recommendations to modify the methodology 

underlying the SCC estimates and has considered each one in the context of this rulemaking.

However, the EPA has determined that these recommendations—including those made to the 

EPA specifically—require additional research, review, and public comment before it can apply 

them to a rulemaking context. The EPA has therefore presented the SCC estimates developed 

through the 2009-2010 interagency process in this rulemaking. The EPA will continue to 

consider these comments and will share the recommendations with the interagency group when 

the current SCC estimates are updated. The remainder of this section provides more detailed 

responses to the recommendations made to the EPA specifically.

Regarding model vintage, the EPA has begun to explore the updated versions of DICE, FUND, 

and PAGE. Additional analysis of the model updates is required before the EPA can incorporate 

them in rulemakings. Furthermore, other federal agencies use the SCC estimates to analyze 
401

benefits of rulemakings and it is important to ensure consistency in the SCC estimates used 

across the government analyses.

The EPA considered the comments regarding CO2 fertilization benefits in FUND and has 

determined that additional research would be required to implement these recommendations. The 

EPA has recognized the need for a thorough review of damage functions in all three models that 

the interagency group used to estimate SCC. Accordingly, the EPA partnered with DOE and 

hosted a series of workshops in 2010-2011 to explore the treatment of impacts in the models. 

The first workshop focused on conceptual and methodological issues related to integrated 

assessment modeling and valuing climate change impacts, along with methods of incorporating 

these estimates into policy analysis.51 The second workshop reviewed research on estimating 

impacts and valuing damages on a sectoral basis.52 These workshops revealed that integrated 

assessment models used for estimating SCC lag the latest research on impacts and damages in 

some sectors. Since then, the EPA has initiated a review of the literature in agriculture and other 

sectors to help researchers more easily improve representation of damages. Consistent with the 

commenter’s recommendation, the EPA is particularly interested in examining recent 

publications about the role of assumptions regarding carbon fertilization. The EPA appreciates 

the reference provided by the commenter and will continue to analyze the components of 

agricultural impacts.

In the meantime, the EPA determined that modifying the FUND structure would be 

counterproductive, given that the latest version incorporates changes in the estimation of 

agricultural impacts. These changes are undergoing peer review and the EPA looks forward to 

exploring these changes.

Furthermore, introducing changes beyond those implemented by the model authors would 

conflict with the methodology established by the interagency working group. A key objective of 

the interagency process was to enable a consistent exploration of the three models while 

respecting the different approaches to quantifying damages taken by the key modelers in the 

field. After conducting an extensive literature review, the interagency group selected three sets of 

input parameters (climate sensitivity, socio-economic and emissions trajectories, and discount 

rates) to use consistently in each model. All other model features were left unchanged, relying on 

the model developers’ best estimates and judgments.

Regarding the recommendations for discount rate selection, the EPA finds it to be defensible and 

transparent given its consistency with the standard contemporary theoretical foundations of 

benefit-cost analysis. The basis for the current discounting approach is discussed in detail in the 

 

51 See http://yosemite.epa.gov/ee/epa/eerm.nsf/vwRepNumLookup/EE-0564?OpenDocument

52 See http://yosemite.epa.gov/ee/epa/eerm.nsf/vwRepNumLookup/EE-0566?OpenDocument
402

SCC TSD. In sum, the interagency group applied three constant certainty-equivalent discount 

rates (2.5, 3, and 5 percent) to the SCC estimates to account for various perspectives about risk 

and uncertainty. The upper value of 5 percent accounts for the view that there may be a high 

correlation between climate damages and market returns while the rest of the SCC analysis 

centers on a discount rate consistent with concerns about risk aversion. The SCC TSD also 

summarizes the consideration of the literature about handling uncertainty in discounting (e.g., 

Newell and Pizer (2003), Weitzman (2001), and the UK’s “Green Book” for regulatory analysis)

and concludes that the proper way to model discount rate uncertainty remains an active area of 

research.53

In addition, the EPA finds this approach to be consistent with OMB Circular A-4. Circular A-4 

discusses the analytical challenges for discounting in an intergeneration context and concludes 

that agencies “might consider a further sensitivity analysis using a lower but positive discount 

rate in addition to calculating net benefits using discount rates of 3 and 7 percent.” Specifically, 

Circular A-4 states that “estimates of the appropriate discount rate” in an intergenerational 

context ranged from 1 to 3 percent.”54 Two of the three discount rates used in the interagency 

exercise fall within this range.

However, the EPA recognizes the limitations of the discounting approach used in the interagency 

modeling exercise. Accordingly, the EPA funded a small workshop on discounting in September 

2011 at which world-recognized experts discussed how the benefits and costs of regulations 

should be discounted for projects with long horizons. In particular, it explored what principles 

should be used to determine the rates at which to discount the costs and benefits of regulatory 

programs when costs and benefits extend over very long horizons. The charge questions that 

were the subject of the workshops discussion focused on three main areas: (1) whether and in 

what context it is appropriate to apply a Ramsey discounting framework in an intergenerational 

setting; (2) whether and how to directly estimate discount rates over long time horizons; and (3) 

how to apply discounting in a regulation where some costs and benefits accrue intragenerationally while others accrue inter-generationally. See 

http://rff.org/Events/Pages/Intergenerational-Discounting-Workshop.aspx for a summary of the 

main discussion points. The EPA is in the process of evaluating next steps with regard to 

possible methodological improvements in intergenerational discounting.

 

53 See EPA-HQ-OAR-2009-0472-11581 for further discussion about key questions about potential time 

inconsistencies that arise with differential discounting approaches.

54 OMB Circular A-4, September 17, 2003, http://www.whitehouse.gov/omb/circulars_a004_a-4/#main-content. 

Circular A-4 uses the following citation for the 1-3 percent range: Portney PR and Weyant JP, eds. (1999), 

Discounting and Intergenerational Equity, Resources for the Future, Washington, DC.
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4.3 Other Comments

Comment: One commenter (0331) asserts that the proposed rules reduce gas field air pollution 

by about 30 percent, but current best available technology can reduce air pollution by 90 to 

95 percent, cost effectively because captured VOCs are salable and have market value. 

Response: The EPA has promulgated final rules that will reduce emissions from the ONG sector 

to the maximum extent authorized under the CAA. For the NSPS, we have identified the 

emission points that can be cost-effectively controlled and have required BSER controls for new, 

modified and reconstructed affected facilities. In many cases, the final rule requires at least 95 

percent control of VOC emissions from subject affected facilities, but the CAA does not 

authorize control of existing facilities under NSPS. In addition, the rule includes some 

exceptions and cutoffs where emissions cannot be controlled for technical reasons or cannot be 

controlled cost effectively. For example, the rule requires 95 percent control of emissions from 

storage vessels with emissions equal to or greater than 6 tpy because we found controls to be cost 

effective at this level of emissions, but does not require controls for vessels with emission below 

this level because such control is not cost effective. For the NESHAP, we have required MACT 

controls for existing and new affected sources as authorized under the CAA.

Comment: Three commenters (1365, 1369, 1382) state that reducing oil and gas pollution will 

protect our communities, create jobs, and will often pay for itself. The commenters contend that 

oil and gas pollution is not only a threat to our health, it is also disrupting our climate because the 

industry is one of the largest sources of global warming pollution in the country. The commenter 

believes that the EPA needs to control all of these threats in these comprehensive rules. 

Response: The EPA agrees with the commenters that regulation of the ONG sector under the 

final NSPS and NESHAP will have many health and welfare benefits.

Comment: One commenter (3470) believes that with the unprecedented rate of growth in oil and 

natural gas exploration and production over the last decade, residents living near oil and natural 

gas sites may be exposed to highly toxic chemicals on a regular basis, with their health at risk. 

The commenter states that a community-based pilot environmental monitoring program in 

northwest New Mexico, southwest Colorado and western Colorado detected 22 toxic chemicals 

in nine air samples, including four known carcinogens, toxins known to damage the nervous 

system, and respiratory irritants, with levels detected in many cases significantly higher than 

what is considered safe by state and federal agencies. The commenter made several 

recommendations for the final rule.

Response: The final NSPS and NESHAP promulgated by the EPA control emissions from the 

ONG sector to the maximum extent authorized under the CAA. These rules expand the 
404

comprehensiveness of the standards by making additional sources of emissions subject to control 

requirements. The rules include provisions to assure compliance and enforceability, and the EPA 

monitors the enforcement programs of the state and local agencies to ensure that all CAA 

regulations are enforced and associated penalties follow the established guidelines. Where 

warranted, the EPA takes the lead on enforcement. Regarding the siting requirements for ONG 

facilities and universal monitoring of ONG facilities, the EPA is not authorized under the CAA 

to compel the actions suggested by the commenter. The EPA agrees with the commenter that it 

would be beneficial for the ONG industry to adopt voluntary measures to reduce emissions, and 

has established such programs as the Natural Gas STAR program encourage such actions.

Comment: One commenter (3528) notes that the Natural Gas STAR program estimates that a 

large reduction in fugitive gas emissions has already occurred over the past few years without the 

rule, and continues as a result of a collaborative working relationship between the EPA and the 

industry. The commenter opines that continuing to build upon the gas savings and emission 

reduction efforts already achieved through the Natural Gas STAR program may be a better 

approach than a new ruling, much of which is covered in various state air quality regulations and 

oil and gas commissions. 

Response: While we agree that the Natural Gas STAR program has been beneficial, the EPA is 

not free to abandon rulemaking under the CAA. We are required periodically to review the 

source categories listed pursuant to the NSPS and NESHAP programs, and we are required to 

regulate emissions from those source categories as prescribed by the CAA. Based on public 

comments and reports to the EPA's Natural Gas STAR program, the EPA recognizes that some 

producers conduct well completions using REC techniques voluntarily for economic and/or 

environmental objectives as a normal part of business. To account for emissions reductions and 

costs arising from voluntary implementation of pollution controls the EPA used information on 

total emission reductions reported to the EPA by partners of the EPA Natural Gas STAR. This 

estimate of this voluntary REC activity in the absence of regulation is also included in the 

baseline. More detailed discussion on the derivation of the baseline is presented in a technical 

memorandum in the docket, as well as in the RIA. 

Additionally, in the RIA, we provide summary-level estimates of emissions reductions and 

engineering compliance costs for a case where no voluntary RECs are assumed to occur. This 

alternative case is presented in order to show impacts if conditions were such that RECs were no 

longer performed on a voluntary basis, but rather were compelled by the regulation, and serves in 

part to capture the inherent uncertainty in projecting voluntary activity into the future. As such, 

this alternative case establishes the full universe of emissions reductions that are guaranteed by 

this NSPS (those that are required to occur under the rule, including those that would likely 

occur voluntarily). While the primary baseline may better represent actual costs (and emissions 

reductions) beyond those already expected under business as usual, the alternative case better 
405

captures the full amount of emissions reductions where the NSPS acts as a backstop to ensure 

that emission reduction practices occur (practices covered by this rule).

Comment: One commenter (4168) requests that the EPA base new regulation on common sense 

and sound science, balancing our clean air and environment with sustaining the oil and natural 

gas industry which is essential to our local and national economies. The commenter asserts that 

any new regulations should be reasonable and proven necessary through sound science.

Response: The EPA agrees with the commenter. We believe that the final rules achieve the goals 

laid out by the commenter.

Comment: While commending the EPA for considering environmental justice issues, one 

commenter (4208) questions the Agency’s determination that the rule will not result in 

disproportionately high adverse health effects on environmental justice communities. The 

commenter believes that improvements are needed in the proposal to address environmental 

justice and encourages the EPA to continue to consider these factors in developing the final rule 

and subsequent regulations. The commenter recommends an analysis at the 5-kilometer distance 

be conducted to assess facility impacts to nearby environmental justice communities, and also 

that the rule writers work with the EPA Office of Environmental Justice to develop criteria and 

specific guidance on how to interpret and apply the outcome of these types of analyses in the 

rulemaking process. 

Another commenter (4254) states that a significant environmental justice issue is the potential 

that increased energy costs will result in lost jobs; in addition, reduced access to affordable 

energy for home heating, electricity generation, and transportation will disproportionately affect 

the most vulnerable segments of society. The commenter also believes that domestic energy 

production will decline, with a corresponding loss of income to farmers, ranchers and other 

royalty owners as well as royalties and severance taxes to states and the federal government, as 

the costs for control technologies, administration, and re-training will alter the cost-benefit 

balance of domestic oil and gas production, resulting in fewer wells being economically 

productive.

Response: 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 
406

groups within the at-risk population living near the 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.

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 multi-pathway effects, and that 

acute and chronic noncancer health impacts are unlikely. The EPA has determined that, although 

there may be an existing disparity in HAP risks from these sources between some demographic 

groups, no demographic group is exposed to an unacceptable level of risk.

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.

Regarding the recommendations of the first commenter, we thank the commenter for the 

suggestions and will consider them in future environmental justice analyses.

We do not agree with the comments of the second commenter. Our analysis of the impacts on the 

U.S. energy system using the U.S. DOE NEMS did not predict the kinds of impacts suggested by 

the commenter. Rather, the analysis shows that domestic natural gas production and prices are 

estimated to remain unchanged 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. 
407

Comment: One commenter (4215) states that the rules need to align the regulatory burdens with 

the significance of human health impacts. According to the commenter, VOC emissions from the 

ONG sector are only 2.3 percent of U.S. emissions, so the reductions resulting from this rule are 

inconsequential. The commenter also states that the residual risk review found cancer risks from 

the sector to be within the range that the EPA considers acceptable. The commenter contends 

that the point of a residual risk assessment is to determine what risks remain and whether more 

protective standards are necessary to protect public health and that, given the outcomes of the 

EPA’s assessments, it is hard to understand why further regulatory action is needed in this case 

to protect human health. 

Response: The EPA does not agree with the commenter. The final rules are consistent with the 

rule-making considerations prescribed by the CAA. In the case of the NSPS, the CAA requires 

that the EPA promulgate technology-based standards for the listed source categories that 

represent BSER, taking into account costs and other listed impacts. The NSPS program is based 

on protecting human health and welfare, and it addresses these through the combination of the 

listing and regulation processes. While 2.3 percent of U.S. VOC emissions sounds small, it 

nevertheless represents a large mass of emissions. To adequately address the total impact of 

VOC emissions nationwide, we must address source categories that individually represent a 

small percentage of total emissions but collectively contribute significantly to the unhealthful 

concentrations of ozone and PM2.5 that our nation continues to experience. In addition, VOC 

contributes to ozone formation close to the source, so emissions that may seem insignificant on a 

national level may be very significant locally.

In the case of the NESHAP, the final rules are technology-based MACT standards under 

section 112(d) of the CAA. The EPA is required to review existing MACT standards at least 

every 8 years, and we must promulgate MACT standards according to the criteria prescribed by 

the CAA. The commenter is correct that our residual risk assessment found that the MACT 

standards adequately protect human health with an adequate margin of safety, but that does not 

negate the requirement for MACT standards under the CAA.

Comment: One commenter (4257) states that robust compliance and enforcement mechanisms 

are necessary in order to ensure that the public reaps the clean air benefits envisioned by the 

proposal, including publicly-available data documenting compliance and enforcement, as well as 

periods of non-compliance. The commenter asserts that penalties for non-compliance with the 

standards, including failure to submit annual reports or knowingly false material statements in 

such reports, must be met with stringent penalties including criminal liability; repeated failure to 

comply with the proposed standards should result in temporary or permanent restrictions on 

production operations. 
408

Response: The EPA agrees that the benefits of the final rules will only be achieved if industry 

complies with them. For this reason, we have included appropriate compliance and monitoring, 

recordkeeping and reporting provisions in the final rules that will assure compliance without 

imposing unnecessary costs on sources. State and local agencies generally are the first line of 

enforcement for NSPS and NESHAP, although the EPA retains enforcement authority as well. 

There is a well-developed system of shared responsibility for enforcement and the EPA oversight 

of state and local programs. The penalties for noncompliance are set out in the statutes law and 

imposed consistently through established guidelines. 

Comment: One commenter (4274) is concerned with the increasing formaldehyde emissions 

created by compressor engine air quality control devices aimed at reducing NOx emissions. The 

commenter notes that the Marcellus Shale will have an increasing number of compressor engines 

installed as both the gas flowing from the field increases, and on well sites as the gas is depleted. 

The commenter believes that we need to know not only the cancer risk of formaldehyde to the 

public living nearby these facilities, but we also need to know how the increasing formaldehyde 

emissions will affect nearby Shale community dwellers who are affected by asthma, chronic 

bronchitis and COPD. The commenter contends that it is necessary to establish a NAAQS for 

formaldehyde, which needs to be reliable relative to health standards for both chronic respiratory 

and cancer considerations.

Response: Combustion emissions from compressor engines are not covered by these final rules, 

so formaldehyde emissions from these engines are not within the scope of the analyses 

conducted for these rules. Rules that address combustion emissions from compressor engines 

include one NESHAP (subpart ZZZZ covering reciprocating internal combustion engines, 

commonly called the RICE NESHAP) and two NSPS (subpart IIII, the NSPS for compression 

ignition engines or the CI NSPS, and subpart JJJJ, the NSPS for spark ignition engines or the SI 

NSPS).

The commenter is correct that formaldehyde emissions can increase as a result of NOx controls 

on engines. The inverse is also true – formaldehyde controls can increase NOx emissions. These 

issues are addressed in the supporting documents developed for the engine standards.

The establishment of a NAAQS for formaldehyde is outside the scope of this action; therefore, 

we are not addressing that comment in this document.
409

5.0 Miscellaneous Comments

Comment: Two commenters (4191, 4240) believe there are several emission sources that should 

be included in the final rule. One commenter (4191) believes these emission sources should 

include amine units, pneumatic pumps, and produced and flowback water facilities. One 

commenter (4240) believes these emission sources should include offshore sources, heatertreaters, and field engines and turbines.

One commenter (4191) recommends that the EPA review emissions data from amine units for 

inclusion in this rule. If amine units are not addressed in the final rule, the commenter requests 

that the EPA provide justification in the preamble of the final rule. The commenter disagrees 

with the EPA’s determination that amine units do not warrant regulation under subpart OOOO 

and that amine units should be considered associated equipment under subparts HH and HHH. 

The commenter states that they have found that VOC and HAP emissions from amine units are 

significant enough to warrant control to avoid the requirements of the title V Operating Permit 

Program, Prevention of Significant Deterioration (PSD) review, or Nonattainment New Source 

Review (NANSR). 

The commenter (4191) requests that the EPA consider including pneumatic pumps in the rule. 

The commenter notes that the EPA provides a definition for pneumatic pump in subpart OOOO, 

but does not use this terminology in any other location within the proposed rule. The commenter 

has found that individually, pneumatic pumps can be significant emission sources, and they have 

issued construction permits for multiple pneumatic pumps with the potential to emit between 10 

and 20 tons of VOC per year.

The commenter (4191) recommends that the EPA review cleanout and inspection activities using 

pipeline inspection gauges (commonly referred to as “pigging”) as an additional source of air 

emissions. The commenter reports that, in oil operations, the emissions from pigging can exceed 

50 tons of VOC per year. Additionally, the commenter reports that natural gas pigging operations 

may result in much lower potential emissions, in the range of 1 to 2 tons of VOC per year. 

One commenter (4240) states that the EPA has the authority and the obligation to regulate the 

emissions of portions of the offshore oil and gas production sector that it has not proposed to 

regulate. The commenter asserts that the Outer Continental Shelf Lands Act (“OCSLA”) 

explicitly extended the “laws and civil and political jurisdiction of the United States” to the 

Outer Continental Shelf, cementing the relevance of domestic environmental law to that region. 

According to the commenter, in doing so, Congress recognized that the shelf is “a vital national 

resource reserve held by the Federal Government for the public,” and which is “subject to 

environmental safeguards.” In fact, the commenter asserts that Congress even ordered the 
410

Secretary of the Interior, who oversees leasing programs in the region, to “cooperate with the 

relevant departments and agencies of the Federal Government” to enforce “environmental laws.” 

One commenter (4240) states that the CAA provides that following the passage of the 1990 

Amendments, the EPA:

[s]hall establish requirements to control air pollution from Outer Continental Shelf 

sources located offshore of the States along the Pacific, Arctic, and Atlantic Coasts, and 

along the United States Gulf Coast off the State of Florida eastward of longitude 87 

degrees and 30 minutes (“OCS sources”) to attain and maintain Federal and State 

ambient air quality standards and to comply with the provisions of [the Prevention of 

Significant Deterioration Program]. 42 U.S.C. 7627(a)(1).

The commenter (4240) states that the CAA goes on to specify that, for OCS sources “located 

within 25 miles of the seaward boundary of such states” such requirements shall be the same as 

would be applicable if the source were located in the corresponding onshore area, and shall 

include, but not be limited to, State and local requirements for emission controls, emissions 

limitations, offsets, permitting, monitoring, testing, and reporting. 42 U.S.C. 7627(a)(1).

According to the commenter (4240), the NSPS clearly fits within this inclusive collection of 

requirements, even though they are Federal requirements, as they are, again, regulations designed 

that support attainment and maintenance of air quality standards. Additionally, the commenter 

opines that the use of “shall” in the directive from Congress to establish regulations aimed at 

attaining and maintaining the NAAQS and comply with the PSD program indicates that the EPA 

must extend the NSPS in Outer Continental Shelf sources.

The commenter (4240) reports although individual heater-treaters are relatively small sources of 

NOx and CO, thousands of them are used in the production process. According to the 

commenter, these emissions are readily subject to control and have been controlled, for years, by 

California regulators. The commenter states that, because each individual heater-treater’s 

emissions will be relatively minor, heater-treaters are unlikely to be directly regulated in many 

states, or under Federal major source permitting programs. The commenter asserts that section 

111 regulation is necessary to ensure that this cumulatively major emissions source is properly 

controlled. The commenter recommends that the EPA set standards no less stringent than those 

employed in the California air districts.

The commenter (4240) believes that the EPA must address NOx emissions (and emissions of 

other pollutants) from field engines, turbines, and drilling rig engines, or demonstrate that they 

are sufficiently addressed by other CAA standards. 
411

Two commenters (4092, 4166) believe that the proposed rule should include nonroad rules for 

the oil/gas sector, since many of the engines used in the oil/gas sector that emit NOx and other 

pollutants are classified as nonroad, not point sources. The commenters assert that, since these 

engines are moved from state to state, the EPA is much better equipped to regulate these engines 

than are the States. The commenters also believe that the proposed rule should include NOx

regulations for stationary engines, compressor engines, heaters and boilers and other point 

sources used in the oil/gas sector, to encompass a complete sector-based approach that includes 

all NOx emissions sources in the oil and gas sector. 

Two commenters (4170, 4208) believe that NOx emissions from reciprocating engines and 

combustion turbines should be addressed in a subsequent rulemaking for the oil and gas sector, 

or at a minimum, the EPA should reassess the NOx emission standards included in NSPS 

subparts JJJJ and KKKK.

Response: Some of the commenters ask the EPA to address under section 112 certain emission 

points that emit HAP or have the potential to emit HAP (e.g., amine treaters, produced and 

flowback water facilities). The Agency does not, however, have sufficient information to 

establish MACT standards under section 112(d)(2) and (d)(3) for such sources at this time, even 

assuming that such sources emit HAP and are located at a major source oil and natural gas 

production facility. See 112(n)(4) (aggregation).

As explained in the preamble in the response to comments section, we do not agree with those 

commenters that assert that section 112(d)(6) mandates that the EPA correct any deficiency in an 

underlying MACT standard when it conducts the “technology review” under that section. As

explained in the preamble, we believe that section 112 does not expressly address this issue, and 

the EPA has discretion in determining how to address a purported flaw in a promulgated 

standard, such a situation where the underlying MACT standard does not include a standard for a 

particular HAP emission point. Section 112(d)(6) provides that the Agency must review and 

revise "as necessary.” The “as necessary” language must be read in the context of the provision, 

which focuses on the review of developments that have occurred since the time of the original 

promulgation of the MACT standard and thus should not be read as a mandate to correct flaws 

that existed at the time of the original promulgation. 

In several recent rulemakings, we have chosen to fix underlying defects in existing MACT 

standards under sections 112(d)(2) and (3), the provisions that directly govern the initial 

promulgation of MACT standards. We believe that our approach is reasonable because using 

those provisions ensures that the process and considerations are those associated with initially 

establishing a MACT standard, and it is reasonable to make corrections following the process 

that would have been followed if we had not made an error at the time of the original 

promulgation. In this rule, we are finalizing MACT standards under section 112(d)(2) and (d)(3) 
412

for small glycol dehydration units, as we have sufficient information to set such standards at this 

time. We are not, however, finalizing MACT standards for the subcategory of storage vessels 

without the PFE, which were unregulated in the 1999 rule, because after evaluating the available 

data and comments received, we believe that we need additional data in order to set an emission 

standard for these vessels. To the extent the commenter has sufficient information to demonstrate 

that a HAP emission point within the oil and natural gas production major source category is 

unregulated under section 112(d), it can petition the Agency to revise the 1999 MACT standards 

to address such point.

Finally, one commenter asks the EPA to consider amine treaters to be associated equipment 

under subparts HH and HHH. The Agency did not propose that change. Rather, we proposed to 

amend the definition of associated equipment to exclude all storage vessels, and not just those 

vessels with PFE. In that case, however, we explained at proposal that we have information 

demonstrating that storage vessels with PFE and those without PFE have comparable emissions 

and that those emissions are significant. While we appreciate the data provided by the 

commenter concerning the amine treaters, that data is from a small subset of facilities in one 

State. We believe we would benefit from obtaining additional data on emissions from amine 

treaters from other facilities in the oil and natural gas production source category before we 

propose any further amendments to the definition of associated equipment. See also section X.C 

of the final rule preamble.

In addition to the above discussion, section IX.A of the final rule preamble also addresses 

treatment of other pollutants under the NSPS. Further, with regard to the specific emission 

points raised by these commenters, we note that engines, turbines, and heaters are also addressed 

in section IX.A of the final rule preamble. No standards were proposed for pneumatic pumps and 

cleanout and inspection activities, nor did we ask for any comment on them. Therefore, we 

believe that there is no logical outgrowth from the proposal to base any changes to the final rule 

and we are making no changes as a result of these comments. Concerning offshore sources, we 

note that offshore sources within U.S. territorial waters are affected sources under NESHAP 

subparts HH and HHH. For NSPS subpart OOOO, we have insufficient information concerning 

the technical feasibility of controlling emissions from affected facilities located offshore, 

particularly whether the controls specified in the final rule are applicable to offshore facilities, 

whether sufficient space is available on offshore rigs for control equipment, and whether the 

types of control equipment evaluated for the final rule (e.g., to estimate cost effectiveness) would 

be allowed under the specific and unique safety requirements applicable to offshore rigs. 

Comment: One commenter (4266) states that the consent decree does not require promulgation 

of rules for new affected sources and believes that the EPA's proposal goes well beyond the 

scope even contemplated by the settlement agreement. The commenter notes that with respect to 

Section 112, the settlement agreement provides that the EPA was to propose and take final action 
413

under sections 112(d)(6) and 112(f)(2). The commenter further notes that, with respect to section 

111, the settlement agreement provides that EPA shall sign one or a combination of the 

following for the NSPS subparts KKK and LLL: 

(a) a proposed rule containing revisions to the NSPS (in whole or in part) under CAA 

section 111(b)(1)(B); and/or 

(b) a proposed determination not to revise the NSPS (in whole or in part) under CAA 

section 111(b)(I)(B); and/or 

(c) a proposed or final determination not to review the NSPS (in whole or in part) under 

CAA section 111(b)(l)(B). 

According to the commenter (4266), for final action, the settlement agreement commits the EPA 

to “sign one or a combination of the following for NSPS subparts KKK and LLL: 

(a) a final rule containing revisions to the NSPS (in whole or in part) under CAA section 

111(b)(1)(B); and/or 

(b) a final determination not to revise the NSPS (in whole or in par) under CAA section 

111(b)(1)(B); and/or 

(c) a final determination not to review the NSPS (in whole or in part) under CAA section 

111(b)(1)(B).” 

The commenter (4266) recommends that the EPA separate the portions of the rule required by 

the consent decree from the voluntary additions to the rulemaking, so appropriate consideration 

can be given to these unique provisions.

Response: As explained in the preamble, when conducting a review of an existing performance 

standard under section section 111(b), the EPA has authority to revise that standard to add 

emission limits for pollutants or emission sources not currently regulated for that source 

category. EPA has appropriately included in this rule performance standards for a number of 

new affected facilities after careful evaluation and through notice and comment. EPA therefore 

sees no need to issue a separate rule to cover the standards for these new affected facilities or 

postponing issuing such standards. 

Comment: The commenter (4191) recommends that the EPA consider providing for alternative 

delegation options, including the possibility of splitting the responsibility for administration of 

the oil and gas sector NSPS between multiple state agencies. The commenter requests that the 

EPA consider the implications of a split delegation, such as funding, enforcement, and oversight 

issues. The commenter believes that without a split delegation option, or some other alternative 

delegation option, many States will be unable to implement these rules holistically without 

changing the long standing roles of their regulatory agencies. According to the commenter, this 
414

is not an insignificant task, particularly in an era of limited State resources, and will be a 

significant challenge within the applicability timeframes envisioned by the EPA’s proposed rule.

Two commenters (4266, 4358) believe that consultation with the “appropriate representatives of 

the Governors and of State air pollution control agencies” of oil and natural gas producing states, 

as required by 42 USC 7411(f), is particularly important. The commenter (4266) believes that the 

experience of these agencies is necessary to insure that only the notification and report 

information that is most beneficial to the agency is required to be submitted. 

One commenter (4191) states that, in the event that State regulatory agencies undertake new and 

expanded roles, there will be associated resource and timing burdens, and it will be very 

challenging for States to effectively and timely oversee activities covered by the rule, when oil 

and gas development is occurring on a large scale and rapid pace, statewide. 

Response: The Statute does not provide for the multi-state split delegation suggested by the 

commenter. Section 111(c) of the CAA authorizes EPA to delegate to individual States the 

impelementation of the NSPS, including this rule. States are not required to take delegation. 

However, we believe that the requirements in the final rule would help ease the State’s burden by 

including cost effective measures that are already being widely implemented in this sector and 

compliance requirements that can be easily tracked by delegated states.

We agree with the commenters that State consultation with the “appropriate representatives of 

the Governors and of State air pollution control agencies” of oil and natural gas producing States 

is important.55 In addition, the EPA realises that States and other enforcement entities are 

confronting limited resources and that visiting sites is not always practical. For that reason, the 

EPA believes the notifications and reporting requirements are vital to ensure compliance with 

our regulations. Therefore, as discussed elsewhere in this document, 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 removed duplicate 

and unnecessary reports throughout the affected subparts. For example, we have provided in the 

final NSPS that advance notifications of well completions that are submitted by owners and 

operators in compliance with State notification requirements will satisfy the requirement in the 

final NSPS for notification no later than 2 days before the beginning of an impending well 

completion. These changes will streamline the reporting process and reduce both compliance an 

denforcement burdens.

 

55 As explained in the preamble to the final rule, because we have concluded that the the currently listed oil and 

natural gas category covers at least those operations in this industry for which we are finalizing standards, we need 

not address the comment claiming that section 111(f) requires that the EPA consult with State Governors before 

amending section 111(b) listing.
415

Comment: One commenter (4221) urges the EPA to recognize the June 23, 2011 Memorandum 

of Understanding (MOU) between the EPA, the Bureau of Land Management, and the Forest 

Service in the preamble to the final rule and to make commitments for attempting to ensure full 

implementation of the MOU in the final rule. The commenter believes that the final rule for this 

oil and gas sector rulemaking should facilitate putting the implementation plan in place, and 

make commitments to ensure that implementation of the MOU is fully realized. 

Response: The EPA recognizes the Memorandum of Understanding (MOU), where the U.S. 

Department of Agriculture (USDA), the U.S. Department of the Interior (DOI), and the EPA 

(Signatories) commit to a clearly defined, efficient approach to compliance with the National 

Environmental Policy Act (NEPA) regarding air quality and air quality related values (AQRVs), 

such as visibility, in connection with oil and gas development on Federal lands 

(http://www.epa.gov/compliance/resources/policies/nepa/air-quality-analyses-mou-2011.pdf). 

We believe that the promulgation of these regulations for the oil and natural gas sector will 

further the goal of improving air quality and AQRVs, and therefore meets, in part, the EPA’s 

commitment under the MOU.

Comment: Six commenters (4159, 4177, 4219, 4220, 4234, 4273) state that the EPA's attempt to 

use natural gas as a “surrogate” for VOC in this rulemaking also implies that the EPA is 

regulating natural gas directly. The commenters assert that this raises a concern that the EPA 

may now consider natural gas to be a “pollutant” regulated under the NSPS and therefore eligible 

under 40 CFR §52.21 to be a “regulated NSR pollutant.” According to the commenters, while 

methane is currently considered a regulated NSR pollutant, other organic compounds in natural 

gas, such as ethane, are not NSR pollutants. In this case, the commenters report that the NSR 

pollutant being regulated is VOC, not natural gas. Four commenters (4159, 4177, 4220, 4273) 

believe that the EPA should clarify that natural gas is not a “regulated NSR pollutant” merely 

because it is being used a surrogate for VOC in this rulemaking. 

One commenter (4219) recommends that the EPA revise the definition for “field gas” to provide 

that “field gas” is “gas with more than 10 percent VOC content by weight.” The commenter 

believes this would keep the rules’ focus where it belongs: on VOC emissions, rather than 

methane or other GHG emissions, and would also prevent overlap or potential inconsistency 

between the proposed new NSPS and the subpart W leak monitoring requirements. 

Two commenters (4234, 4246) believe that it is imperative that the NSPS not imply that natural 

gas is a pollutant and for the EPA to revise the definition of “modification” if the change 

increases the unit’s “natural gas” emissions. 

Response: The EPA is using natural gas as a surrogate for VOC because natural gas emission 

rates are more readily available to the industry and are a reasonable indicator of VOC emission 
416

rate. For example, we consider natural gas to be an appropriate surrogate for VOC for well 

completion activities because our analyses of data on composition of natural gas at the wellhead 

indicated that emissions of natural gas during well completions contain various chemical species 

that are VOC. Additionally, we believe it would be overly burdensome to owners and operators 

and regulatory agencies to determine the VOC content of the gas emitted during well completion 

operations, particularly in cases where the VOC content may vary considerably over time. 

Similarly, natural gas is being used as a surrogate for VOC for pneumatic controllers because of

the proportional relationship between them. When a natural gas stream is emitted to the 

atmosphere, VOC in the gas also reaches the atmosphere since it is a component of the natural 

gas stream. The natural gas emissions occur without any physical separation, chemical separation 

or chemical reaction process of the chemical species within the natural gas; therefore, the 

proportion of VOC in natural gas is not altered during the course of being emitted to the 

atmosphere, and natural gas is an appropriate surrogate for VOC.

As for the comments that express concern that the EPA may consider natural gas as a “regulated 

NSR pollutant,” the EPA clarifies that PSD permitting requirements apply when “actual control” 

of the pollutant is required based on a regulatory requirement. (75 FR 17004-17023; April 2, 

2010). Natural gas, under the final rule, is not the regulated pollutant but is the measured 

surrogate that is used to determine applicability for purposes of controlling VOC, which is the 

regulated pollutant. Therefore, to clarify, natural gas will not be considered a “regulated NSR 

pollutant” as a result of it being used as a surrogate for VOC for determining applicability under 

this rulemaking.

Based on the above response, we do not believe there is a need to further revise the definition of 

“modification.”56

5.1 Request for Extension of the Compliance Date

Comment: Four commenters (4213, 4214, 4215, 4218) believe that the compliance date for the 

final rule should be extended. According to the commenters, as proposed, affected facilities 

would have to be in compliance as of the date of publication of the final rule. The commenters 

believe that compliance as of the date of publication would not allow affected facilities sufficient 

time to plan or prepare for compliance. 

Two commenters (4214, 4218) state that in order for many of the affected sources to be in 

compliance as of the publication date of the final rule, these sources would need to be replaced 

now, prior to the issuance of a final rule. One commenter (4214) requests that the EPA 

 

56 However, as exlaiend in section IX.A.1 of the preamble, EPA has specifically defined in subpart OOOO the term 

“modification” as it applies well completions conducted on gas wells that are refractured.
417

reconsider and allow at least 90 days from the publication date of the final rule for facilities to 

comply with the rule. Another commenter (4218) recommends that the compliance deadline for 

affected sources be extended to 180 days after publication of the final rule. 

One commenter (4240) strongly opposes any delay to the implementation of the NSPS. The 

commenter notes that delaying of the implementation of the requirements are contrary to the 

statute, which requires new sources on which construction is commenced after the date on which 

new standards are proposed to meet the standards once they begin operations. 

Response: The NSPS standards apply to affected facilities that commenced construction, 

modification or reconstruction after August 23, 2011. The subpart OOOO standards being 

promulgated in this action are effective 60 days after the date of publication in the Federal 

Register, which is the effective date of the final rule. This provides affected facilities with an 

additional 60 days from the publication date of the final rule for facilities to comply with the 

rule.

Additionally, in the final rule, because of uncertainties in the supply of REC equipment and labor 

over the near-term we are now requiring RECs for completion operations begun at nonexploratory and non-delineation wells on or after January 1, 2015. 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 before January 1, 2015 if possible. Completion operations at wildcat and delineation wells 

and non-wildcat and non-delineation low pressure wells are required to control flowback 

emissions with a completion combustion device unless it is technically infeasible or unsafe to do 

so. Rationale for this change is presented in section IX.B of the preamble to the final rule.

Also, in the final rule, the standards for certain pneumatic controllers and for storage vessels

apply to new and modified affected facilities after an adjustment period to allow build up of 

equipment or control devices needed to meet the standards. Rationale for these changes is 

presented in section IX.C and Eof the preamble to the final rule.

We believe that these changes in the final rule address the commenters’ concern about needing 

additional time to meet the standards without sacrificing the desired air quality benefits of the 

rule or impede production of oil or natural gas.

5.2 Rules are an Attempt to Regulate Methane and Other Greenhouse Gases

Comment: Nine commenters (0824, 2803, 3492, 4162, 4189, 4208, 4237, 4240, 4355) state that 

the EPA must regulate methane emissions from the oil and gas industry. The commenters 

continue by saying that methane is a potent greenhouse gas and poses a significant threat to
418

public health and welfare. Two commenters (4189, 4240) believe that the EPA’s failure to 

address methane pollution violates section 111 of the CAA and the EPA’s own longstanding 

practice for determining whether to regulate dangerous air pollutants. The commenters note that 

there are many other cost-effective control measures available to reduce these methane emissions 

and create substantial financial and public health benefits. Two commenters (3492, 4240) note 

that the EPA is legally obligated to regulate greenhouse gases based on the U.S. Supreme 

Court’s ruling in Massachusetts v. EPA. One commenter (4208) states that controlling methane 

emissions from this sector is also consistent with the recommendations recently issued by the 

Secretary of Energy Advisory Board’s Shale Gas Production Subcommittee. 

One commenter (4159) supports the EPA's decision not to regulate methane as part of this rule. 

The commenter believes that the regulation of GHG from oil and gas operations should be 

considered in a separate proposed rulemaking. The commenter urges the EPA to take into 

account the requirements and co-benefit reductions under the final version of this rulemaking 

before moving forward with any greenhouse gas regulation.

Six commenters (2245, 4164, 4174, 4177, 4178, 4192) believe that the actual aim of the 

proposed standards is to regulate GHG, notably methane. Four of the commenters (2245, 4164, 

4174, 4178) state that the regulations prescribe operating standards and practices that, for natural 

gas transmission and storage, aim almost exclusively at preventing methane from escaping these 

facilities.

One commenter (2245) states that the preamble acknowledges that the proposed regulations 

would achieve a significant reduction of methane emissions, but discounts these reductions as an 

incident, a co-benefit, of the proposed requirements for VOC control. According to the 

commenter, the EPA’s own analysis suggests otherwise. The commenter states that, according to 

the preamble, the proposed regulations will reduce VOC emissions by 540,000 tons and will 

reduce methane emissions by 3.4 million tons, six times more than the purportedly targeted 

pollutant.

According to the commenter (2245), using VOC regulations as a foil for regulating GHG is 

premature as a matter of policy, unfounded as a matter of law, inconsistent with prevailing 

regulatory policy and contrary to the country’s immediate energy and environmental interests. 

As a matter of policy, the commenter believes that it is simply too soon to begin regulating 

GHG, particularly methane escaping from natural gas transmission and storage systems. The 

commenter provides that the EPA promulgated its greenhouse gas reporting rule precisely to 

develop a database that would inform decisions about whether and how to regulate greenhouse 

gas emissions, including the establishment of NSPS. The commenter reports that the first set of 

reports from oil and natural gas systems on fugitive and vented greenhouse gas emissions (per 

subpart W of the greenhouse gas reporting rule) have not yet been submitted. The commenter 
419

opines that, today, there is simply not an adequate empirical basis for regulating greenhouse 

gases from natural gas transmission and storage systems.

The commenter (2245) also asserts that regulating greenhouse gases through these VOC 

requirements is also unnecessary as a matter of law. According to the commenter, the EPA 

issued the proposed rules to fulfill its obligations under a consent decree addressing the 

regulation of VOC and sulfur dioxide emissions from the “oil and natural gas production” source 

category. The commenter asserts that the EPA’s legal obligations extended solely to those 

pollutants and sources. The commenter argues that the expansive scope of the proposed rule, 

both as to pollutants (bringing in methane) and as to sources (bringing in transmission and 

storage) is not warranted by the litigation giving rise to these rules. 

Two commenters (4192, 4246) believe that the EPA should state clearly in the preamble that the 

proposed subpart OOOO is not considering or regulating methane as a covered pollutant.

Five commenters (4164, 4218, 4229, 4273, 4281) state that the EPA should not regulate “natural 

gas.” One commenter (4281) adds that there are many facilities where natural gas streams 

contain very low or no VOCs, for example, CBM. The commenter states that an increase in 

natural gas emissions does not necessarily increase the emission of VOCs or any other regulated 

pollutant under the Proposed Rule.

One commenter (4265) argues that the EPA’s justification for regulating emissions of VOCs 

from the natural gas industry under the proposed NSPS is unsupported. The commenter asserts 

that because the VOC content of natural gas is very low, the current attainment status in 

Michigan (and elsewhere) suggests that current levels of control of VOCs and other ozone 

precursors are adequately protecting public health. The commenter believes that the EPA is 

expanding the rule to address emissions of methane (a GHG) and other natural gas “pollutants” 

from all sources within the oil and natural gas industry. 

One commenter (4229) suggests there is a misapprehension that the EPA is deeming natural gas 

or its primary constituent – methane – to be a VOC or a pollutant regulated by the rule. The 

commenter states this misunderstanding could also arise from the proposed definition of 

“modification” in §60.5430. The commenter gives examples showing the EPA’s intent is not to 

regulate GHGs (methane) and that the EPA recognizes that methane and natural gas are not 

VOCs as such for purposes of the NSPS, although the EPA is also welcoming an opportunity to 

achieve the co-benefit of reducing GHG emissions. The commenter believes it is imperative that 

the NSPS not imply that natural gas is a pollutant. 

Two commenters (4266, 4273) state that there are insufficient conditions in the proposed rule to 

limit the applicability to streams that have a significant quantity of VOC, resulting in a NSPS 
420

regulation that can be interpreted to apply to streams with no VOCs. The commenter states that 

in this proposed rule, the term “natural gas” is used in the titles of the category, plants and 

equipment descriptions, as well as a surrogate for VOCs. The commenter states that many 

natural gas streams are mainly methane and have little or no VOC content when it is produced 

from the reservoir (thus the terms “dry gas” and “coal bed methane” that are common in the 

industry). The commenter states that though the EPA has previously stated that it does not intend 

to regulate GHGs within this rule, without some minimum applicability threshold for VOCs, the 

EPA is essentially regulating GHGs.

Two commenters (4218, 4225) believe using natural gas as a VOC surrogate in the proposed rule 

becomes the equivalent to the EPA regulating GHGs for low to no VOC gas streams though 

GHG regulation is something the EPA purports not to do in this proposal. One commenter 

(4218) adds that, to the extent the EPA is attempting to regulate GHGs under subpart OOOO, the 

EPA has failed to make the necessary findings to do so. The commenter states that section 111 of 

the CAA provides that the EPA may promulgate NSPS only for categories of sources that 

“cause, or contribute significantly to, air pollution which may reasonably be anticipated to

endanger public health or welfare.” The commenter concludes that because the EPA has not 

made an endangerment finding specific to GHG emissions and does not purport to do so in 

connection with this rulemaking, the EPA cannot regulate GHG emissions under subpart OOOO.

Response: The NSPS regulates VOC emsisions and not methane. For the reasons explained in 

section IX.A.2 of the final rule preamble, we are not taking final action in this rule with respect 

to regulation of methane. Rather, we intend to continue to evaluate the appropriateness of 

regulating methane with an eye toward taking additional steps if appropriate.

Because the EPA is not regulating methane in this rule, the EPA needs not address the 

claims that regulation of methane is not warrented by the litigation or that the EPA fails to make 

the necessary findings to regulate GHG (methane). With respect to the rule’s coverage of the 

transmission and storage segment of this sector, as explained in section IX.A.2 of the final rule 

preamble, the EPA has concluded that the listed oil and gas source category covers the 

oeprations for which we have established pernformance standards in the final rule. 

5.3 Regulation of NOx and other Pollutants

Comment: Two commenters (3492, 4189) state that the EPA has failed to regulate hydrogen 

sulfide (H2S) from the oil and gas industry. The commenters explain that hydrogen sulfide is a 

highly toxic gas that smells like rotten eggs and can lead to neurological impairment or death at 

relatively low concentrations. One commenter (4189) states there are numerous control 

technologies available for controlling hydrogen sulfide emissions from the oil and gas industry. 

The commenter asserts that the EPA must take action under section 111. 
421

One commenter (4189) states that the EPA must regulate particulate matter emissions from the 

oil and gas industry. The commenter asserts that particulate matter (PM10 and PM2.5) has been 

linked to respiratory and cardiovascular problems, including aggravated asthma attacks, chronic 

bronchitis, decreased lung function, heart attacks, and premature death. The commenter reports 

that sensitive populations, including the elderly, children, and people with existing heart or lung 

problems, are most at risk from particulate matter pollution. The commenter notes that 

particulate matter emissions occur during road and well-pad construction, heavy equipment 

moving dirt and leveling the ground and vehicles traveling back and forth on access roads. The 

commenter believes that there are numerous methods for controlling these emissions, such as 

using water for dust suppression, reduced speed limits, and planning to minimize road networks. 

One commenter (3492) states that the final rules must target nitrogen oxide (NOx) and sulfur 

dioxide (SO2) emissions from natural gas processing plants since Pennsylvania and the 

Allegheny National Forest are in the Northeast Ozone Transport Zone. 

Five commenters (4092, 4166, 4170, 4208, 4240) request that the proposed rule be expanded to 

address NOx emissions from the oil/gas sector. 

Response: Please see section IX.A.2 of the final rule preamble.
422

Appendix A. List of Commenters Cited in this RTC Document Submitting Comments To EPA Air and 

Radiation Docket Number EPA-HQ-OAR-2010-0505 Regarding the Oil and Natural Gas NSPS and NESHAP 

Reviews Proposed August 23, 2011

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

0400 September 9, 2011 Lisa Epifani

Gas Processors Association (GPA)

0412 September 9, 2011 Mari Ruckel

Texas Oil & Gas Association (TxOAG)

0422 September 8, 2011 Ken Zeserson

Planning Board Town of Ulysses

Tompkins County, NY

0978 September 15, 2011 Jim Littlefield

Surfers' Environmental Alliance (SEA)

0985 September 19, 2011 Patrick J. Nugent

Texas Pipeline Association (TPA)

1069 September 22, 2011 Mike and Judy Campsey

Buffalo Creek Watershed Association 

1090 September 16, 2011 Kate Williams

Alaska Oil and Gas Association (AOGA)

1187 September 28, 2011 Vorys, Sater, Seymour and Pease LLP

Ohio Oil and Gas Association (OOGA)

1296 September 29, 2011 Ken Mathews

Aeon Process Equipment and Controls

1350 September 29, 2011 David J. Ellenberger

National Wildlife Federation

1527 October 4, 2011 Deb Thomas

Powder River Basin Resource Council

Clark Resource Council

Pavillion Area Concerned Citizens

1644 October 4, 2011 Christian Alvarado

Railroad Commission of Texas

1657 October 5, 2011 Sara Arkle

Idaho Conservation League (ICL)
423

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

2245 October 11, 2011 Lisa S. Beal

Interstate Natural Gas Association of America (INGAA)

2718 October 11, 2011 Chris Daum

Oasis Montana Inc.

2750 September 14, 2011 Peter D. Robertson

America's Natural Gas Alliance (ANGA)

2803 October 12, 2011 Shaun Porter

Arkansas Water Protection Alliance

3350 October 20, 2011 Adam Peshek

Reason Foundation

3351 October 20, 2011 David Aguirre

Montana Dept. of Environmental Quality

3399 October 20, 2011 Chelsa Wagner

Pennsylvania House of Representatives

3408 October 24, 2011 Christine Griffin

Smithfield Township

3409 October 24, 2011 Vera Scroggins

Citizens For Clean Water

3447 October 24, 2011 Brad Richards

Illinois Oil & Gas Association

3456 October 21, 2011 Patrick Dowd

City of Pittsburgh, Pennsylvania

3459 October 20, 2011 Lon Burnam

House District 90

Texas House of Representatives

3460 October 24, 2011 Phyllis Mundy

Pennsylvania House of Representatives

3466 October 21, 2011 Camille "Bud" George

Commonwealth of Pennsylvania

House of Representatives

3467 October 24, 2011 John K. Baillie

Citizens for Pennsylvania's Future
424

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

3468 October 24, 2011 Frank L. Lindsey

Indiana Oil and Gas Association (INOGA)

3469 October 24, 2011 Randall R. LaBauve

NextEra Energy, Inc.

3470 October 24, 2011 Denny Larson

Global Community Monitor (GCM)

3473 October 25, 2011 Ann Campbell

House of Representatives

Commonwealth of Pennsylvania, Harrisburg

3474 October 24, 2011 Natalie Joubert

Consumer Energy Alliance (CEA)

3475 October 24, 2011 Christian Alvarado

Railroad Commission of Texas

3476 October 24, 2011 Frank I. Lindsey

CountryMark Energy Resources, LLC

3477 October 25, 2011 Alby Modiano

US Oil & Gas Association

3478 October 24, 2011 Pennsylvania House of Representatives

3492 October 24, 2011 Cathy Pedler

Allegheny Defense Project (ADP)

3495 October 24, 2011 Charles E. Smith

Countrymark Cooperative Holding Corp.

3527 October 24, 2011 Veronica Nasser

REM Technology Inc.

3528 October 24, 2011 Steven G. Folk

Red Willow Production Company, LLC

3529 October 25, 2011 Scott C. Blauvelt

East Management Services, LP (EMS)

3551 October 27, 2011 Cathy Purves

Trout Unlimited

3552 October 22, 2011 Michelle Naccarati-Chapkis

Women for a Healthy Environment
425

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

3560 October 31, 2011 Steve Henke

New Mexico Oil and Gas Association 

3562 October 20, 2011 John S. Lyons

Division for Air Quality

Commonwealth of Kentucky

3583 November 1, 2011 James Ferlo

Senate of Pennsylvania

3618 November 3, 2011 Chris Klaus

North Central Texas Clean Air Steering Committee

3619 November 3, 2011 Mark Burroughs and Jungus Jordan

North Texas Clean Air Steering Committee 

3638 November 7, 2011 Eugene Depasquale

Pennsylvania House of Representatives

3639 November 9, 2011 John S. Lyons

Kentucky Dept. for Environmental Protection

3928 November 17, 2011 Thoma Y. Au

Clean Air Board of Central Pennsylvania

4039 November 18, 2011 Roberta J. Jackson

Dominion Resources Services, Inc.

4041 November 18, 2011 Lori Payne

City of South Lake, Texas

4042 November 21, 2011 John A. Paul

Regional Air Pollution Control Agency Dayton, Ohio

4056 November 21, 2011 Sabrina N. Wilkin

Marathon Petroleum Company LP

4092 November 21, 2011 Alex Ryan-Bond

Ozone Transport Commission (OTC)

4104 November 22, 2011 Lisa S. Beal

Interstate Natural Gas Association of America (INGAA)

4135 November 25, 2011 John V. Corra

Wyoming Dept. of Environmental Quality
426

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

4137 November 23, 2011 Mike Brownell

Chesapeake Energy Corporation

4158 November 28, 2011 Trinh M. Tran

El Paso Corporation

4159 November 28, 2011 J. Kelly Robbins

Arkansas Independent Producers and Royalty Owners 

Association (AIPRO)

4160 November 28, 2011 Susan Combs

Texas Comptroller of Public Accounts

4161 November 28, 2011 Timothy Andrus

Utah Division of Air Quality

4162 November 29, 2011 Jon A. Mueller

Chesapeake Bay Foundation, Inc. (CBF)

4163 November 29, 2011 Grant Maki

Ohio Environmental Council (OEC)

4164 November 29, 2011 Leslie Witherspoon

Solar Turbines Incorporated

4165 November 29, 2011 Adam Berig

Colorado Oil & Gas Association (COGA)

4166 November 28, 2011 Ronald A. Amirikian

Delaware Dept. of Natural Resources

4167 November 29, 2011 Teddy Carter

Texas Independent Producers and Royalty Owners 

Association (TIPRO)

4168 November 29, 2011 C. Louis Renaud

Texas General Land Office

4170 November 29, 2011 Michael L. Krancer

Pennsylvania Dept. of Environmental Protection

4174 November 30, 2011 Richard Metcalf

LA Mid-Continent Oil and Gas Assn.

4175 November 30, 2011 John Dutton

Gas Compressor Association
427

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

4176 November 28, 2011 Dave Aguirre

Montana Dept. of Environmental Quality

4177 November 30, 2011 Mari Ruckel

Texas Oil and Gas Association

4178 November 28, 2011 Laura J. Finley

Oklahoma Dept. of Environmental Quality

4184 November 30, 2011 J. Jared Snyder

New York State Dept. of Environmental Conservation

Division of Air Resources

4185 November 30, 2011 Thomas Bach

Kinder Morgan Energy Partners, LP

4189 November 30, 2011 Earthjustice

Berks Gas Truth, et al.

4191 November 30, 2011 William C. Allison V

Colorado Dept. of Public Health and Environment

4192 November 30, 2011 Jeff Applekamp

Gas Processors Association (GPA)

4193 November 30, 2011 Eric J. Barndt

Black Hills Exploration And Production and Midstream 

LLCs

4208 November 30, 2011 S. William Becker

National Association of Clean Air Agencies (NACAA)

4209 November 30, 2011 Angie Burckhalter

Oklahoma Independent Petroleum Association (OIPA)

4210 November 30, 2011 Veronica Nasser

REM Technology, Inc.

4212 November 30, 2011 Veronica Nasser

REM Technology, Inc.

4213 November 30, 2011 Lisa Yoho

BG Americas & Global LNG (BGA)

4214 November 30, 2011 Anne Blankenship

West Virginia Oil and Natural Gas Association 

(WVONGA)
428

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

4215 November 30, 2011 Holly Propst

Western Business Roundtable

4216 November 30, 2011 Lee Fuller

Independent Petroleum Association of America (IPAA)

4217 November 30, 2011 Dan F. Hunter

ConocoPhillips Company

4218 November 30, 2011 Jessica L. Keiser

Targa Resources Corp.

4219 November 30, 2011 Patrick J. Nugent

Texas Pipeline Association (TPA)

4220 November 30, 2011 John Robitaille

Petroleum Association of Wyoming (PAW)

4221 November 30, 2011 Bruce Pendery

Wyoming Outdoor Council 

Environmental Defense Fund

4222 November 30, 2011 Rebecca Smith

State of Alaska Dept. of Natural Resources

Dept. of Environmental Conservation

4225 November 30, 2011 Stan Dempsey, Jr.

Colorado Petroleum Association (CPA)

4226 November 29, 2011 Carrie Crumpton

CONSOL Energy Inc.

4227 November 30, 2011 Rebecca Rentz

Exterran

4228 November 30, 2011 Lee Hinman

Noble Energy Inc.

4229 November 30, 2011 Amy D. Kapuga

Consumers Energy

4230 November 30, 2011 Renu M. Chakrabarty

West Virginia Dept. of Environmental Protection

Division of Air Quality
429

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

4231 November 29, 2011 Kathleen M. Sgamma

Western Energy Alliance

Montana Petroleum Association (MPA)

North Dakota Petroleum Council (NDPC)

4233 November 30, 2011 Joe Leonard

Devon Corporation

4234 November 30, 2011 Pamela A. Lacey

American Gas Association (AGA)

4235 November 30, 2011 Stan Dempsey, Jr.

Colorado Petroleum Association (CPA)

4236 November 30, 2011 Charlie Burd

Independent Oil and Gas Association of West Virginia 

(IOGAWV)

4237 November 30, 2011 Theodore Robinson

Citizen Power

4238 November 30, 2011 Cathy S. Woollums

MidAmerican Energy Holdings Company

4239 November 30, 2011 Daniel S. Sullivan

State of Alaska 

Dept. of Natural Resources

Dept. of Environmental Conservation 

4240 November 30, 2011 Craig Holt Segall

Sierra Club et al.

4241 November 30, 2011 Amy Farrell and Bruce Thompson

America’s Natural Gas Alliance (ANGA)

American Exploration and Petroleum Council (AXPC)

4242 November 30, 2011 Sparsh Khandeshi

Environmental Integrity Project (EIP)

4243 November 30, 2011 Katten Muchin Rosenman LLP

Air Permitting Forum

4244 December 1, 2011 Michael Pontiff

Newfield Exploration Company

4245 November 30, 2011 Jimmy D. Carlile
430

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

Permian Basin Petroleum Association 

4246 November 30, 2011 Carolann Montoya

Marcellus Shale Coalition (MSC)

4247 November 30, 2011 Kate Williams

Alaska Oil and Gas Association (AOGA)

4248 November 30, 2011 Laura A. Brust

American Chemistry Council (ACC)

4249 November 30, 2011 Gregory L. Ryan

DTE Energy

4250 November 30, 2011 Joe Osborne

Group Against Smog and Pollution (GASP)

4251 November 30, 2011 Gretchen C. Kern

Pioneer Natural Resources USA, Inc.

4252 November 30, 2011 Bill Grygar

Anadarko Petroleum Corporation

4253 November 30, 2011 Janice E. Nolen

American Lung Association et al.

4254 November 30, 2011 Stuart M. Kowalski

Slawson Exploration Company, Inc.

4255 November 30, 2011 Anthony J. Giuliani

Ohio Oil and Gas Association

4256 November 30, 2011 David A. Galt

Montana Petroleum Association

4257 November 30, 2011 Elizabeth deLone Paranhos

EDF and Wyoming Outdoor Council

4258 November 30, 2011 Steve P. Henke

New Mexico Oil & Gas Association (NMOGA)

4259 November 30, 2011 Christi Zeller

La Plata County Energy Council

4260 November 30, 2011 Ritu Talwar

Spectra Energy Corp
431

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

4261 November 30, 2011 Bryan D. Johnston

Louisiana Dept. of Environmental Quality 

4262 November 30, 2011 John C. Bosch

J. Bosch Ltd.

4263 November 30, 2011 Kenneth A. Malmquist

AECOM

4264 November 30, 2011 Clay Freeberg

Chevron Corporation

4265 November 30, 2011 Gregory L. Ryan

DTE Energy

4266 November 30, 2011 Matthew Todd

American Petroleum Institute (API)

4267 November 30, 2011 Dan Girand

Mack Energy Corp.

4268 November 30, 2011 John Dutton

Gas Compressor Association (GCA)

4269 November 30, 2011 Tommy Taylor

Texas Alliance of Energy Producers

4270 November 30, 2011 George Williams

Sempra Energy

4273 November 30, 2011 Shannon S. Broome, et al.

Air Permitting Forum

4274 November 29, 2011 Emily Krafjack

Wyoming County, Pennsylvania

4275 November 30, 2011 Bruce Baizel

Earthworks' Oil & Gas Accountability Project (OGAP)

4276 November 30, 2011 Elizabeth deLone Paranhos

Argyle-Bartonville Community Alliance, et al.

4281 November 30, 2011 R. Douglas Rogers

Marathon Oil Company

4282 November 30, 2011 Scott Crump

Quantum Resources Management, LLC
432

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

4296 November 30, 2011 Ralph Kisberg, et al.

Responsible Drilling Alliance

4316 November 30, 2011 Charles A. Whitehead

Linear Motion Technologies LP

4317 December 1, 2011 Carla L. Suszkowski

Range Resources-Appalachia, LLC

4320 November 30, 2011 Todd L. Normane

Talisman Energy USA, Inc.

4354 November 30, 2011 Matthew Todd

The Residual Risk Coalition (R2C)

4355 November 5, 2011 Nancy Wiggins

Yellowstone Valley Audubon Society

4356 November 30, 2011 Tangela Niemann

Texas Commission on Environmental Quality (TCEQ)

4357 November 30, 2011 John Bosch

Picarro

4358 December 5, 2011 Catherine H. Reheis-Boyd

Western States Petroleum Association

4375 November 30, 2011 David Presley

Clean Air Council (CAC)

4425 December 12, 2011 Katten Muchin Rosenman LLP

Air Permitting Forum

4456 December 13, 2011 Lisa Willis

Pennsylvania Independent Oil and Gas Association 

(PIOGA)

4457 November 30, 2011 Devorah Ancel

Sierra Club et al.

4458 November 30, 2011 Devorah Ancel

Sierra Club et al.

4459 November 30, 2011 Devorah Ancel

Sierra Club et al.
433

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation

4460 November 30, 2011 Devorah Ancel

Sierra Club et al.

4461 November 30, 2011 Devorah Ancel

Sierra Club et al.

4462 November 30, 2011 Devorah Ancel

Sierra Club et al.

4463 November 30, 2011 Devorah Ancel

Sierra Club et al.

4472 October 25, 2011 Elizabeth Ames Jones

Railroad Commission of Texas
434
435

Appendix B. Complete List of Commenters that Submitted Comments to EPA Air and Radiation Docket 

Number EPA-HQ-OAR-2010-0505 Regarding the Oil and Natural Gas NSPS and NESHAP Reviews 

Proposed August 23, 2011

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0082 August 3, 2011 Mass Comment Campaign sponsoring organization 

unknown (12)

0083 August 8, 2011 League of Conservation Voters

mass comment campaign (1,000)

0087 July 29, 2011 G. P. Sharpe

Private Citizen

0089 August 1, 2011 M. J. Kramer, Jr.

Private Citizen

0090 July 29, 2011 J. Lobdill

Private Citizen

0091 August 12, 2011 L. Theophilus

Private Citizen

0092 August 14, 2011 M. Chupa

Private Citizen

0093 August 14, 2011 J. Carter

Private Citizen

0094 August 15, 2011 J. Petrulionis

Private Citizen

0095 August 15, 2011 L. Goodwin

Private Citizen

0096 August 15, 2011 I. Putzer

Private Citizen

0097 August 16, 2011 J. Sergovic

Private Citizen

0098 August 4, 2011 T. Badal

Private Citizen

0099 August 9, 2011 R. Desy

Private Citizen

0100 August 9, 2011 D. Karney

Private Citizen

0101 August 9, 2011 H. Pedersen

Private Citizen

0102 August 9, 2011 M. Ward

Private Citizen

0103 August 9, 2011 S. Babuka

Private Citizen

0104 August 9, 2011 L. Smith

Private Citizen

0105 August 9, 2011 C. Whiting

Private Citizen

0106 August 10, 2011 T. Supowitz

Private Citizen
436

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0107 August 10, 2011 C. Lee

Private Citizen

0108 August 10, 2011 J. Higbie

Private Citizen

0109 August 10, 2011 G. & J. Preston

Private Citizens

0110 August 10, 2011 Brian CH

Private Citizen

0111 August 10, 2011 P. Groff

Private Citizen

0112 August 9, 2011 J. C. Djelal

Private Citizen

0113 August 9, 2011 C. Cicale

Private Citizen

0114 August 9, 2011 J. Wozniak

Private Citizen

0115 August 9, 2011 P. Hineline

Private Citizen

0116 August 9, 2011 T. Lamborn

Private Citizen

0117 August 9, 2011 M. Tommelleo

Private Citizen

0118 August 9, 2011 B. Paci

Private Citizen

0119 August 9, 2011 S. Duskin

Private Citizen

0120 August 9, 2011 K. Moore

Private Citizen

0121 August 9, 2011 T. Ronan

Private Citizen

0122 August 9, 2011 L. Pavlo

Private Citizen

0123 August 9, 2011 M. Carrella

Private Citizen

0124 August 9, 2011 A. Young

Private Citizen

0125 August 9, 2011 D. and S. Katz

Private Citizens

0126 August 9, 2011 L. Birch

Private Citizen

0127 August 9, 2011 F. Pierce

Private Citizen

0128 August 9, 2011 J. Marshall

Private Citizen

0129 August 9, 2011 M. Marchetti

Private Citizen
437

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0130 August 9, 2011 B. Silverstein

Private Citizen

0131 August 9, 2011 L. Gross

Private Citizen

0132 August 9, 2011 R. Rupert

Private Citizen

0133 August 9, 2011 T. Mannello

Private Citizen

0134 August 9, 2011 R. Edwards

Private Citizen

0135 August 9, 2011 A. Conklin-Wood

Private Citizen

0136 August 9, 2011 B. and D. Klaput

Private Citizens

0137 August 9, 2011 T. Reiff

Private Citizen

0138 August 9, 2011 M. Leitch

Private Citizen

0139 August 9, 2011 K. Swam

Private Citizen

0140 August 9, 2011 S. Heisey

Private Citizen

0141 August 9, 2011 C. Steinberg

Private Citizen

0142 August 9, 2011 T. Knapp

Private Citizen

0143 August 9, 2011 J. Brown

Private Citizen

0144 August 9, 2011 S. Seese

Private Citizen

0145 August 9, 2011 J. Branigan

Private Citizen

0146 August 9, 2011 J. and B. Freund

Private Citizens

0147 August 9, 2011 G. Palmer

Private Citizen

0149 August 25, 2011 J. Wenderoth

Private Citizen

0150 August 25, 2011 L. Fleisher

Private Citizen

0151 August 28, 2011 K. Petronko

Private Citizen

0152 August 30, 2011 J. Bennett

Private Citizen

0153 September 1, 2011 B. Brister

Private Citizen
438

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0154 September 1, 2011 D. Fuentes

Private Citizen

0155 September 1, 2011 M. Wood

Private Citizen

0156 September 1, 2011 F. Groot

Private Citizen

0157 September 1, 2011 P. Landua

Private Citizen

0158 September 1, 2011 G. Crouse

Private Citizen

0159 September 1, 2011 K. Berglund

Private Citizen

0160 September 2, 2011 S. Schmidt

Private Citizen

0161 September 2, 2011 S. Parker

Private Citizen

0162 September 2, 2011 B. Flowers

Private Citizen

0163 September 3, 2011 W. Sharfman

Private Citizen

0164 September 3, 2011 R. Sdano

Private Citizen

0165 September 4, 2011 V. Burris

Private Citizen

0166 August 31, 2011 WildEarth Guardians mass comment campaign 

(1,667)

0167 September 7, 2011 W. Arons

Private Citizen

0168 September 7, 2011 A. Leonard

Private Citizen

0169 September 7, 2011 M. Leitch

Private Citizen

0170 September 7, 2011 J. Waldron

Private Citizen

0171 September 7, 2011 D. M. Kelley

Private Citizen

0172 September 7, 2011 M. DeStefano

Private Citizen

0173 September 7, 2011 Dr. P. Mathieson

Private Citizen

0174 September 7, 2011 D. Shapiro

Private Citizen

0175 September 7, 2011 A. Eynon

Private Citizen

0176 September 7, 2011 H. Kropf

Private Citizen
439

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0177 September 7, 2011 S. Kirby

Private Citizen

0178 September 7, 2011 T. Stevens

Private Citizen

0179 September 7, 2011 J. Bruce

Private Citizen

0180 September 7, 2011 B. Mathers

Private Citizen

0181 September 6, 2011 S. Squier

Private Citizen

0182 September 6, 2011 R. Sauder

Private Citizen

0183 September 6, 2011 S. Finman

Private Citizen

0184 September 6, 2011 D. Lavender

Private Citizen

0185 September 6, 2011 V. Yasek

Private Citizen

0186 September 7, 2011 L. Davis

Private Citizen

0187 September 7, 2011 G. Price

Private Citizen

0188 September 7, 2011 L. Desimone

Private Citizen

0189 September 7, 2011 J. C. Djelal

Private Citizen

0190 September 7, 2011 B. Koenig

Private Citizen

0191 September 7, 2011 J. Frederick

Private Citizen

0192 September 7, 2011 S. Hammerman

Private Citizen

0193 September 7, 2011 B. Brigham

Private Citizen

0194 September 7, 2011 Dr. L. Burky

Private Citizen

0195 September 7, 2011 D. Craig

Private Citizen

0196 September 7, 2011 S. Corson-Finnerty

Private Citizen

0197 September 7, 2011 J. Forsberg

Private Citizen

0198 September 7, 2011 M. Garvin

Private Citizen

0199 August 23, 2011 League of Conservation Voters 

mass comment campaign (27)
440

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0200 August 30, 2011 Penn Environment mass comment campaign (1,763)

0201 September 6, 2011 M. Oviedo

Private Citizen

0202 September 6, 2011 K. and L. Smith

Private Citizens

0203 September 6, 2011 L. Hollister

Private Citizen

0204 September 6, 2011 C. Hollister

Private Citizen

0205 September 6, 2011 N. Liebert

Private Citizen

0206 September 7, 2011 K. Davidson

Private Citizen

0207 September 7, 2011 S. Foehl

Private Citizen

0208 September 7, 2011 K. Dabney

Private Citizen

0209 September 7, 2011 J. Dayl

Private Citizen

0210 September 7, 2011 T. Flynn III

Private Citizen

0211 September 7, 2011 J. Meade

Private Citizen

0212 September 7, 2011 J. Allison

Private Citizen

0213 September 7, 2011 E. Bell

Private Citizen

0214 September 7, 2011 Dr. A. Shah-Yukich

Private Citizen

0215 September 7, 2011 M. Kirby

Private Citizen

0216 September 7, 2011 C. Kishinchaand

Private Citizen

0217 September 7, 2011 C. Morrow

Private Citizen

0218 September 7, 2011 A. Tolins

Private Citizen

0219 September 7, 2011 M. S. Haines

Private Citizen

0220 September 7, 2011 S. Kolbowski

Private Citizen

0221 September 7, 2011 J. Nelson

Private Citizen

0222 September 6, 2011 M. Stanton

Private Citizen
441

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0223 September 6, 2011 J. and N. Payne

Private Citizen

0224 September 6, 2011 R. and E. Garrison

Private Citizens

0225 September 6, 2011 L. Garfinkel

Private Citizen

0226 September 6, 2011 T. Jiunta

Private Citizen

0227 September 6, 2011 K. Gosliner

Private Citizen

0228 September 6, 2011 A. Bevan

Private Citizen

0229 September 6, 2011 M. Hunt

Private Citizen

0230 September 6, 2011 E. Smyser

Private Citizen

0231 September 6, 2011 M. Escobar

Private Citizen

0232 September 7, 2011 N. Corcoran

Private Citizen

0233 September 6, 2011 E. Falconi

Private Citizen

0234 September 6, 2011 L. Wenneker

Private Citizen

0235 September 6, 2011 C. Matthews

Private Citizen

0236 September 6, 2011 L. Davidson

Private Citizen

0237 September 6, 2011 M. Fallon

Private Citizen

0238 September 6, 2011 Anonymous public comment

0239 September 6, 2011 K. Gering

Private Citizen

0240 September 6, 2011 M. Bertini

Private Citizen

0241 September 7, 2011 R. DuPlessis

Private Citizen

0242 September 7, 2011 R. Liebert

Private Citizen

0243 September 7, 2011 P. Coleman

Private Citizen

0244 September 7, 2011 S. Petrie

Private Citizen

0245 September 7, 2011 J. Walsh

Private Citizen
442

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0246 September 7, 2011 E. Perchonock

Private Citizen

0247 September 7, 2011 V. Ross

Private Citizen

0248 September 7, 2011 L. Torrieri

Private Citizen

0249 September 7, 2011 A. Tryba

Private Citizen

0250 September 7, 2011 S. Kunz

Private Citizen

0251 September 7, 2011 A. McFadden

Private Citizen

0252 September 7, 2011 D. Hartz

Private Citizen

0253 September 7, 2011 M. Miller

Private Citizen

0254 September 7, 2011 M. Stewart

Private Citizen

0255 September 7, 2011 Dr. M. M. Kyde

Private Citizen

0256 September 8, 2011 D. Robinson

Private Citizen

0257 September 8, 2011 M. Polansky

Private Citizen

0258 September 8, 2011 J. Edgar

Private Citizen

0259 September 8, 2011 E. Hart

Private Citizen

0260 September 8, 2011 J. Wiener

Private Citizen

0261 September 8, 2011 R. Doyle

Private Citizen

0262 September 8, 2011 K. White

Private Citizen

0263 September 8, 2011 M. Potts

Private Citizen

0264 September 7, 2011 J. McCartney

Private Citizen

0265 September 7, 2011 J. Bogle

Private Citizen

0266 September 7, 2011 A. Rice

Private Citizen

0267 September 7, 2011 R. Bruenn

Private Citizen

0268 September 7, 2011 L. Roese

Private Citizen
443

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0269 September 7, 2011 R. and C. Magarigal

Private Citizen

0270 September 7, 2011 B. Raley

Private Citizen

0271 September 8, 2011 A. Brennan

Private Citizen

0272 September 8, 2011 D. Martinez

Private Citizen

0273 September 8, 2011 Dr. S. Lochner

Private Citizen

0274 September 7, 2011 F. Powell

Private Citizen

0275 September 7, 2011 J. Elliott

Private Citizen

0276 September 7, 2011 R. Cava

Private Citizen

0277 September 7, 2011 R. Davey

Private Citizen

0278 September 7, 2011 J. Kunzelman

Private Citizen

0279 September 7, 2011 J. Sadicario

Private Citizen

0280 September 7, 2011 J. Barker

Private Citizen

0281 September 7, 2011 C. Kell

Private Citizen

0282 September 7, 2011 J. Polak

Private Citizen

0283 September 7, 2011 V. Brown

Private Citizen

0284 September 7, 2011 R. Cope

Private Citizen

0285 September 7, 2011 A. Suhrie

Private Citizen

0286 September 7, 2011 J. Davidson

Private Citizen

0287 September 7, 2011 K. Armbruster

Private Citizen

0288 September 7, 2011 B. O'Connor

Private Citizen

0289 September 7, 2011 K. Eldridge

Private Citizen

0290 September 7, 2011 J. Walter

Private Citizen

0291 September 7, 2011 Dr. V. Nachmias

Private Citizen
444

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0292 September 7, 2011 A. Ciampa

Private Citizen

0293 September 7, 2011 Dr. G. Hackenberg

Private Citizen

0294 September 7, 2011 C. Hunt

Private Citizen

0295 September 7, 2011 Dr. S. Adelman

Private Citizen

0296 September 7, 2011 R. Obeski

Private Citizen

0297 September 7, 2011 R. Buchanan

Private Citizen

0298 September 7, 2011 J. Lenke

Private Citizen

0299 September 7, 2011 N. West

Private Citizen

0300 September 7, 2011 R. Schmetzer

Private Citizen

0301 September 7, 2011 M. Williams

Private Citizen

0302 September 7, 2011 P. Reutemann

Private Citizen

0303 September 7, 2011 Dr. P. Eaken

Private Citizen

0304 September 7, 2011 W. MacLuckie

Private Citizen

0305 September 7, 2011 P. Turk

Private Citizen

0306 September 7, 2011 D. Urban

Private Citizen

0307 September 7, 2011 S. Nicklin

Private Citizen

0308 September 7, 2011 R. Brunner

Private Citizen

0309 September 7, 2011 R. Slabe

Private Citizen

0310 September 7, 2011 E. Friel

Private Citizen

0311 September 7, 2011 B. Nye

Private Citizen

0312 September 7, 2011 J. Mayher

Private Citizen

0313 September 7, 2011 S. Bumbaugh

Private Citizen

0314 September 7, 2011 H. M. Bracken

Private Citizen
445

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0315 September 7, 2011 L. Babbey

Private Citizen

0316 September 7, 2011 D. Heagy

Private Citizen

0317 September 7, 2011 L. Jeub

Private Citizen

0318 September 7, 2011 J. Inskeep

Private Citizen

0319 September 7, 2011 R. Harper

Private Citizen

0320 September 7, 2011 Dr. L. Sell

Private Citizen

0321 September 7, 2011 R. Abrams

Private Citizen

0322 September 8, 2011 C. Alberici

Private Citizen

0323 September 7, 2011 S. Newbury

Private Citizen

0324 September 8, 2011 P. Donohue

Private Citizen

0325 September 8, 2011 B. Riggs

Private Citizen

0326 September 8, 2011 B. Schmitt

Private Citizen

0327 September 8, 2011 K. Good

Private Citizen

0328 September 7, 2011 S. Burg

Private Citizen

0329 September 7, 2011 K. James

Private Citizen

0330 September 7, 2011 A. Difiore

Private Citizen

0331 September 7, 2011 D. Simons

Private Citizen

0332 September 7, 2011 T. Lee

Private Citizen

0333 September 7, 2011 T. Lucas

Private Citizen

0334 September 8, 2011 B. Campbell

Private Citizen

0335 September 7, 2011 W. Hollenbach

Private Citizen

0336 September 7, 2011 Dr. H. Bitaxis

Private Citizen

0337 September 7, 2011 V. Woolridge

Private Citizen
446

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0338 September 7, 2011 L. Daly

Private Citizen

0339 September 7, 2011 T. Dignazio

Private Citizen

0340 September 7, 2011 M. Dawley

Private Citizen

0341 September 7, 2011 A. Kurpaska

Private Citizen

0342 September 7, 2011 R. Loverdi

Private Citizen

0343 September 7, 2011 Dr. J. Confer

Private Citizen

0344 September 7, 2011 A. McGee

Private Citizen

0345 September 7, 2011 D. Fellenberg

Private Citizen

0346 September 7, 2011 L. Michaels

Private Citizen

0347 September 7, 2011 S. Sanders

Private Citizen

0348 September 7, 2011 Dr. S. Kirk

Private Citizen

0349 September 7, 2011 B. Handler

Private Citizen

0350 September 7, 2011 D. MacInnes

Private Citizen

0351 September 7, 2011 M. Leitch

Private Citizen

0352 September 7, 2011 W. Witczak

Private Citizen

0353 September 7, 2011 M. Keegan

Private Citizen

0354 September 8, 2011 J. Pennington

Private Citizen

0355 September 8, 2011 L. Theophanis

Private Citizen

0356 September 8, 2011 Dr. J. V. Murphy

Private Citizen

0357 September 7, 2011 A. Young

Private Citizen

0358 September 7, 2011 K. Black

Private Citizen

0359 September 7, 2011 M. Van Kirk

Private Citizen

0360 September 7, 2011 S. Comfort

Private Citizen
447

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0361 September 7, 2011 T. Walker

Private Citizen

0362 September 7, 2011 M. Hufford

Private Citizen

0363 September 7, 2011 O. Brubaker

Private Citizen

0364 September 8, 2011 K. Bates

Private Citizen

0365 September 8, 2011 A. Arendas

Private Citizen

0366 September 7, 2011 D. Plank

Private Citizen

0367 September 7, 2011 T. Kerr

Private Citizen

0368 September 7, 2011 A. Will

Private Citizen

0369 September 7, 2011 M. Clark

Private Citizen

0370 September 7, 2011 M. Hamilton

Private Citizen

0371 September 7, 2011 J. Tjiattas

Private Citizen

0372 September 7, 2011 M. Schueltz

Private Citizen

0373 September 7, 2011 C. Root

Private Citizen

0374 September 7, 2011 S. Cundiff

Private Citizen

0375 September 7, 2011 J. Gaadt

Private Citizen

0376 September 7, 2011 G. Strandlien

Private Citizen

0377 September 7, 2011 C. Crocker

Private Citizen

0378 September 7, 2011 E. Rattan

Private Citizen

0379 September 7, 2011 B. Drummey

Private Citizen

0380 September 7, 2011 L. Bean

Private Citizen

0381 September 7, 2011 K. Maloney

Private Citizen

0382 September 7, 2011 D. Kobus

Private Citizen

0383 September 7, 2011 D. Coyle

Private Citizen
448

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0384 September 7, 2011 G. Thomson

Private Citizen

0385 September 7, 2011 F. Gilmore

Private Citizen

0386 September 7, 2011 M. C. Knobil

Private Citizen

0387 September 7, 2011 B. Hammarstrom

Private Citizen

0388 September 7, 2011 F. Harkings

Private Citizen

0389 September 7, 2011 E. Barnes

Private Citizen

0390 September 7, 2011 L. Lalena

Private Citizen

0391 September 8, 2011 S. Bender

Private Citizen

0392 September 8, 2011 Dr. M. Sarfaty

Private Citizen

0393 September 8, 2011 R. Dumm

Private Citizen

0394 September 8, 2011 K. Hrabovsky

Private Citizen

0395 September 8, 2011 N. Bella

Private Citizen

0396 September 8, 2011 M. Huegel

Private Citizen

0397 September 8, 2011 T. Kearney

Private Citizen

0398 September 8, 2011 B. Rooney

Private Citizen

0399 September 8, 2011 T. Bissinger

Private Citizen

0400 September 9, 2011 Jeff Applekamp

Gas Processors Association

0401 September 8, 2011 Dr. M. Donlin

Private Citizen

0402 September 7, 2011 K. Fidorra

Private Citizen

0403 September 7, 2011 D. Dixon

Private Citizen

0404 September 7, 2011 Y. Schwartz

Private Citizen

0405 September 7, 2011 M. Bowser

Private Citizen

0406 September 7, 2011 S. Landenwitsch

Private Citizen
449

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0407 September 7, 2011 D. Becker

Private Citizen

0408 September 7, 2011 S. Robinson

Private Citizen

0409 September 7, 2011 H. Turner

Private Citizen

0410 September 7, 2011 D. Rollfinke

Private Citizen

0411 September 7, 2011 P. Greene

Private Citizen

0412 September 9, 2011 Deb Hastings

Texas Oil and Gas Association

0413 September 8, 2011 M. Mostello

Private Citizen

0414 September 8, 2011 P. Paulsen

Private Citizen

0415 September 8, 2011 J. Stomato

Private Citizen

0416 September 8, 2011 D. Dudrick

Private Citizen

0417 September 8, 2011 J. Zeserson

Private Citizen

0418 September 8, 2011 M. Bertonaschi

Private Citizen

0419 September 9, 2011 A. Walker

Private Citizen

0420 September 9, 2011 M. Castillo

Private Citizen

0421 September 9, 2011 S. Breitenbeck

Private Citizen

0422 September 8, 2011 Ken Zeserson

Planning Board Town of Ulysses, Tompkins County, 

NY

0423 September 9, 2011 A. Bevan

Private Citizen

0424 September 9, 2011 J. Feldman

Private Citizen

0425 September 9, 2011 A. Mento

Private Citizen

0426 September 9, 2011 C. Mathews

Private Citizen

0427 September 9, 2011 M. Beuth

Private Citizen

0428 September 9, 2011 R. Schaef

Private Citizen
450

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0429 September 9, 2011 G. Henze

Private Citizen

0430 September 9, 2011 M. Mcmackin

Private Citizen

0431 September 9, 2011 D. Maurer

Private Citizen

0432 September 9, 2011 E. McDade

Private Citizen

0433 September 9, 2011 D. McManus

Private Citizen

0434 September 9, 2011 J. Kesich

Private Citizen

0435 September 19, 2011 S. Wojnaroski

Private Citizen

0436 September 10, 2011 B. Brendel

Private Citizen

0437 September 12, 2011 J. Carricato

Private Citizen

0438 September 10, 2011 L. Altfest

Private Citizen

0439 September 10, 2011 R. Robitaille

Private Citizen

0440 September 10, 2011 H. Klussman

Private Citizen

0441 September 10, 2011 T. Mac Krell

Private Citizen

0442 September 10, 2011 J. Mitchell

Private Citizen

0443 September 10, 2011 C. Spina

Private Citizen

0444 September 10, 2011 M. Miller

Private Citizen

0445 September 10, 2011 T. Verts

Private Citizen

0446 September 10, 2011 K. Van Dame

Private Citizen

0447 September 10, 2011 I. Miller

Private Citizen

0448 September 10, 2011 K. Krimmel

Private Citizen

0449 September 11, 2011 R. Hynosky

Private Citizen

0450 September 11, 2011 J. Gratz

Private Citizen

0451 September 11, 2011 C. Swan

Private Citizen
451

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0452 September 11, 2011 C. Moses

Private Citizen

0453 September 11, 2011 T. Sefcik

Private Citizen

0454 September 11, 2011 J. Mason

Private Citizen

0455 September 11, 2011 D. Wright

Private Citizen

0456 September 11, 2011 T. Curran

Private Citizen

0457 September 12, 2011 K. Kirlew

Private Citizen

0458 September 12, 2011 K. McDonough

Private Citizen

0459 September 14, 2011 Dr. D. Bassett

Private Citizen

0460 September 14, 2011 J. Waldron

Private Citizen

0461 September 14, 2011 E. Christy

Private Citizen

0462 September 14, 2011 J. Marsh

Private Citizen

0463 September 14, 2011 U. Reed

Private Citizen

0464 September 14, 2011 P. McGrath

Private Citizen

0465 September 14, 2011 M. Leitch

Private Citizen

0466 September 14, 2011 P. Greene

Private Citizen

0467 September 14, 2011 K. Jansa

Private Citizen

0468 September 14, 2011 H. Kropf

Private Citizen

0469 September 14, 2011 D. Kelly

Private Citizen

0470 September 14, 2011 C. A. Parowski

Private Citizen

0471 September 14, 2011 F. Trimarchi

Private Citizen

0472 September 14, 2011 E. Deluca

Private Citizen

0473 September 14, 2011 R. Ludlow

Private Citizen

0474 September 14, 2011 M. Hennemann

Private Citizen
452

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0475 September 14, 2011 V. Prince

Private Citizen

0476 September 14, 2011 J. Roden

Private Citizen

0477 September 14, 2011 J. Kurilla

Private Citizen

0478 September 14, 2011 C. Corbelli

Private Citizen

0479 September 14, 2011 C. OLick

Private Citizen

0480 September 14, 2011 A. Zangrilli

Private Citizen

0481 September 14, 2011 K. Slagle

Private Citizen

0482 September 14, 2011 K. W. Reed

Private Citizen

0483 September 14, 2011 Heather Stewart

Private Citizen

0484 September 14, 2011 C. and R. Donahey

Private Citizens

0485 September 14, 2011 Dr. A. Dahm

Private Citizen

0486 September 14, 2011 D. Lavender

Private Citizen

0487 September 14, 2011 J. Walter

Private Citizen

0488 September 14, 2011 J. Bogle

Private Citizen

0489 September 13, 2011 C. Snyder

Private Citizen

0490 September 15, 2011 Anonymous public comment

0491 September 15, 2011 J. Rego

Private Citizen

0492 September 15, 2011 Anonymous public comment

0493 September 14, 2011 C. A. Kell

Private Citizen

0494 September 14, 2011 Dr. K. Smith

Private Citizen

0495 September 14, 2011 K. Keefe

Private Citizen

0496 September 14, 2011 Dr. B. Monahan

Private Citizen

0497 September 14, 2011 J. Bradley

Private Citizen

0498 September 14, 2011 B. Campbell

Private Citizen
453

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0499 September 14, 2011 M. Skinner

Private Citizen

0500 September 14, 2011 P. di Francesco

Private Citizen

0501 September 14, 2011 N. Monroe

Private Citizen

0502 September 14, 2011 R. Williams

Private Citizen

0503 September 14, 2011 J. Barker

Private Citizen

0504 September 14, 2011 B. Bernhardy

Private Citizen

0505 September 14, 2011 T. Gordon

Private Citizen

0506 September 12, 2011 M. A. Bentz

Private Citizen

0507 September 14, 2011 B. Abraham

Private Citizen

0508 September 14, 2011 N. Bella

Private Citizen

0509 September 14, 2011 T. Hallidy

Private Citizen

0510 September 14, 2011 K. Ellis

Private Citizen

0511 September 14, 2011 M. L. Myers

Private Citizen

0512 September 14, 2011 R. Schmetzer

Private Citizen

0513 September 14, 2011 J. Levins-Rivera

Private Citizen

0514 September 14, 2011 Dr. J. Dinger

Private Citizen

0515 September 14, 2011 L. Gustafson

Private Citizen

0516 September 14, 2011 D. Greenspan

Private Citizen

0517 September 14, 2011 J. and N. Lutz

Private Citizens

0518 September 14, 2011 L. Whelden

Private Citizen

0519 September 14, 2011 D. Fazio

Private Citizen

0520 September 12, 2011 H. Elkins

Private Citizen

0521 September 14, 2011 V. Watson

Private Citizen
454

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0522 September 14, 2011 S. V. Wert

Private Citizen

0523 September 14, 2011 R. Robinson

Private Citizen

0524 September 14, 2011 M. Collins

Private Citizen

0525 September 14, 2011 J. Pawlak

Private Citizen

0526 September 14, 2011 L. Griffin

Private Citizen

0527 September 14, 2011 C. Getty

Private Citizen

0528 September 14, 2011 L. Lane

Private Citizen

0529 September 14, 2011 E. Krawiec

Private Citizen

0530 September 14, 2011 J. Schnakenberg

Private Citizen

0531 September 14, 2011 Dr. T. Apple

Private Citizen

0532 September 14, 2011 T. Brink

Private Citizen

0533 September 14, 2011 Grace A.

Private Citizen

0534 September 14, 2011 S. Goldsmith

Private Citizen

0535 September 14, 2011 P. Crownfield

Private Citizen

0536 September 14, 2011 M. Duda

Private Citizen

0537 September 14, 2011 G. Trudeau

Private Citizen

0538 September 14, 2011 Dr. J. Anderson

Private Citizen

0539 September 14, 2011 J. Gantz

Private Citizen

0540 September 14, 2011 Dr. A. Klinger

Private Citizen

0541 September 12, 2011 N. McDonald

Private Citizen

0542 September 14, 2011 S. Foehl

Private Citizen

0543 September 14, 2011 Dr. A. Ranere

Private Citizen

0544 September 12, 2011 Dr. G. Gallo

Private Citizen
455

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0545 September 14, 2011 E. Spiegel

Private Citizen

0546 September 14, 2011 N. Bickham

Private Citizen

0547 September 14, 2011 G. B. Uhler

Private Citizen

0548 September 14, 2011 T. and A. McLaughlin

Private Citizens

0549 September 14, 2011 J. and C. Harter

Private Citizen

0550 September 14, 2011 J. Fava

Private Citizen

0551 September 14, 2011 J. Miller

Private Citizen

0552 September 15, 2011 C. Kishinchand

Private Citizen

0553 September 15, 2011 Dr. D. Hamilton

Private Citizen

0554 September 14, 2011 D. Read

Private Citizen

0555 September 14, 2011 J. Wuenschel

Private Citizen

0556 September 14, 2011 M. Filoromo

Private Citizen

0557 September 14, 2011 S. Novick

Private Citizen

0558 September 14, 2011 D. Weinkauf

Private Citizen

0559 September 14, 2011 N. Dupree

Private Citizen

0560 September 14, 2011 T. Armstrong

Private Citizen

0561 September 15, 2011 M. Daniels

Private Citizen

0562 September 15, 2011 M. Wessant

Private Citizen

0563 September 14, 2011 D. Morse

Private Citizen

0564 September 14, 2011 Dr. J. Dresser

Private Citizen

0565 September 14, 2011 J. Ammon

Private Citizen

0566 September 14, 2011 S. Dahne

Private Citizen

0567 September 14, 2011 D. Hartz

Private Citizen
456

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0568 September 14, 2011 Dr. D. Ahl

Private Citizen

0569 September 14, 2011 B. Doxtater

Private Citizen

0570 September 12, 2011 M. Waltman

Private Citizen

0571 September 14, 2011 J. Greenwald

Private Citizen

0572 September 15, 2011 J. Hoover

Private Citizen

0573 September 15, 2011 B. Birchard

Private Citizen

0574 September 15, 2011 T. Seay

Private Citizen

0575 September 14, 2011 S. Lach

Private Citizen

0576 September 14, 2011 H. Gogins

Private Citizen

0577 September 15, 2011 M. Sokol

Private Citizen

0578 September 14, 2011 J. Fishman

Private Citizen

0579 September 14, 2011 L. Simmons

Private Citizen

0580 September 14, 2011 J. McMullen

Private Citizen

0581 September 14, 2011 Dr. A. Norman

Private Citizen

0582 September 14, 2011 J. Petrisek

Private Citizen

0583 September 14, 2011 V. Hays

Private Citizen

0584 September 14, 2011 C. Boyle

Private Citizen

0585 September 14, 2011 J. Martini

Private Citizen

0586 September 15, 2011 Dr. W. Davis

Private Citizen

0587 September 15, 2011 W. Montgomery

Private Citizen

0588 September 15, 2011 M. Warren

Private Citizen

0589 September 15, 2011 E. Vaughn

Private Citizen

0590 September 15, 2011 C. Schmalz

Private Citizen
457

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0591 September 14, 2011 V. Woorlidge

Private Citizen

Private Citizen

0592 September 14, 2011 P. Herlong

Private Citizen

0593 September 13, 2011 D. Rosenberger

Private Citizen

0594 September 14, 2011 Dr. S. Loughlin

Private Citizen

0595 September 14, 2011 A. Marx

Private Citizen

0596 September 14, 2011 T. Dignazio

Private Citizen

0597 September 14, 2011 A. Hernandez

Private Citizen

0598 September 14, 2011 M. Pavlovich

Private Citizen

0599 September 14, 2011 A. Hernandez

Private Citizen

0600 September 14, 2011 Dr. E. Hulsey

Private Citizen

0601 September 14, 2011 C. Wolfe

Private Citizen

0602 September 14, 2011 A. Kurland

Private Citizen

0603 September 14, 2011 S. Weikart

Private Citizen

0604 September 14, 2011 J. Minor

Private Citizen

0605 September 14, 2011 Dr. M. Cole

Private Citizen

0606 September 14, 2011 P. Scheirer

Private Citizen

0607 September 14, 2011 E. Racoosin

Private Citizen

0608 September 14, 2011 M. Genin

Private Citizen

0609 September 14, 2011 T. Crawford

Private Citizen

0610 September 14, 2011 M. Hadcock

Private Citizen

0611 September 14, 2011 D. A. Pedtke, Sr.

Private Citizen

0612 September 14, 2011 M. A. Lajoie-Sandroff

Private Citizen
458

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0613 September 15, 2011 P. Dritt

Private Citizen

0614 September 15, 2011 C. Bechtle

Private Citizen

0615 September 15, 2011 S. Blair

Private Citizen

0616 September 15, 2011 S. Babbitt

Private Citizen

0617 September 15, 2011 P. Cohen

0618 September 14, 2011 Earthjustice mass comment campaign (58,723)

0619 September 13, 2011 M. O. Moyer

Private Citizen

0620 September 14, 2011 S. Finman

Private Citizen

0621 September 14, 2011 R. Klaput

Private Citizen

0622 September 14, 2011 M. Heilman

Private Citizen

0623 September 14, 2011 W. Hardenberg

Private Citizen

0624 September 14, 2011 E. Binder

Private Citizen

0625 September 14, 2011 R. Lernberg

Private Citizen

0626 September 14, 2011 M. Welke

Private Citizen

0627 September 14, 2011 P. and P. French

Private Citizen

0628 September 14, 2011 K. Wicce

Private Citizen

0629 September 14, 2011 S. Barbier

Private Citizen

0630 September 14, 2011 S. Robeson

Private Citizen

0631 September 14, 2011 J. Cunningham

Private Citizen

0632 September 14, 2011 J. Conrardy

Private Citizen

0633 September 14, 2011 S. Tomkiel

Private Citizen

0634 September 14, 2011 Dr. T. Kauffman

Private Citizen

0635 September 14, 2011 M. Cleaves

Private Citizen

0636 September 14, 2011 R. E. Carlson

Private Citizen
459

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0637 September 14, 2011 J. A. Mungai

Private Citizen

0638 September 14, 2011 L. Abbe

Private Citizen

0639 September 14, 2011 R. Grimm

Private Citizen

0640 September 14, 2011 Dr. D. Harrison

Private Citizen

0641 September 15, 2011 P. Hanson

Private Citizen

0642 September 15, 2011 D. Selvaggio

Private Citizen

0643 September 15, 2011 K. Jones

Private Citizen

0644 September 15, 2011 B. M. Bean

Private Citizen

0645 September 15, 2011 J. Glover

Private Citizen

0646 September 15, 2011 S. Silk

Private Citizen

0647 September 15, 2011 P. Daniello

Private Citizen

0648 September 15, 2011 Dr. M. Bookbinder

Private Citizen

0649 September 15, 2011 T. Mac Krell

Private Citizen

0650 September 15, 2011 L. Koelle

Private Citizen

0651 September 15, 2011 Dr. G. Crouse

Private Citizen

0652 September 14, 2011 R. Moore

Private Citizen

0653 September 14, 2011 A. Lowe

Private Citizen

0654 September 14, 2011 R. Sheresh

Private Citizen

0655 September 14, 2011 P. Megowan

Private Citizen

0656 September 14, 2011 Dr. J. Brauner

Private Citizen

0657 September 14, 2011 K. Eysenbach

Private Citizen

0658 September 15, 2011 L. Stock

Private Citizen

0659 September 15, 2011 V. Murti

Private Citizen
460

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0660 September 15, 2011 J. and W. MacDonald

Private Citizens

0661 September 15, 2011 S. Alex

Private Citizen

0662 September 15, 2011 Dr. C. Leman

Private Citizen

0663 September 15, 2011 L. Sharp

Private Citizen

0664 September 15, 2011 J. Masi

Private Citizen

0665 September 15, 2011 Dr. P. A. Anasasio

Private Citizen

0666 September 15, 2011 C. Lisowski

Private Citizen

0667 September 15, 2011 B. Peiffer

Private Citizen

0668 September 14, 2011 A. Phillipson

Private Citizen

0669 September 14, 2011 P. Lambert

Private Citizen

0670 September 14, 2011 B. Bennett

Private Citizen

0671 September 15, 2011 G. James

Private Citizen

0672 September 15, 2011 D. V. Goodman

Private Citizen

0673 September 14, 2011 D. Pino

Private Citizen

0674 September 15, 2011 K. Gresham

Private Citizen

0675 September 15, 2011 P. Shabazian

Private Citizen

0676 September 14, 2011 Dr. L. Santer

Private Citizen

0677 September 14, 2011 J. Neely

Private Citizen

0678 September 14, 2011 S. Sears

Private Citizen

0679 September 15, 2011 V. Cardellini

Private Citizen

0680 September 15, 2011 A. Ulrich

Private Citizen

0681 September 15, 2011 G. Sengstake

Private Citizen

0682 September 15, 2011 C. E. Krause

Private Citizen
461

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0683 September 14, 2011 L. Trautman

Private Citizen

0684 September 14, 2011 E. Flower

Private Citizen

0685 September 14, 2011 P. Battisti

Private Citizen

0686 September 14, 2011 A. Cohen

Private Citizen

0687 September 14, 2011 T. McHugh

Private Citizen

0688 September 15, 2011 J. DiSalle

Private Citizen

0689 September 14, 2011 A. Mudd

Private Citizen

0690 September 14, 2011 L. Lawrence

Private Citizen

0691 September 14, 2011 L. Greco

Private Citizen

0692 September 14, 2011 Dr. K. Cross

Private Citizen

0693 September 14, 2011 E. Barlow

Private Citizen

0694 September 14, 2011 Dr. B. Prairie

Private Citizen

0695 September 15, 2011 J. Hohl

Private Citizen

0696 September 15, 2011 S. Blake

Private Citizen

0697 September 15, 2011 Dr. M. McGuire

Private Citizen

0698 September 15, 2011 A. Cornford

Private Citizen

0699 September 15, 2011 J. Gerske

Private Citizen

0700 September 15, 2011 M. Greer

Private Citizen

0701 September 15, 2011 D. Burgess

Private Citizen

0702 September 15, 2011 J. Seekins

Private Citizen

0703 September 15, 2011 C. Clements

Private Citizen

0704 September 15, 2011 Dr. D. Mintz

Private Citizen

0705 September 15, 2011 A. Ambler

Private Citizen
462

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0706 September 15, 2011 Dr. J. Harmon

Private Citizen

0707 September 15, 2011 C. Petty

Private Citizen

0708 September 15, 2011 M. Britton

Private Citizen

0709 September 15, 2011 P. Jones

Private Citizen

0710 September 15, 2011 M. Maroon

Private Citizen

0711 September 14, 2011 Dr. J. Nemeth

Private Citizen

0712 September 14, 2011 S. Eckrich

Private Citizen

0713 September 14, 2011 B. Riggs

Private Citizen

0714 September 14, 2011 M. Clark

Private Citizen

0715 September 14, 2011 N. Powell

Private Citizen

0716 September 15, 2011 J. Steitz

Private Citizen

0717 September 15, 2011 M. Vanderhill

Private Citizen

0718 September 15, 2011 B. Flowers

Private Citizen

0719 September 15, 2011 E. Isaacs

Private Citizen

0720 September 15, 2011 M. Ralphe

Private Citizen

0721 September 15, 2011 J. Nichols

Private Citizen

0722 September 15, 2011 Dr. E. Valinsky

Private Citizen

0723 September 15, 2011 B. Jones

Private Citizen

0724 September 14, 2011 J. Miller

Private Citizen

0725 September 14, 2011 C. Kishinchand

Private Citizen

0726 September 14, 2011 Dr. D. Hamilton

Private Citizen

0727 September 14, 2011 M. Daniels

Private Citizen

0728 September 14, 2011 M. Wessant

Private Citizen
463

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0729 September 14, 2011 J. Hoover

Private Citizen

0730 September 14, 2011 B. Birchard

Private Citizen

0731 September 14, 2011 J. Nemeth

Private Citizen

0732 September 14, 2011 S. Eckrich

Private Citizen

0733 September 14, 2011 B. Riggs

Private Citizen

0734 September 14, 2011 M. Clark

Private Citizen

0735 September 14, 2011 N. Powell

Private Citizen

0736 September 14, 2011 I. Soloway

Private Citizen

0737 September 14, 2011 J. McMullen

Private Citizen

0738 September 14, 2011 A. Norman

Private Citizen

0739 September 14, 2011 J. Petrisek

Private Citizen

0740 September 14, 2011 V. Hays

Private Citizen

0741 September 14, 2011 C. Boyle

Private Citizen

0742 September 14, 2011 J. Martini

Private Citizen

0743 September 15, 2011 C. Wolfe

Private Citizen

0744 September 14, 2011 A. Kurland

Private Citizen

0745 September 14, 2011 S. Weikart

Private Citizen

0746 September 14, 2011 S. Weikart

Private Citizen

0747 September 14, 2011 M. Cole

Private Citizen

0748 September 14, 2011 P. Scheirer

Private Citizen

0749 September 14, 2011 E. Racoosin

Private Citizen

0750 September 14, 2011 J. A. Mungai

Private Citizen

Private Citizen
464

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0751 September 14, 2011 P. Megowan

Private Citizen

0752 September 14, 2011 Dr. J. Brauner

Private Citizen

0753 September 15, 2011 G. James

Private Citizen

0754 September 15, 2011 D. V. Goodman

Private Citizen

0755 September 15, 2011 K. Gresham

Private Citizen

0756 September 15, 2011 P. Shabazian

Private Citizen

0757 September 15, 2011 J. Glover

Private Citizen

0758 September 15, 2011 S. Sik

Private Citizen

0759 September 15, 2011 P. Daniello

Private Citizen

0760 September 15, 2011 Dr. M. Bookbinder

Private Citizen

0761 September 15, 2011 T. MacKrell

Private Citizen

0762 September 15, 2011 L. Koelle

Private Citizen

0763 September 15, 2011 Dr. G. Crouse

Private Citizen

0764 September 15, 2011 L. Sharp

Private Citizen

0765 September 15, 2011 J. Masi

Private Citizen

0766 September 15, 2011 Dr. P. A. Anasasio

Private Citizen

0767 September 15, 2011 C. Lisowski

Private Citizen

0768 September 15, 2011 B. Peiffer

Private Citizen

0769 September 15, 2011 Dr. C. S. Russell

Private Citizen

0770 September 15, 2011 V. Harding

Private Citizen

0771 September 15, 2011 A. R. Syvan

Private Citizen

0772 September 14, 2011 T. Seay

Private Citizen

0773 September 14, 2011 S. Lach

Private Citizen
465

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0774 September 14, 2011 H. Gogins

Private Citizen

0775 September 14, 2011 M. Sokol

Private Citizen

0776 September 14, 2011 P. Lambert

Private Citizen

0777 September 14, 2011 J. Fishman

Private Citizen

0778 September 14, 2011 L. Simmons

Private Citizen

0779 September 14, 2011 T. Dignazio

Private Citizen

0780 September 14, 2011 S. Sears

Private Citizen

0781 September 14, 2011 L. Trautman

Private Citizen

0782 September 14, 2011 E. Flower

Private Citizen

0783 September 14, 2011 A. Mudd

Private Citizen

0784 September 14, 2011 P. Battisti

Private Citizen

0785 September 14, 2011 A. Cohen

Private Citizen

0786 September 14, 2011 T. McHugh

Private Citizen

0787 September 14, 2011 L. Lawrence

Private Citizen

0788 September 14, 2011 L. Greco

Private Citizen

0789 September 14, 2011 Dr. K. Cross

Private Citizen

0790 September 14, 2011 E. Barlow

Private Citizen

0791 September 14, 2011 Dr. B. Prairie

Private Citizen

0792 September 14, 2011 E. Binder

Private Citizen

0793 September 14, 2011 R. Lernberg

Private Citizen

0794 September 14, 2011 M. Welke

Private Citizen

0795 September 14, 2011 P. and P. French

Private Citizens

0796 September 14, 2011 K. Wicce

Private Citizen
466

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0797 September 14, 2011 D. Read

Private Citizen

0798 September 14, 2011 D. Morse

Private Citizen

0799 September 14, 2011 J. Dresser

Private Citizen

0800 September 14, 2011 M. Genin

Private Citizen

0801 September 14, 2011 T. Crawford

Private Citizen

0802 September 14, 2011 M. Hadcock

Private Citizen

0803 September 14, 2011 D. A. Pedtke, Sr.

Private Citizen

0804 September 14, 2011 M. A. Lajoie-Sandroff

Private Citizen

0805 September 15, 2011 S. Barbier

Private Citizen

0806 September 14, 2011 S. Robeson

Private Citizen

0807 September 14, 2011 J. Cunningham

Private Citizen

0808 September 14, 2011 J. Conrardy

Private Citizen

0809 September 14, 2011 S. Tomkiel

Private Citizen

0810 September 14, 2011 T. Kauffman

Private Citizen

0811 September 14, 2011 M. Cleaves

Private Citizen

0812 September 14, 2011 E. Carlson

Private Citizen

0813 September 15, 2011 V. Cardellini

Private Citizen

0814 September 15, 2011 A. Ulrich

Private Citizen

0815 September 15, 2011 B. Flowers

Private Citizen

0816 September 15, 2011 M. Ralphe

Private Citizen

0817 September 15, 2011 Dr. E. Valinsky

Private Citizen

0818 September 15, 2011 G. Sengstake

Private Citizen

0819 September 15, 2011 C. E. Krause

Private Citizen
467

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0820 September 15, 2011 J. DiSalle

Private Citizen

0821 September 15, 2011 J. Hohl

Private Citizen

0822 September 15, 2011 V. Murti

Private Citizen

0823 September 15, 2011 J. and W. MacDonald

Private Citizens

0824 September 15, 2011 S. Alex

Private Citizen

0825 September 15, 2011 Dr. C. Leman

Private Citizen

0826 September 15, 2011 Dr. W. Davis

Private Citizen

0827 September 15, 2011 W. Montgomery

Private Citizen

0828 September 15, 2011 M. Warren

Private Citizen

0829 September 15, 2011 E. Vaughn

Private Citizen

0830 September 15, 2011 C. Schmalz

Private Citizen

0831 September 15, 2011 J. Cummings

Private Citizen

0832 September 15, 2011 Dr. T. Pretlow

Private Citizen

0833 September 15, 2011 Dr. C. and P. Lechner

Private Citizens

0834 September 15, 2011 Dr. J. Tullis

Private Citizen

0835 September 15, 2011 R. Desalle

Private Citizen

0836 September 15, 2011 C. Schaaf

Private Citizen

0837 September 15, 2011 Dr. R. Segal

Private Citizen

0838 September 15, 2011 W. Wellman

Private Citizen

0839 September 15, 2011 S. Hathaway

Private Citizen

0840 September 15, 2011 P. Schultze

Private Citizen

0841 September 15, 2011 J. Kreiss

Private Citizen

0842 September 15, 2011 Dr. R. Tanner

Private Citizen
468

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0843 September 15, 2011 R. Robitaille

Private Citizen

0844 September 15, 2011 N. Van Dyke

Private Citizen

0845 September 15, 2011 B. and H.R. Malpass

Private Citizens

0846 September 15, 2011 D. Potter

Private Citizen

0847 September 15, 2011 D. Stanko

Private Citizen

0848 September 15, 2011 E. Luisada

Private Citizen

0849 September 15, 2011 J. Lewandowski

Private Citizen

0850 September 15, 2011 K. Shaw

Private Citizen

0851 September 15, 2011 C. O. Dietrich

Private Citizen

0852 September 14, 2011 A. Hernandez

Private Citizen

0853 September 14, 2011 M. Pavlovich

Private Citizen

0854 September 14, 2011 A. Hernandez

Private Citizen

0855 September 14, 2011 Dr. E. Hulsey

Private Citizen

0856 September 15, 2011 B. Jones

Private Citizen

0857 September 15, 2011 L. Abbe

Private Citizen

0858 September 15, 2011 R. Grimm

Private Citizen

0859 September 15, 2011 Dr. D. Harrison

Private Citizen

0860 September 15, 2011 P. Hanson

Private Citizen

0861 September 15, 2011 K. Eysenbach

Private Citizen

0862 September 15, 2011 L. Stock

Private Citizen

0863 September 15, 2011 P. Dritt

Private Citizen

0864 September 15, 2011 C. Bechtle

Private Citizen

0865 September 15, 2011 J. Maryanski

Private Citizen
469

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0866 September 15, 2011 V. Garcia

Private Citizen

0867 September 15, 2011 J. Vardzel

Private Citizen

0868 September 15, 2011 E. Mayer

Private Citizen

0869 September 15, 2011 A. Hasz

Private Citizen

0870 September 15, 2011 S. Blair

Private Citizen

0871 September 15, 2011 C. Nelson

Private Citizen

0872 September 15, 2011 R. Duncan

Private Citizen

0873 September 15, 2011 C. Woodcock

Private Citizen

0874 September 15, 2011 S. Babbitt

Private Citizen

0875 September 15, 2011 M. D. Williamson

Private Citizen

0876 September 15, 2011 A. Leonard

Private Citizen

0877 September 15, 2011 R. Davey

Private Citizen

0878 September 15, 2011 M. Flanagan

Private Citizen

0879 September 15, 2011 P. Howard

Private Citizen

0880 September 15, 2011 H. Curtler III

Private Citizen

0881 September 14, 2011 I. Soloway

Private Citizen

0882 September 15, 2011 P. Cohen

Private Citizen

0883 September 15, 2011 D. Selvaggio

Private Citizen

0884 September 15, 2011 K. Jones

Private Citizen

0885 September 15, 2011 B. M. Bean

Private Citizen

0886 September 15, 2011 J. Schuchert

Private Citizen

0887 September 15, 2011 Dr. L. Eiseman

Private Citizen

0888 September 15, 2011 A. Nuse

Private Citizen
470

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0889 September 15, 2011 M. Wellington

Private Citizen

0890 September 15, 2011 J. Corrigan

Private Citizen

0891 September 15, 2011 L. Bagley

Private Citizen

0892 September 15, 2011 Dr. J. Leith

Private Citizen

0893 September 15, 2011 K. Shair

Private Citizen

0894 September 15, 2011 V. Mosca-Clark

Private Citizen

0895 September 15, 2011 K. Rousseau

Private Citizen

0896 September 15, 2011 E. Kudlesky II

Private Citizen

0897 September 15, 2011 F. Merker

Private Citizen

0898 September 15, 2011 J. Dorwart

Private Citizen

0899 September 15, 2011 M. Nelson

Private Citizen

0900 September 15, 2011 T. D'Angelo

Private Citizen

0901 September 15, 2011 S. Legler

Private Citizen

0902 September 15, 2011 Dr. L. Thompson

Private Citizen

0903 September 15, 2011 A. Badami

Private Citizen

0904 September 15, 2011 J. Sheridan

Private Citizen

0905 September 15, 2011 S. Shoss

Private Citizen

0906 September 16, 2011 Dr. L. Bazan

Private Citizen

0907 September 15, 2011 J. Hodie

Private Citizen

0908 September 16, 2011 J. Falcon

Private Citizen

0909 September 16, 2011 J. Charvat

Private Citizen

0910 September 16, 2011 A. Grove

Private Citizen

0911 September 16, 2011 D. G. Neel

Private Citizen
471

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0912 September 16, 2011 T. Dukes

Private Citizen

0913 September 15, 2011 T. Cannon

Private Citizen

0914 September 15, 2011 R. Platt

Private Citizen

0915 September 16, 2011 C. Lane

Private Citizen

0916 September 16, 2011 H. Aikens

Private Citizen

0917 September 16, 2011 A. Reczek

Private Citizen

0918 September 15, 2011 L. Elkind

Private Citizen

0919 September 15, 2011 L. Lambeth

Private Citizen

0920 September 15, 2011 O. Tegland

Private Citizen

0921 September 15, 2011 G. Hinde

Private Citizen

0922 September 15, 2011 D. Burg

Private Citizen

0923 September 16, 2011 B. Brigham

Private Citizen

0924 September 16, 2011 H. A. Aho

Private Citizen

0925 September 16, 2011 P. B. Furnas

Private Citizen

0926 September 15, 2011 Dr. K. Allen

Private Citizen

0927 September 15, 2011 D. Tobin

Private Citizen

0928 September 15, 2011 T. Imajo

Private Citizen

0929 September 15, 2011 A. Behrman

Private Citizen

0930 September 15, 2011 L. Fraser

Private Citizen

0931 September 15, 2011 T. Matlin

Private Citizen

0932 September 15, 2011 J. Capozzelli

Private Citizen

0933 September 15, 2011 P. Conley

Private Citizen

0934 September 15, 2011 F. Sordelet

Private Citizen
472

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0935 September 15, 2011 B. Kantola

Private Citizen

0936 September 15, 2011 M. Moderacki

Private Citizen

0937 September 15, 2011 J. Ertelt

Private Citizen

0938 September 16, 2011 H. Miller

Private Citizen

0939 September 16, 2011 K. White

Private Citizen

0940 September 16, 2011 S. Staggenborg

Private Citizen

0941 September 16, 2011 A. Bender

Private Citizen

0942 September 15, 2011 M. Hood

Private Citizen

0943 September 15, 2011 P. Howes

Private Citizen

0944 September 15, 2011 A. Brennan

Private Citizen

0945 September 15, 2011 L. Fraser

Private Citizen

0946 September 15, 2011 H. Berkowitz

Private Citizen

0947 September 15, 2011 P. La Point

Private Citizen

0948 September 15, 2011 E. White

Private Citizen

0949 September 15, 2011 D. Shiring

Private Citizen

0950 September 15, 2011 L. Stevens

Private Citizen

0951 September 15, 2011 M. Laws

Private Citizen

0952 September 15, 2011 C. McPeak

Private Citizen

0953 September 15, 2011 C. Cross

Private Citizen

0954 September 15, 2011 S. Norman-Jones

Private Citizen

0955 September 16, 2011 Mass Comment Campaign sponsoring organization 

unknown (483)

0956 September 15, 2011 J. Gutacker

Private Citizen

0957 September 15, 2011 A. Shaner

Private Citizen
473

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0958 September 15, 2011 P. Karie

Private Citizen

0959 September 15, 2011 P. Keating-Butler

Private Citizen

0960 September 16, 2011 M. Fitzgerald

Private Citizen

0961 September 15, 2011 S. Spacel

Private Citizen

0962 September 16, 2011 M. Kennedy

Private Citizen

0963 September 16, 2011 S. Moss

Private Citizen

0964 September 15, 2011 K. Newton

Private Citizen

0965 September 15, 2011 P. Leven

Private Citizen

0966 September 14, 2011 R. Moore

Private Citizen

0967 September 14, 2011 A. Lowe

Private Citizen

0968 September 15, 2011 D. Matsis

Private Citizen

0969 September 15, 2011 P. Clark

Private Citizen

0970 September 14, 2011 R. Sheresh

Private Citizen

0971 September 14, 2011 A. Phillipson

Private Citizen

0972 September 14, 2011 B. Bennett

Private Citizen

0973 September 15, 2011 N. Vanderborgh

Private Citizen

0974 September 15, 2011 B. Backman

Private Citizen

0975 September 15, 2011 M. McGlashan

Private Citizen

0976 September 15, 2011 M. Elder

Private Citizen

0977 September 15, 2011 D. Pino

Private Citizen

0978 September 15, 2011 Jim Littlefield

Surfers' Environmental Alliance

0979 September 15, 2011 J. Steitz

Private Citizen

0980 September 15, 2011 M. Vanderhill

Private Citizen
474

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

0981 September 15, 2011 E. Isaacs

Private Citizen

0982 September 16, 2011 L. Hill

Private Citizen

0983 September 16, 2011 Dr. I. Lillien

Private Citizen

0984 September 16, 2011 Dr. H. Gwiazda

Private Citizen

0985 September 19, 2011 Patrick J. Nugent

Texas Pipeline Association

0986 September 15, 2011 L. Jobe

Private Citizen

0987 September 15, 2011 R. Meyers

Private Citizen

0988 September 15, 2011 K. Leaman

Private Citizen

0989 September 15, 2011 J. Krow

Private Citizen

0990 September 15, 2011 G. Clark

Private Citizen

0991 September 15, 2011 S. Bensel

Private Citizen

0992 September 15, 2011 R. Vosburg

Private Citizen

0993 September 15, 2011 E. Drake

Private Citizen

0994 September 15, 2011 D. Wouters

Private Citizen

0995 September 15, 2011 A. Grundstrom

Private Citizen

0996 September 15, 2011 D. Esters

Private Citizen

0997 September 15, 2011 M. Matzek

Private Citizen

0998 September 15, 2011 J. Sorrells

Private Citizen

0999 September 15, 2011 T. Holt

Private Citizen

1000 September 15, 2011 N. N. Neau

Private Citizen

1001 September 16, 2011 R. Siegfried

Private Citizen

1002 September 16, 2011 J. Burger

Private Citizen

1003 September 16, 2011 D. Marino

Private Citizen
475

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1004 September 15, 2011 Dr A. Holloway

Private Citizen

1005 September 16, 2011 J. Donlen

Private Citizen

1006 September 15, 2011 S. Dowling

Private Citizen

1007 September 15, 2011 S. Peters

Private Citizen

1008 September 16, 2011 W. Grady

Private Citizen

1009 September 16, 2011 J. Peterson

Private Citizen

1010 September 16, 2011 C. Moore

Private Citizen

1011 September 16, 2011 A. Franklin

Private Citizen

1012 September 16, 2011 J. Elliott

Private Citizen

1013 September 16, 2011 K. Scott

Private Citizen

1014 September 16, 2011 C. Kuhinka

Private Citizen

1015 September 16, 2011 J. Chamberlin

Private Citizen

1016 September 17, 2011 E. Talbot

Private Citizen

1017 September 17, 2011 M. Strawn

Private Citizen

1018 September 17, 2011 S. Weinberg

Private Citizen

1019 September 17, 2011 M. Hosey

Private Citizen

1020 September 17, 2011 M. Haines

Private Citizen

1021 September 17, 2011 M. Pickens

Private Citizen

1022 September 17, 2011 F. Schilling

Private Citizen

1023 September 17, 2011 T. Rieve

Private Citizen

1024 September 17, 2011 M. Bitz

Private Citizen

1025 September 17, 2011 J. Boone

Private Citizen

1026 September 17, 2011 D. Green

Private Citizen
476

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1027 September 17, 2011 T. Hazelleaf

Private Citizen

1028 September 17, 2011 P. and M. Leven

Private Citizens

1029 September 17, 2011 C. Ring

Private Citizen

1030 September 17, 2011 C. Teodori

Private Citizen

1031 September 17, 2011 M. Waltman

Private Citizen

1032 September 17, 2011 T. Curran

Private Citizen

1033 September 17, 2011 N. Nicol

Private Citizen

1034 September 17, 2011 H. Bitaxis

Private Citizen

1035 September 18, 2011 J. Teuschl

Private Citizen

1036 September 18, 2011 C. Coyne

Private Citizen

1037 September 18, 2011 E. Williams

Private Citizen

1038 September 18, 2011 L. Grossberg

Private Citizen

1039 September 18, 2011 P. Wenner

Private Citizen

1040 September 18, 2011 L. Zdrofcoff

Private Citizen

1041 September 18, 2011 B. Trinkley

Private Citizen

1042 September 18, 2011 J. Pentzien

Private Citizen

1043 September 18, 2011 J. Foster

Private Citizen

1044 September 19, 2011 G. Anderson

Private Citizen

1045 September 19, 2011 K. Lund

Private Citizen

1046 September 19, 2011 M. Polansky

Private Citizen

1047 September 19, 2011 J. Cutler

Private Citizen

1048 September 19, 2011 J. Lyles

Private Citizen

1049 September 19, 2011 E. Hulsey

Private Citizen
477

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1050 September 20, 2011 E. Mac Ken

Private Citizen

1051 September 19, 2011 S. Anderson

Private Citizen

1052 September 19, 2011 J. Bridy

Private Citizen

1053 September 19, 2011 L. Penrose

Private Citizen

1054 September 19, 2011 R. Sdano

Private Citizen

1055 September 19, 2011 F. Krohn

Private Citizen

1056 September 19, 2011 R. Haworth

Private Citizen

1057 September 19, 2011 R. van West

Private Citizen

1058 September 20, 2011 B. Roon

Private Citizen

1059 September 20, 2011 T. Seto

Private Citizen

1060 September 20, 2011 K. Scott

Private Citizen

1061 September 20, 2011 D. Hunting

Private Citizen

1062 September 20, 2011 L. Foster

Private Citizen

1063 September 20, 2011 R. Bennett

Private Citizen

1064 September 20, 2011 Ms. Truschel

Private Citizen

1065 September 20, 2011 A. Weidman

Private Citizen

1066 September 20, 2011 S. Zlotnick

Private Citizen

1067 September 20, 2011 T. Paul

Private Citizen

1068 September 20, 2011 Anonymous Public Comment

1069 September 22, 2011 Buffalo Creek Watershed Association

1070 September 21, 2011 P. Matejcek

Private Citizen

1071 September 21, 2011 M. Mitsch

Private Citizen

1072 September 21, 2011 R. Desalle

Private Citizen

1073 September 21, 2011 L. Lambeth

Private Citizen
478

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1074 September 21, 2011 S. Ibarra

Private Citizen

1075 September 21, 2011 L. Mershon

Private Citizen

1076 September 21, 2011 S. Schmidt

Private Citizen

1077 September 21, 2011 K. Burroughs

Private Citizen

1078 September 21, 2011 H. Makar

Private Citizen

1079 September 20, 2011 C. Duclos

Private Citizen

1080 September 20, 2011 J. Kurpaska

Private Citizen

1081 September 20, 2011 R. and J. Ferry

Private Citizens

1082 September 20, 2011 R. Yttri

Private Citizen

1083 September 20, 2011 W. Bernard

Private Citizen

1084 September 20, 2011 E. Leone

Private Citizen

1085 September 21, 2011 A. Brewer

Private Citizen

1086 September 20, 2011 S. Davis

Private Citizen

1087 September 21, 2011 M. Pellegrini

Private Citizen

1088 September 21, 2011 K. Linn

Private Citizen

1089 September 21, 2011 A. Adams

Private Citizen

1090 September 16, 2011 Kate Willams

Alaska Oil and Gas Association

1091 September 21, 2011 G. Crouse

Private Citizen

1092 September 21, 2011 L. Berd

Private Citizen

1093 September 21, 2011 C. Fremaux

Private Citizen

1094 September 21, 2011 M. Szydlowski

Private Citizen

1095 September 21, 2011 C. Guthrie

Private Citizen

1096 September 21, 2011 W. Adams

Private Citizen
479

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1097 September 21, 2011 M. Farrell

Private Citizen

1098 September 21, 2011 K. Petri

Private Citizen

1099 September 22, 2011 C. Keys

Private Citizen

1100 September 21, 2011 O. Lim

Private Citizen

1101 September 22, 2011 T. Wine

Private Citizen

1102 September 22, 2011 D. Johnson

Private Citizen

1103 September 22, 2011 G. Bannon

Private Citizen

1104 September 22, 2011 R. Decker

Private Citizen

1105 September 23, 2011 Benita Phillips RN BSN

Western Colorado Congress

Mesa County

1106 September 22, 2011 A. Pastore

Private Citizen

1107 September 22, 2011 J. Glick

Private Citizen

1108 September 22, 2011 D. Held

Private Citizen

1109 September 22, 2011 C. Sanders

Private Citizen

1110 September 23, 2011 A. Feulner

Private Citizen

1111 September 23, 2011 D. Thornton

Private Citizen

1112 September 23, 2011 R. Sanderson

Private Citizen

1113 September 23, 2011 M. Katzenbach

Private Citizen

1114 September 23, 2011 R. Nielsen

Private Citizen

1115 September 23, 2011 L. Hayhurst

Private Citizen

1116 September 23, 2011 J. Medina

Private Citizen

1117 September 23, 2011 B. Dengler-Germain

Private Citizen

1118 September 23, 2011 C. Corbelli

Private Citizen
480

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1119 September 23, 2011 G. Tiver

Private Citizen

1120 September 23, 2011 T. La Point

Private Citizen

1121 September 23, 2011 M. Ditmyer

Private Citizen

1122 September 23, 2011 R. Van Aken

Private Citizen

1123 September 23, 2011 M. Havey

Private Citizen

1124 September 23, 2011 L. Hanratty

Private Citizen

1125 September 23, 2011 S. Mccoy-Collinger

Private Citizen

1126 September 23, 2011 D. Burnham

Private Citizen

1127 September 23, 2011 K. Bates

Private Citizen

1128 September 23, 2011 M. Reser

Private Citizen

1129 September 24, 2011 A. Harville

Private Citizen

1130 September 24, 2011 D. Greene

Private Citizen

1131 September 24, 2011 J. Ehrlich

Private Citizen

1132 September 24, 2011 J. Wolfenden

Private Citizen

1133 September 24, 2011 K. Rowlett

Private Citizen

1134 September 25, 2011 I. Casillas

Private Citizen

1135 September 25, 2011 A. Lillstrom

Private Citizen

1136 September 25, 2011 A. Bellacosa

Private Citizen

1137 September 25, 2011 M. Pezzati

Private Citizen

1138 September 25, 2011 T. Henize

Private Citizen

1139 September 25, 2011 C. Fremaux

Private Citizen

1140 September 26, 2011 M. Golembeski

Private Citizen

1141 September 25, 2011 D. Armani

Private Citizen
481

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1142 September 25, 2011 M. Sarratt

Private Citizen

1143 September 25, 2011 T. Giesy

Private Citizen

1144 September 25, 2011 V. Nguyen

Private Citizen

1145 September 25, 2011 C. Buchanan

Private Citizen

1146 September 26, 2011 D. Dreyer-Ross

Private Citizen

1147 September 25, 2011 S. Intilli

Private Citizen

1148 September 25, 2011 E. Kirby

Private Citizen

1149 September 25, 2011 W. Scott

Private Citizen

1150 September 25, 2011 J. Schultz

Private Citizen

1151 September 25, 2011 M. Harmon

Private Citizen

1152 September 25, 2011 T. Carlson

Private Citizen

1153 September 25, 2011 C. Iberg

Private Citizen

1154 September 25, 2011 J. Duffin

Private Citizen

1155 September 25, 2011 E. Perchonock

Private Citizen

1156 September 25, 2011 S. Badawy

Private Citizen

1157 September 27, 2011 Anonymous public comment

1158 September 25, 2011 M. Carter

Private Citizen

1159 September 25, 2011 L. Carroll

Private Citizen

1160 September 25, 2011 S. Gruenler

Private Citizen

1161 September 25, 2011 P. Kugler

Private Citizen

1162 September 25, 2011 D. Goubert

Private Citizen

1163 September 25, 2011 K. Alyanakian

Private Citizen

1164 September 25, 2011 E. McRae

Private Citizen
482

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1165 September 25, 2011 F. O'Brien

Private Citizen

1166 September 25, 2011 A. McNeil

Private Citizen

1167 September 25, 2011 T. Foster

Private Citizen

1168 September 25, 2011 D. Brooks

Private Citizen

1169 September 25, 2011 K. Armor

Private Citizen

1170 September 25, 2011 T. Zangrilli

Private Citizen

1171 September 25, 2011 G. Kovacovsky

Private Citizen

1172 September 25, 2011 B. Blakney

Private Citizen

1173 September 25, 2011 E. Craig

Private Citizen

1174 September 25, 2011 L. Jaffee

Private Citizen

1175 September 25, 2011 J. Crowther

Private Citizen

1176 September 25, 2011 K. Vanco

Private Citizen

1177 September 25, 2011 B. Dillenbeck

Private Citizen

1178 September 25, 2011 T. Shawe

Private Citizen

1179 September 26, 2011 C. Sayre

Private Citizen

1180 September 26, 2011 C. Mariani

Private Citizen

1181 September 27, 2011 M. Mirabello

Private Citizen

1182 September 27, 2011 S. Daman

Private Citizen

1183 September 27, 2011 S. Johnson

Private Citizen

1184 September 27, 2011 M. Rawley

Private Citizen

1185 September 27, 2011 Y. Stinson

Private Citizen

1186 September 28, 2011 Anonymous public comment

1187 September 28, 2011 Anthony J. Giuliani, Vorys, Sater, Seymour and 

Pease LLP

Ohio Oil and Gas Association
483

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1188 September 27, 2011 C. Summerhill

Private Citizen

1189 September 27, 2011 M. Boyd

Private Citizen

1190 September 26, 2011 J. Adams

Private Citizen

1191 September 26, 2011 P. Johnson

Private Citizen

1192 September 26, 2011 D. Wimberly

Private Citizen

1193 September 26, 2011 D. Van Der Tak

Private Citizen

1194 September 26, 2011 G. Baughan

Private Citizen

1195 September 26, 2011 C. Bish

Private Citizen

1196 September 26, 2011 J. Powers

Private Citizen

1197 September 26, 2011 A. Jackman

Private Citizen

1198 September 26, 2011 R. Himmer

Private Citizen

1199 September 26, 2011 K. Frey

Private Citizen

1200 September 26, 2011 D. Buccilli

Private Citizen

1201 September 26, 2011 K. Maclaren

Private Citizen

1202 September 27, 2011 W. Carr

Private Citizen

1203 September 26, 2011 A. McHale

Private Citizen

1204 September 26, 2011 J. Thompson

Private Citizen

1205 September 26, 2011 L. Witzke-Baum

Private Citizen

1206 September 26, 2011 S. Brownrigg

Private Citizen

1207 September 26, 2011 L. Lawton

Private Citizen

1208 September 23, 2011 Environmental Defense Fund 

mass comment campaign (41,454)

1209 September 26, 2011 D. Kisor

Private Citizen

1210 September 26, 2011 R. Fletcher

Private Citizen
484

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1211 September 26, 2011 M. Givler

Private Citizen

1212 September 26, 2011 P. MacDonald

Private Citizen

1213 September 26, 2011 A. Seethaler

Private Citizen

1214 September 26, 2011 S. Edinger

Private Citizen

1215 September 26, 2011 J. Lappin

Private Citizen

1216 September 26, 2011 D. and S. Katz

Private Citizen

1217 September 26, 2011 M. Hunt

Private Citizen

1218 September 26, 2011 T. and M. Dimuzio

Private Citizen

1219 September 26, 2011 R. Pearson

Private Citizen

1220 September 26, 2011 M. Noonan

Private Citizen

1221 September 26, 2011 A. D'Ancona

Private Citizen

1222 September 26, 2011 B. Silbert

Private Citizen

1223 September 14, 2011 Mass Comment Campaign sponsoring organization 

unknown (14)

1224 September 26, 2011 C. Gendron

Private Citizen

1225 September 26, 2011 M. Felley

Private Citizen

1226 September 28, 2011 D. Ziskin

Private Citizen

1227 September 26, 2011 J. Erb

Private Citizen

1228 September 26, 2011 J. Moore

Private Citizen

1229 September 26, 2011 T. Husarik

Private Citizen

1230 September 26, 2011 B. Day

Private Citizen

1231 September 26, 2011 K. Painter

Private Citizen

1232 September 26, 2011 C. Cook-Huffman

Private Citizen

1233 September 26, 2011 R. Richardson

Private Citizen
485

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1234 September 26, 2011 L. Gopalan

Private Citizen

1235 September 26, 2011 R. Ellis

Private Citizen

1236 September 26, 2011 Z. Price

Private Citizen

1237 September 26, 2011 M. Feeman

Private Citizen

1238 September 26, 2011 C. Schneider

Private Citizen

1239 September 26, 2011 D. Asselin

Private Citizen

1240 September 26, 2011 B. Stankay

Private Citizen

1241 September 26, 2011 R. Hoesch

Private Citizen

1242 September 26, 2011 T. DiCampli

Private Citizen

1243 September 26, 2011 M. Kelly

Private Citizen

1244 September 26, 2011 M. Ramos

Private Citizen

1245 September 26, 2011 D. Denton

Private Citizen

1246 September 26, 2011 E. Albright

Private Citizen

1247 September 26, 2011 K. Refosco

Private Citizen

1248 September 26, 2011 B. Wise

Private Citizen

1249 September 26, 2011 S. Simpson

Private Citizen

1250 September 26, 2011 S. McKay

Private Citizen

1251 September 26, 2011 P. McBee

Private Citizen

1252 September 26, 2011 F. Shankle

Private Citizen

1253 September 26, 2011 E. Clark

Private Citizen

1254 September 26, 2011 B. Kelly

Private Citizen

1255 September 27, 2011 M. Guttman

Private Citizen

1256 September 26, 2011 P. Davies

Private Citizen
486

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1257 September 26, 2011 W. Dennis

Private Citizen

1258 September 26, 2011 E. Colonna

Private Citizen

1259 September 26, 2011 A. Hofelt

Private Citizen

1260 September 26, 2011 S. Dolan

Private Citizen

1261 September 26, 2011 S. Gibson

Private Citizen

1262 September 26, 2011 J. Evans

Private Citizen

1263 September 26, 2011 J. Butler

Private Citizen

1264 September 26, 2011 M. Hansen

Private Citizen

1265 September 26, 2011 A. Ascenzi

Private Citizen

1266 September 26, 2011 E. Shipley

Private Citizen

1267 September 26, 2011 M. Barrick

Private Citizen

1268 September 26, 2011 G. Hall

Private Citizen

1269 September 26, 2011 K. Krupsha

Private Citizen

1270 September 26, 2011 G. Massey

Private Citizen

1271 September 26, 2011 D. Larson

Private Citizen

1272 September 26, 2011 E. Aversa

Private Citizen

1273 September 26, 2011 C. Brady

Private Citizen

1274 September 26, 2011 P. Lane

Private Citizen

1275 September 26, 2011 G. Price

Private Citizen

1276 September 26, 2011 C. Myers

Private Citizen

1277 September 26, 2011 R. Hayes

Private Citizen

1278 September 26, 2011 K. Kuehlwein

Private Citizen

1279 September 26, 2011 G. Lewis

Private Citizen
487

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1280 September 26, 2011 S. Siler

Private Citizen

1281 September 26, 2011 J. Walker

Private Citizen

1282 September 26, 2011 P. Buckland

Private Citizen

1283 September 26, 2011 C. Wilson

Private Citizen

1284 September 26, 2011 S. Chew

Private Citizen

1285 September 26, 2011 N. Carlin

Private Citizen

1286 September 26, 2011 M. Paez

Private Citizen

1287 September 26, 2011 S. Willhelm

Private Citizen

1288 September 26, 2011 M. Haughey

Private Citizen

1289 September 26, 2011 L. Schade

Private Citizen

1290 September 26, 2011 D. Sibley

Private Citizen

1291 September 26, 2011 J. Mudd

Private Citizen

1292 September 28, 2011 J. Wolf

Private Citizen

1293 September 28, 2011 D. Barnes

Private Citizen

1294 September 28, 2011 M. Bertonaschi

Private Citizen

1295 September 28, 2011 N. Ternullo

Private Citizen

1296 September 29, 2011 Ken Mathews

Aeon Process Equipment and Controls

1297 September 28, 2011 L. Reed

Private Citizen

1298 September 28, 2011 N. Downing

Private Citizen

1299 September 28, 2011 M. Miller

Private Citizen

1300 September 28, 2011 J. Rubbo

Private Citizen

1301 September 28, 2011 Anonymous public comment

1302 September 28, 2011 E. Lloyd

Private Citizen
488

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1303 September 27, 2011 D. Ternullo

Private Citizen

1304 September 27, 2011 M. Miller

Private Citizen

1305 September 27, 2011 P. Crownfield

Private Citizen

1306 September 27, 2011 Sandy (no surname provided)

Private Citizen

1307 September 27, 2011 M. Bandes

Private Citizen

1308 September 27, 2011 T. Kerstettert

Private Citizen

1309 September 27, 2011 N. Rapp

Private Citizen

1310 September 27, 2011 J. Sellenraad

Private Citizen

1311 September 27, 2011 G. Koehler

Private Citizen

1312 September 29, 2011 S. Brill

Private Citizen

1313 September 27, 2011 M. Marino

Private Citizen

1314 September 27, 2011 D. Malcom

Private Citizen

1315 September 27, 2011 C. Bade

Private Citizen

1316 September 27, 2011 S. Williammee

Private Citizen

1317 September 27, 2011 J. Rooney

Private Citizen

1318 September 27, 2011 S. Wojnaroski

Private Citizen

1319 September 27, 2011 N. Starr

Private Citizen

1320 September 27, 2011 T. Kaznowski

Private Citizen

1321 September 27, 2011 B. KenCairn

Private Citizen

1322 September 27, 2011 E. Beeson

Private Citizen

1323 September 27, 2011 M. Cedillos

Private Citizen

1324 September 27, 2011 E. Hogan

Private Citizen

1325 September 27, 2011 C. Lane

Private Citizen
489

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1326 September 27, 2011 G. Lewis

Private Citizen

1327 September 27, 2011 A. Baehr

Private Citizen

1328 September 27, 2011 V. Davies

Private Citizen

1329 September 28, 2011 M. Murphy

Private Citizen

1330 September 28, 2011 S. Carman

Private Citizen

1331 September 28, 2011 C. Jones

Private Citizen

1332 September 28, 2011 K. Brown

Private Citizen

1333 September 28, 2011 G. Shanks

Private Citizen

1334 September 28, 2011 Anonymous public comment

1335 September 28, 2011 P. Lauver

Private Citizen

1336 September 28, 2011 W. Heacock

Private Citizen

1337 September 29, 2011 D. Romm

Private Citizen

1338 September 29, 2011 A. Berenzy

Private Citizen

1339 September 29, 2011 C. Gisselquist

Private Citizen

1340 September 29, 2011 P. Campbell

Private Citizen

1341 September 29, 2011 Z. Warner

Private Citizen

1342 September 29, 2011 Anonymous public comment

1343 September 29, 2011 S. Besterman

Private Citizen

1344 September 29, 2011 P. Crownfield

Private Citizen

1345 September 29, 2011 T. Manaugh

Private Citizen

1346 September 29, 2011 A. Kettering

Private Citizen

1347 September 29, 2011 R. Lazarus

Private Citizen

1348 September 30, 2011 T. Hassett

Private Citizen

1349 September 30, 2011 V. Eibner

Private Citizen
490

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1350 September 29, 2011 David J. Ellenberger

National Wildlife Federation

1351 September 30, 2011 B. Weinstein

Private Citizen

1352 October 3, 2011 C. Fette

Private Citizen

1353 October 2, 2011 L. Thompson

Private Citizen

1354 October 1, 2011 J. Cooper

Private Citizen

1355 October 2, 2011 J. Stevens

Private Citizen

1356 September 30, 2011 L. De Simone

Private Citizen

1357 October 1, 2011 L. Alexander

Private Citizen

1358 September 30, 2011 C. Mears

Private Citizen

1359 October 2, 2011 K. Schrader

Private Citizen

1360 October 1, 2011 C. Heywood

Private Citizen

1361 October 2, 2011 K. Knerl

Private Citizen

1362 October 2, 2011 S. Franzheim

Private Citizen

1363 October 1, 2011 Susan Watkins and Helen Gibbins

League of Women Voters of 

West Virginia

1364 October 2, 2011 S. Franzheim

Private Citizen

1365 September 29, 2011 L. and K. Burky

Private Citizens

1366 September 29, 2011 S. Bodman

Private Citizen

1367 September 29, 2011 L. Braun

Private Citizen

1368 September 29, 2011 G. Kenville

Private Citizen

1369 September 29, 2011 J. and N. Diener

Private Citizens

1370 September 29, 2011 K. Nielsen

Private Citizen

1371 September 29, 2011 A. Bonus

Private Citizen
491

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1372 September 29, 2011 J. Huffman

Private Citizen

1373 September 29, 2011 T. Willis

Private Citizen

1374 September 29, 2011 B. Schultz

Private Citizen

1375 September 29, 2011 E. Barrall

Private Citizen

1376 September 29, 2011 D. Keister

Private Citizen

1377 September 29, 2011 J. Flicker

Private Citizen

1378 September 29, 2011 S. Graef

Private Citizen

1379 September 29, 2011 K. Warren

Private Citizen

1380 September 29, 2011 D. Ames

Private Citizen

1381 September 29, 2011 Dr. J. Brown

Private Citizen

1382 September 29, 2011 Dr. G. Byrne

Private Citizen

1383 September 29, 2011 E. M. Trawick

Private Citizen

1384 September 29, 2011 M. Woersching

Private Citizen

1385 September 29, 2011 M. McCall

Private Citizen

1386 September 29, 2011 T. Lafferty

Private Citizen

1387 September 29, 2011 A. Broskley

Private Citizen

1388 September 29, 2011 R. Ross

Private Citizen

1389 September 29, 2011 M. Smith

Private Citizen

1390 September 29, 2011 C. Hasz

Private Citizen

1391 September 29, 2011 D. Filion

Private Citizen

1392 September 29, 2011 Dr. M. Nicholson

Private Citizen

1393 September 29, 2011 P. Buckland

Private Citizen

1394 September 29, 2011 S. Kibler

Private Citizen
492

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1395 September 29, 2011 M. Heiman

Private Citizen

1396 September 29, 2011 J. Cramer

Private Citizen

1397 September 29, 2011 W. White

Private Citizen

1398 September 29, 2011 L. Godfrey

Private Citizen

1399 September 29, 2011 Dr. C. Essenburg

Private Citizen

1400 September 29, 2011 P. Smith

Private Citizen

1401 September 29, 2011 L. Hickman

Private Citizen

1402 September 29, 2011 E. Grieco

Private Citizen

1403 September 29, 2011 J. Marish

Private Citizen

1404 September 29, 2011 J. Hartigan

Private Citizen

1405 September 29, 2011 J. Mitchell

Private Citizen

1406 September 29, 2011 R. Linnenberger

Private Citizen

1407 September 29, 2011 Dr. C. Johnson

Private Citizen

1408 September 29, 2011 M. Drake

Private Citizen

1409 September 29, 2011 R. Schoenecker

Private Citizen

1410 September 29, 2011 A. Nolder

Private Citizen

1411 September 29, 2011 S. Carpenter

Private Citizen

1412 September 29, 2011 S. Saxe

Private Citizen

1413 September 29, 2011 M. Schultz

Private Citizen

1414 October 4, 2011 D. Woltkamp

Private Citizen

1415 September 29, 2011 T. Sparkman

Private Citizen

1416 September 29, 2011 C. Alsafi

Private Citizen

1417 September 29, 2011 J. Mayo

Private Citizen
493

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1418 September 29, 2011 K. Herb

Private Citizen

1419 September 29, 2011 G. Fister

Private Citizen

1420 September 29, 2011 M. Nowak

Private Citizen

1421 October 4, 2011 J. Miller

Private Citizen

1422 September 29, 2011 S. DiMarino

Private Citizen

1423 September 29, 2011 C. Daigle

Private Citizen

1424 September 29, 2011 D. Sherrick

Private Citizen

1425 September 29, 2011 J. Tiebout

Private Citizen

1426 September 29, 2011 A. Wagner

Private Citizen

1427 September 29, 2011 N. Peffer

Private Citizen

1428 September 29, 2011 J. Hablinski

Private Citizen

1429 September 29, 2011 J. Verry

Private Citizen

1430 September 29, 2011 S. Mattingly

Private Citizen

1431 September 29, 2011 A. Conley

Private Citizen

1432 September 29, 2011 H. Funk

Private Citizen

1433 September 29, 2011 J. Avouris

Private Citizen

1434 September 29, 2011 C. Carpenter

Private Citizen

1435 September 29, 2011 Z. Tseng

Private Citizen

1436 September 29, 2011 P. Perkins

Private Citizen

1437 September 29, 2011 C. Bowles

Private Citizen

1438 September 29, 2011 L. Reavely

Private Citizen

1439 September 29, 2011 L. Lagaly

Private Citizen

1440 October 4, 2011 E. Blackler

Private Citizen
494

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1441 September 29, 2011 M. Whited

Private Citizen

1442 September 29, 2011 S. Jensen

Private Citizen

1443 September 29, 2011 J. Dolan

Private Citizen

1444 October 4, 2011 J. Houser

Private Citizen

1445 September 29, 2011 C. Harper

Private Citizen

1446 September 29, 2011 A. Rodriguez

Private Citizen

1447 October 4, 2011 D. Reber

Private Citizen

1448 September 29, 2011 D. Ward

Private Citizen

1449 September 29, 2011 C. Edwards

Private Citizen

1450 September 29, 2011 L. Hartley

Private Citizen

1451 September 29, 2011 M. Infante

Private Citizen

1452 September 29, 2011 R. Burgy

Private Citizen

1453 September 29, 2011 W. Strong

Private Citizen

1454 September 29, 2011 D. Davis

Private Citizen

1455 September 29, 2011 J. Altshuler

Private Citizen

1456 September 29, 2011 N. Johnson

Private Citizen

1457 September 29, 2011 R. Reimer

Private Citizen

1458 September 7, 2011 J. & N. Diener

Private Citizens

1459 September 29, 2011 Lyndsey Ellis

Private Citizen

1460 September 25, 2011 K. Sherrod

Private Citizen

1461 September 29, 2011 G. Arcand III

Private Citizen

1462 October 4, 2011 P. Schutt

Private Citizen

1463 September 29, 2011 D. Perry

Private Citizen
495

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1464 September 29, 2011 C. Ladner

Private Citizen

1465 September 29, 2011 Dr. W. Cutts

Private Citizen

1466 September 29, 2011 C. A. Parker

Private Citizen

1467 September 29, 2011 J. Bolden

Private Citizen

1468 September 29, 2011 J. McGuire-Conlon

Private Citizen

1469 September 29, 2011 D. Perry

Private Citizen

1470 September 29, 2011 Dr. N. Fabris

Private Citizen

1471 September 29, 2011 J. Lytle

Private Citizen

1472 October 4, 2011 Dr. M. Melody

Private Citizen

1473 October 4, 2011 A. Sunshine

Private Citizen

1474 September 29, 2011 A. Edwardson

Private Citizen

1475 September 29, 2011 K. Wall

Private Citizen

1476 September 29, 2011 C. Buchanan

Private Citizen

1477 September 29, 2011 L. Weise

Private Citizen

1478 September 29, 2011 M. Brickey

Private Citizen

1479 September 29, 2011 Dr. M. A. Segal

Private Citizen

1480 September 29, 2011 V. Wilkinson

Private Citizen

1481 September 29, 2011 B. Russell

Private Citizen

1482 September 29, 2011 K. Cullins

Private Citizen

1483 September 29, 2011 D. Larsen-Mills

Private Citizen

1484 September 29, 2011 K. Outlaw

Private Citizen

1485 September 29, 2011 B. J. Lawson

Private Citizen

1486 September 29, 2011 L. Bagley

Private Citizen
496

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1487 September 29, 2011 M. and G. Buinger

Private Citizens

1488 September 29, 2011 D. M. Davino

Private Citizen

1489 September 29, 2011 V. Freyholtz

Private Citizen

1490 September 29, 2011 A. Alexander

Private Citizen

1491 September 29, 2011 L. Klakring

Private Citizen

1492 September 29, 2011 R. Sharpe

Private Citizen

1493 September 29, 2011 R. Mayer

Private Citizen

1494 September 29, 2011 D. Keller-Perry

Private Citizen

1495 September 29, 2011 A. Dybas

Private Citizen

1496 September 29, 2011 Dr. P. Cox

Private Citizen

1497 September 29, 2011 J. Sanchez

Private Citizen

1498 September 29, 2011 L. Wimberly

Private Citizen

1499 September 29, 2011 J. Brenner

Private Citizen

1500 September 29, 2011 E. Mallin

Private Citizen

1501 September 29, 2011 M. Shareef

Private Citizen

1502 September 29, 2011 L. Hill

Private Citizen

1503 September 29, 2011 J. Armstrong

Private Citizen

1504 September 29, 2011 D. Manley

Private Citizen

1505 September 29, 2011 J. D. Singer

Private Citizen

1506 September 29, 2011 F. Campbell

Private Citizen

1507 September 29, 2011 G. Desrochers

Private Citizen

1508 September 29, 2011 C. R. Hines

Private Citizen

1509 September 29, 2011 L. Harris

Private Citizen
497

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1510 September 29, 2011 M. Wentland

Private Citizen

1511 September 29, 2011 C. Waring

Private Citizen

1512 October 5, 2011 M. Hilliard

Private Citizen

1513 September 29, 2011 B. Weaver

Private Citizen

1514 October 5, 2011 T. Tuner

Private Citizen

1515 September 29, 2011 J. Albertini

Private Citizen

1516 September 29, 2011 S. Donaldson

Private Citizen

1517 September 29, 2011 M. Smith

Private Citizen

1518 September 29, 2011 L. Graham

Private Citizen

1519 September 29, 2011 C. Westbrook

Private Citizen

1520 September 29, 2011 P. Prince

Private Citizen

1521 September 29, 2011 Dr. H. Nardone

Private Citizen

1522 September 29, 2011 R. Zeisler

Private Citizen

1523 September 29, 2011 D. W. Wynne

Private Citizen

1524 September 29, 2011 J. Hennessee

Private Citizen

1525 September 29, 2011 D. Strimer

Private Citizen

1526 September 29, 2011 K. Hughes

Private Citizen

1527 October 4, 2011 Deb Thomas

Powder River Basin Resource Council

Clark Resource Council

Pavillion Area Concerned Citizens

1528 September 3, 2011 J. Oakes

Private Citizen

1529 September 29, 2011 H. Billington

Private Citizen

1530 September 29, 2011 H. Billington

Private Citizen

1531 September 29, 2011 G. Kolesar

Private Citizen
498

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1532 September 29, 2011 D. LaVerne

Private Citizen

1533 September 29, 2011 K. Lowry

Private Citizen

1534 September 29, 2011 A. Redig

Private Citizen

1535 September 29, 2011 A. Wagoner

Private Citizen

1536 September 29, 2011 W. R. Wertz

Private Citizen

1537 September 29, 2011 Dr. L. Glesne

Private Citizen

1538 September 29, 2011 P. Olson

Private Citizen

1539 September 29, 2011 G. Aernouts

Private Citizen

1540 October 5, 2011 J. Pannone

Private Citizen

1541 September 29, 2011 S. Sheldon

Private Citizen

1542 September 29, 2011 S. Raw

Private Citizen

1543 September 29, 2011 L. Rogers

Private Citizen

1544 September 29, 2011 J. Seluga

Private Citizen

1545 September 29, 2011 M. Gorr

Private Citizen

1546 September 29, 2011 R. Wittshirk

Private Citizen

1547 September 29, 2011 M. Patton

Private Citizen

1548 September 29, 2011 M. Eaton

Private Citizen

1549 September 29, 2011 J. Manos

Private Citizen

1550 September 29, 2011 T. Dubarr

Private Citizen

1551 September 29, 2011 Dr. N. Banman

Private Citizen

1552 September 29, 2011 C. Ohlson

Private Citizen

1553 September 29, 2011 D. Will

Private Citizen

1554 September 29, 2011 D. Strahl

Private Citizen
499

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1555 September 29, 2011 S. Larson

Private Citizen

1556 September 29, 2011 Dr. W. Thwaites

Private Citizen

1557 September 29, 2011 S. Raymond

Private Citizen

1558 September 29, 2011 J. Barker

Private Citizen

1559 September 29, 2011 S. Joshua

Private Citizen

1560 September 29, 2011 L. Rodriguez

Private Citizen

1561 September 29, 2011 J. Hargett

Private Citizen

1562 September 29, 2011 T. Chandler

Private Citizen

1563 September 29, 2011 M. B. Hardy

Private Citizen

1564 September 29, 2011 F. Contini

Private Citizen

1565 September 29, 2011 C. Herman-Wurmfeld

Private Citizen

1566 September 29, 2011 C. Nisinson

Private Citizen

1567 September 29, 2011 J. Geiger

Private Citizen

1568 September 29, 2011 J. Milan

Private Citizen

1569 September 29, 2011 M. Herschler

Private Citizen

1570 September 29, 2011 F. Harvey-Shea

Private Citizen

1571 September 29, 2011 D. Hodum

Private Citizen

1572 September 29, 2011 E. Renner

Private Citizen

1573 September 29, 2011 B. Whipple

Private Citizen

1574 September 29, 2011 E. Yesko

Private Citizen

1575 September 29, 2011 G. Nichols

Private Citizen

1576 September 29, 2011 M. Bradshaw

Private Citizen

1577 September 29, 2011 T. and I. O. Brown

Private Citizens
500

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1578 September 29, 2011 S. Toland

Private Citizen

1579 October 4, 2011 J. Allen

Private Citizen

1580 September 30, 2011 P. Boland

Private Citizen

1581 September 29, 2011 E. Lippincott

Private Citizen

1582 September 29, 2011 B. Wright

Private Citizen

1583 September 29, 2011 C. Brown

Private Citizen

1584 September 29, 2011 M. Rucinski

Private Citizen

1585 October 4, 2011 V. Egan

Private Citizen

1586 September 29, 2011 D. Harper

Private Citizen

1587 September 29, 2011 S. Carvey

Private Citizen

1588 October 4, 2011 R. Mann

Private Citizen

1589 October 4, 2011 L. Halsey

Private Citizen

1590 October 4, 2011 E. Wysocki

Private Citizen

1591 October 4, 2011 B. McKinney

Private Citizen

1592 October 4, 2011 L. Urban

Private Citizen

1593 October 4, 2011 L. Urban

Private Citizen

1594 October 4, 2011 K. Kristijanson-Gural

Private Citizen

1595 September 29, 2011 W. Wheelock

Private Citizen

1596 September 29, 2011 J. W. Mikus

Private Citizen

1597 September 29, 2011 S. Ling

Private Citizen

1598 October 5, 2011 K. Thomas

Private Citizen

1599 September 29, 2011 G. Giesey

Private Citizen

1600 September 29, 2011 S. Woodruu

Private Citizen
501

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1601 September 29, 2011 D. Alman

Private Citizen

1602 September 29, 2011 C. Lingeman

Private Citizen

1603 September 29, 2011 A. Githler

Private Citizen

1604 September 29, 2011 B. and M. R. Garon

Private Citizens

1605 September 29, 2011 S. Sheon

Private Citizen

1606 September 29, 2011 S. Xie

Private Citizen

1607 September 29, 2011 J. Siegle

Private Citizen

1608 September 29, 2011 D. Read

Private Citizen

1609 October 4, 2011 L. Rodd

Private Citizen

1610 September 29, 2011 A. Flaccavento

Private Citizen

1611 September 29, 2011 E. Hereford

Private Citizen

1612 September 29, 2011 A. Christensen

Private Citizen

1613 September 29, 2011 B. F. Hamilton

Private Citizen

1614 September 29, 2011 D. Deick

Private Citizen

1615 September 29, 2011 M. Wood

Private Citizen

1616 September 29, 2011 J. Coakley

Private Citizen

1617 September 29, 2011 T. Wilson

Private Citizen

1618 September 29, 2011 D. Pryor

Private Citizen

1619 September 29, 2011 L. Larkin

Private Citizen

1620 September 29, 2011 K. Kassem

Private Citizen

1621 September 29, 2011 E. Tureck

Private Citizen

1622 September 29, 2011 J. Smith

Private Citizen

1623 September 29, 2011 Dr. T. Davis

Private Citizen
502

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1624 September 29, 2011 K. Keathley

Private Citizen

1625 September 29, 2011 S. Nokes

Private Citizen

1626 September 29, 2011 J. Dowling

Private Citizen

1627 September 29, 2011 S. Tuerk

Private Citizen

1628 September 29, 2011 D. Mondejar

Private Citizen

1629 September 29, 2011 D. Holm

Private Citizen

1630 September 29, 2011 M. Blewett

Private Citizen

1631 September 29, 2011 P. A. Bollman

Private Citizen

1632 September 29, 2011 P. Hoeschele

Private Citizen

1633 September 29, 2011 L. Bowman

Private Citizen

1634 September 29, 2011 L. Filor

Private Citizen

1635 September 29, 2011 R. Eiler

Private Citizen

1636 September 29, 2011 S. Mehrotra

Private Citizen

1637 September 29, 2011 T. Conlon

Private Citizen

1638 September 29, 2011 A. Jones

Private Citizen

1639 September 29, 2011 M. Strawn

Private Citizen

1640 September 29, 2011 C. Browsher

Private Citizen

1641 September 29, 2011 G. Ripley

Private Citizen

1642 September 29, 2011 C. Kelly

Private Citizen

1643 September 29, 2011 M. Johnson

Private Citizen

1644 October 4, 2011 Barry T. Smitherman

Railroad Commission of Texas

1645 September 29, 2011 A. Mitchell

Private Citizen

1646 September 29, 2011 D. Bell

Private Citizen
503

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1647 September 29, 2011 S. Langsjoen

Private Citizen

1648 September 29, 2011 P. Brashear

Private Citizen

1649 September 29, 2011 N. Engelfried

Private Citizen

1650 September 29, 2011 M. Hertzler

Private Citizen

1651 September 28, 2011 J. Moore

Private Citizen

1652 September 29, 2011 J. W. Goodspeed

Private Citizen

1653 September 29, 2011 R. V. Cogan

Private Citizen

1654 September 29, 2011 J. Dolan

Private Citizen

1655 October 4, 2011 L. Epperson

Private Citizen

1656 September 29, 2011 B. Henzi

Private Citizen

1657 October 5, 2011 Sara Arkle

Idaho Conservation League

1658 September 29, 2011 P. Gynn

Private Citizen

1659 September 29, 2011 T. Cannon

Private Citizen

1660 September 29, 2011 R. Seger

Private Citizen

1661 September 29, 2011 D. P. Serbanic

Private Citizen

1662 September 29, 2011 J. Miner

Private Citizen

1663 September 29, 2011 S. Carroll

Private Citizen

1664 September 29, 2011 Daniel L. (surname not provided)

Private Citizen

1665 September 29, 2011 J. Vincent

Private Citizen

1666 September 29, 2011 R. Grace

Private Citizen

1667 September 29, 2011 M. Smith

Private Citizen

1668 September 29, 2011 S. & W. Bartovics

Private Citizen

1669 September 29, 2011 T. Rieve

Private Citizen
504

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1670 September 29, 2011 I. Mason

Private Citizen

1671 September 29, 2011 M. A. Wild

Private Citizen

1672 September 29, 2011 Dr. D. Shaw

Private Citizen

1673 September 29, 2011 M. Sosebee

Private Citizen

1674 October 4, 2011 A. Weaver

Private Citizen

1675 September 29, 2011 J. Wiener

Private Citizen

1676 September 29, 2011 W. Suydam

Private Citizen

1677 September 29, 2011 D. Gaubatz

Private Citizen

1678 September 29, 2011 S. Peacock

Private Citizen

1679 October 4, 2011 Dr. N. Shiffler

Private Citizen

1680 October 4, 2011 R. Breen

Private Citizen

1681 September 29, 2011 R. Smith

Private Citizen

1682 September 29, 2011 C. Warren

Private Citizen

1683 September 29, 2011 J. Meyer

Private Citizen

1684 September 29, 2011 Dr. E. Beshero-Bondar

Private Citizen

1685 September 29, 2011 B. Knoth

Private Citizen

1686 September 29, 2011 J. Knapp

Private Citizen

1687 September 29, 2011 R. Ford

Private Citizen

1688 September 29, 2011 J. Mellow

Private Citizen

1689 September 29, 2011 S. Boniface

Private Citizen

1690 September 29, 2011 S. Sanders

Private Citizen

1691 September 29, 2011 K. Hanson

Private Citizen

1692 September 29, 2011 S. Murren-Azad

Private Citizen
505

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1693 September 29, 2011 D. Ochoa

Private Citizen

1694 September 29, 2011 E. Webster

Private Citizen

1695 September 29, 2011 Dr. P. Picardi

Private Citizen

1696 September 29, 2011 Dr. N. Verber

Private Citizen

1697 September 29, 2011 J. Stone

Private Citizen

1698 September 29, 2011 R. Bradley

Private Citizen

1699 September 29, 2011 V. Amare

Private Citizen

1700 September 29, 2011 F. Welty

Private Citizen

1701 September 29, 2011 J. Feldman

Private Citizen

1702 September 29, 2011 A. R. Johnson

Private Citizen

1703 September 29, 2011 B. Williams

Private Citizen

1704 September 29, 2011 G. Andrews

Private Citizen

1705 September 29, 2011 L. Eatenson

Private Citizen

1706 September 29, 2011 Dr. H. and V. Peace

Private Citizens

1707 September 29, 2011 N. Breckenridge

Private Citizen

1708 September 29, 2011 S. Michael

Private Citizen

1709 September 29, 2011 E. Huffmans

Private Citizen

1710 September 29, 2011 T. Alvey

Private Citizen

1711 September 29, 2011 M. Patton

Private Citizen

1712 September 29, 2011 R. Hepler III

Private Citizen

1713 September 29, 2011 M. McKennon

Private Citizen

1714 September 29, 2011 P. Roden

Private Citizen

1715 September 29, 2011 F. Gros

Private Citizen
506

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1716 September 29, 2011 F. Krohn

Private Citizen

1717 September 29, 2011 J. Wendl

Private Citizen

1718 September 29, 2011 J. Gollatz

Private Citizen

1719 September 29, 2011 R. Jenkinson

Private Citizen

1720 September 29, 2011 K. Crane

Private Citizen

1721 September 29, 2011 R. & B. Stippec

Private Citizen

1722 September 29, 2011 D. Lockspeiser

Private Citizen

1723 September 29, 2011 H. McCausland

Private Citizen

1724 September 29, 2011 L. Scordilis

Private Citizen

1725 September 29, 2011 Sierra Club mass comment campaign (1,981)

1726 September 29, 2011 C. Conlon

Private Citizen

1727 September 29, 2011 N. M. Shaughnessy

Private Citizen

1728 September 29, 2011 M. Marino

Private Citizen

1729 September 29, 2011 M. S. Dennis

Private Citizen

1730 September 29, 2011 L. Reed

Private Citizen

1731 September 29, 2011 K. Popovich

Private Citizen

1732 September 29, 2011 G. Betts

Private Citizen

1733 September 29, 2011 D. Goodwin

Private Citizen

1734 September 29, 2011 C. Beitel

Private Citizen

1735 September 29, 2011 S. McDonnell

Private Citizen

1736 September 29, 2011 J. Sapunarich

Private Citizen

1737 September 29, 2011 J. Pearson

Private Citizen

1738 September 29, 2011 Dr. R. Braslau

Private Citizen
507

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1739 September 29, 2011 Dr. J. Howland

Private Citizen

1740 September 29, 2011 J. Roelof

Private Citizen

1741 September 29, 2011 D. Good

Private Citizen

1742 September 29, 2011 M. Kolar

Private Citizen

1743 September 29, 2011 A. Lannon

Private Citizen

1744 September 29, 2011 M. E. Teeter

Private Citizen

1745 September 29, 2011 J. Bloom

Private Citizen

1746 September 29, 2011 R. Woiler

Private Citizen

1747 September 29, 2011 R. Novkow

Private Citizen

1748 September 29, 2011 R. Lem

Private Citizen

1749 September 29, 2011 N. Nettles

Private Citizen

1750 September 29, 2011 S. Sanders

Private Citizen

1751 September 29, 2011 K. I. Henry

Private Citizen

1752 September 29, 2011 Dr. J. Nicholson

Private Citizen

1753 September 29, 2011 J. Countryman

Private Citizen

1754 September 29, 2011 Dr. J. Arrowsmith

Private Citizen

1755 September 29, 2011 B. League

Private Citizen

1756 September 29, 2011 D. Barbee

Private Citizen

1757 September 29, 2011 E. McCollum

Private Citizen

1758 September 29, 2011 V. Gibbens

Private Citizen

1759 September 29, 2011 Lynn (no surname provided)

Private Citizen

1760 September 29, 2011 C. Bush

Private Citizen

1761 September 29, 2011 J. Wallace

Private Citizen
508

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1762 September 29, 2011 B. Ikler

Private Citizen

1763 September 29, 2011 R. Schell

Private Citizen

1764 September 29, 2011 J. McDade

Private Citizen

1765 September 29, 2011 M. King

Private Citizen

1766 September 29, 2011 Dr. R. Genovese

Private Citizen

1767 September 29, 2011 J. Birdsong

Private Citizen

1768 September 29, 2011 C. Steohens

Private Citizen

1769 September 29, 2011 J. Scalone

Private Citizen

1770 September 29, 2011 A. Saldana

Private Citizen

1771 September 29, 2011 M. S. Kalb

Private Citizen

1772 September 29, 2011 D. Shugar

Private Citizen

1773 September 29, 2011 Dr. B. Howard-Pitney

Private Citizen

1774 September 29, 2011 E. Coffman

Private Citizen

1775 September 29, 2011 S. James

Private Citizen

1776 September 29, 2011 R. Schmetzer

Private Citizen

1777 September 29, 2011 E. Usadi

Private Citizen

1778 September 29, 2011 H. and G. Rockwood III

Private Citizens

1779 September 29, 2011 B. Dunn

Private Citizen

1780 September 29, 2011 J. Beckman

Private Citizen

1781 September 29, 2011 L. Donati

Private Citizen

1782 September 29, 2011 J. Magnarella

Private Citizen

1783 September 29, 2011 H. Kahn

Private Citizen

1784 September 29, 2011 J. Thurman

Private Citizen
509

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1785 September 29, 2011 J. Caldwell

Private Citizen

1786 September 29, 2011 F. Gilmore

Private Citizen

1787 September 29, 2011 Dr. L. Vardy

Private Citizen

1788 September 29, 2011 D. and C. Shelton

Private Citizens

1789 September 29, 2011 F. Dula

Private Citizen

1790 September 29, 2011 M. Eberhart

Private Citizen

1791 September 29, 2011 S. Nevius

Private Citizen

1792 September 29, 2011 L. Sanders

Private Citizen

1793 September 29, 2011 A. Pratt

Private Citizen

1794 September 29, 2011 Dr. M. Atherton

Private Citizen

1795 September 29, 2011 S. Blair

Private Citizen

1796 September 29, 2011 L. Reis

Private Citizen

1797 September 29, 2011 P. Matejcek

Private Citizen

1798 September 29, 2011 L. Chandler

Private Citizen

1799 September 29, 2011 M. Griego

Private Citizen

1800 September 29, 2011 B. Bennett

Private Citizen

1801 September 29, 2011 J. Howe

Private Citizen

1802 September 29, 2011 A. Hansen

Private Citizen

1803 September 29, 2011 H. Leertouwer

Private Citizen

1804 September 29, 2011 G. Tice

Private Citizen

1805 September 29, 2011 N. Thompson

Private Citizen

1806 September 29, 2011 N. Terry

Private Citizen

1807 September 29, 2011 Dr. S. Cochran

Private Citizen
510

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1808 September 29, 2011 K. Fletcher

Private Citizen

1809 September 29, 2011 J. Jaeger

Private Citizen

1810 September 29, 2011 K. Cooper

Private Citizen

1811 September 29, 2011 A. Holstein

Private Citizen

1812 September 29, 2011 T. Seto

Private Citizen

1813 September 29, 2011 T. Merrill

Private Citizen

1814 September 29, 2011 R. Greiner

Private Citizen

1815 September 29, 2011 B. Strasko

Private Citizen

1816 September 29, 2011 K. Loomis

Private Citizen

1817 September 29, 2011 R. Robitaille

Private Citizen

1818 September 29, 2011 E. Balogh

Private Citizen

1819 September 29, 2011 S. Evans

Private Citizen

1820 September 29, 2011 J. Steele

Private Citizen

1821 September 29, 2011 J. Clark

Private Citizen

1822 September 29, 2011 N. Kurtz

Private Citizen

1823 September 29, 2011 M. Cunningham

Private Citizen

1824 September 29, 2011 H. Thomas

Private Citizen

1825 September 29, 2011 A. Shapiro

Private Citizen

1826 September 29, 2011 R. Ysasi

Private Citizen

1827 September 29, 2011 Dr. J. Brown

Private Citizen

1828 September 29, 2011 S. Young

Private Citizen

1829 September 29, 2011 S. Rubenstein

Private Citizen

1830 September 29, 2011 M. Maroon

Private Citizen
511

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1831 September 29, 2011 L. Flaccavento

Private Citizen

1832 September 29, 2011 R. Yepsen

Private Citizen

1833 September 29, 2011 M. Boyett

Private Citizen

1834 September 29, 2011 A. Zito

Private Citizen

1835 September 29, 2011 J. Skurray

Private Citizen

1836 September 29, 2011 J. Fisher

Private Citizen

1837 September 29, 2011 S. Brown

Private Citizen

1838 September 29, 2011 K. Young

Private Citizen

1839 September 29, 2011 S. Stantejsky

Private Citizen

1840 September 29, 2011 B. Kobernuss

Private Citizen

1841 September 29, 2011 R. Ribeiro

Private Citizen

1842 September 29, 2011 R. Hill

Private Citizen

1843 September 29, 2011 Dr. C. Thomasson

Private Citizen

1844 September 29, 2011 R. Mckenzie

Private Citizen

1845 September 29, 2011 S. Kearney

Private Citizen

1846 September 29, 2011 J. Cutler

Private Citizen

1847 September 29, 2011 M. Chan

Private Citizen

1848 September 29, 2011 A. Gwartney

Private Citizen

1849 September 29, 2011 L. Larson

Private Citizen

1850 September 29, 2011 L. Avant

Private Citizen

1851 September 29, 2011 M. Culp

Private Citizen

1852 September 29, 2011 B. Loigman

Private Citizen

1853 September 29, 2011 P. Mortensen

Private Citizen
512

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1854 September 29, 2011 C. Keefe

Private Citizen

1855 September 29, 2011 C. Millhouse

Private Citizen

1856 September 29, 2011 C. Nichols

Private Citizen

1857 September 29, 2011 V. Mullins

Private Citizen

1858 September 29, 2011 E. Muelder

Private Citizen

1859 September 29, 2011 L. Hanratty

Private Citizen

1860 September 29, 2011 J. Slezak Fritz

Private Citizen

1861 September 29, 2011 J. Serrano

Private Citizen

1862 September 29, 2011 Dr. A. Botwin

Private Citizen

1863 September 29, 2011 C. Fulcher

Private Citizen

1864 September 29, 2011 C. Lippincott

Private Citizen

1865 September 29, 2011 D. Wooll

Private Citizen

1866 September 29, 2011 J. McGee

Private Citizen

1867 September 29, 2011 D. Mark

Private Citizen

1868 September 9, 2011 M. Brezin

Private Citizen

1869 September 29, 2011 J. Simonson

Private Citizen

1870 September 29, 2011 M. Starkey

Private Citizen

1871 September 29, 2011 B. C. Dick

Private Citizen

1872 September 29, 2011 J. S. Lennon

Private Citizen

1873 September 29, 2011 S. Bourgeois

Private Citizen

1874 September 29, 2011 J. Loring

Private Citizen

1875 September 29, 2011 B. Kaiser

Private Citizen

1876 September 29, 2011 Dr. K. Hurley

Private Citizen
513

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1877 September 29, 2011 Dr. P. Bertoncini

Private Citizen

1878 September 29, 2011 R. Miale

Private Citizen

1879 September 29, 2011 R. Blotter

Private Citizen

1880 September 29, 2011 D. Dutelle

Private Citizen

1881 September 29, 2011 Dr. D. Glick

Private Citizen

1882 September 29, 2011 J. Cohen

Private Citizen

1883 September 29, 2011 L. Spelman

Private Citizen

1884 September 29, 2011 Dr. D. Nord

Private Citizen

1885 September 29, 2011 V. Young

Private Citizen

1886 September 29, 2011 T. Davis

Private Citizen

1887 September 29, 2011 R. Meredith

Private Citizen

1888 September 29, 2011 R. Meredith

Private Citizen

1889 September 29, 2011 T. Whitcombe

Private Citizen

1890 September 29, 2011 S. Patterson

Private Citizen

1891 September 29, 2011 S. Helmholz

Private Citizen

1892 September 29, 2011 S. Fouche

Private Citizen

1893 September 29, 2011 C. Nix

Private Citizen

1894 September 29, 2011 G. Buzzetti

Private Citizen

1895 September 29, 2011 D. Soohoo

Private Citizen

1896 September 29, 2011 L. Shelton

Private Citizen

1897 September 29, 2011 J. McCrone-Ephraim

Private Citizen

1898 September 29, 2011 Dr. N. Wooduff

Private Citizen

1899 September 29, 2011 C. Dzubak

Private Citizen
514

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1900 September 29, 2011 F. Sugarman

Private Citizen

1901 September 29, 2011 R. Fisher

Private Citizen

1902 September 29, 2011 A. Drelles

Private Citizen

1903 September 29, 2011 N. Friend

Private Citizen

1904 September 29, 2011 S. McDonough

Private Citizen

1905 September 29, 2011 R. Ottinger

Private Citizen

1906 September 29, 2011 Dr. J. McClure

Private Citizen

1907 September 29, 2011 V. Mosca-Clark

Private Citizen

1908 September 29, 2011 D. Soong

Private Citizen

1909 September 29, 2011 J. Boots

Private Citizen

1910 September 29, 2011 S. Getter

Private Citizen

1911 September 29, 2011 W. Roberson

Private Citizen

1912 September 29, 2011 W. Pass

Private Citizen

1913 September 29, 2011 E. Bernhard

Private Citizen

1914 September 29, 2011 M. Sherman

Private Citizen

1915 September 29, 2011 Dr. W. Moore

Private Citizen

1916 September 29, 2011 K. Michasiow-Levy

Private Citizen

1917 September 29, 2011 S. Rios

Private Citizen

1918 September 29, 2011 H. Brene

Private Citizen

1919 September 29, 2011 B. Mulliken

Private Citizen

1920 September 29, 2011 C. Strother

Private Citizen

1921 September 29, 2011 R. Tomaselli

Private Citizen

1922 September 29, 2011 C. Lawson

Private Citizen
515

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1923 September 29, 2011 H. Ricciardi

Private Citizen

1924 September 29, 2011 E. Kappos

Private Citizen

1925 September 29, 2011 M. Kindelberger

Private Citizen

1926 September 29, 2011 B. Smith

Private Citizen

1927 September 29, 2011 J. Davis

Private Citizen

1928 September 29, 2011 K. Tretten

Private Citizen

1929 September 29, 2011 B. Ellingson

Private Citizen

1930 September 29, 2011 G. Koury

Private Citizen

1931 September 29, 2011 Dr. F. Norris

Private Citizen

1932 September 29, 2011 Dr. N. Rapp

Private Citizen

1933 September 29, 2011 V. Jhaveri

Private Citizen

1934 September 29, 2011 K. McInyre

Private Citizen

1935 September 29, 2011 J. Albers

Private Citizen

1936 September 29, 2011 S. Smith

Private Citizen

1937 September 29, 2011 K. Otero

Private Citizen

1938 September 29, 2011 S. Lopez

Private Citizen

1939 September 29, 2011 J. Paul

Private Citizen

1940 September 29, 2011 C. Long

Private Citizen

1941 September 29, 2011 A. Waters

Private Citizen

1942 September 29, 2011 E. Greisch

Private Citizen

1943 September 29, 2011 D. Peckler

Private Citizen

1944 September 29, 2011 S. Hartmann

Private Citizen

1945 September 29, 2011 N. Douglas

Private Citizen
516

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1946 September 29, 2011 A. Phillips Kushigemachi

Private Citizen

1947 September 29, 2011 R. Terrell

Private Citizen

1948 September 29, 2011 R. Terrell

Private Citizen

1949 September 29, 2011 P. Brockman

Private Citizen

1950 September 29, 2011 D. Siegal

Private Citizen

1951 September 29, 2011 B. Pontones

Private Citizen

1952 September 29, 2011 Dr. S.M. & A.R. Shahed

Private Citizens

1953 September 29, 2011 J. Millner

Private Citizen

1954 September 29, 2011 L. Atkinson

Private Citizen

1955 September 29, 2011 S. V. Dolsen

Private Citizen

1956 September 29, 2011 Dr. D. Dow

Private Citizen

1957 September 29, 2011 G. Nicolls

Private Citizen

1958 September 29, 2011 P. Donovan

Private Citizen

1959 September 29, 2011 D. Gaspard

Private Citizen

1960 September 29, 2011 P. Sargent

Private Citizen

1961 September 29, 2011 N. Hatalsky

Private Citizen

1962 September 29, 2011 K. Gallagher

Private Citizen

1963 September 29, 2011 R. and B. Stippec

Private Citizens

1964 September 29, 2011 P. Cusano

Private Citizen

1965 September 29, 2011 S. McNeil

Private Citizen

1966 September 29, 2011 J. Riggs

Private Citizen

1967 September 29, 2011 M. A. Waddel

Private Citizen

1968 September 29, 2011 F. Harper

Private Citizen
517

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1969 September 29, 2011 S. DeMers

Private Citizen

1970 September 29, 2011 L. Vaughters

Private Citizen

1971 September 29, 2011 R. Medina

Private Citizen

1972 September 29, 2011 T. Thurman

Private Citizen

1973 September 29, 2011 J. Riggs

Private Citizen

1974 September 29, 2011 R. Knablin

Private Citizen

1975 September 29, 2011 M. Briley

Private Citizen

1976 September 29, 2011 J. Shaw

Private Citizen

1977 September 29, 2011 V. Wingert

Private Citizen

1978 September 29, 2011 R. Lazzarini

Private Citizen

1979 September 29, 2011 J. Bilenky

Private Citizen

1980 September 29, 2011 Dr. W. Wagner

Private Citizen

1981 September 29, 2011 J. Buehler

Private Citizen

1982 September 29, 2011 S. Hubbard-Reeves

Private Citizen

1983 September 29, 2011 M. E. Ryall

Private Citizen

1984 September 29, 2011 A. Huff

Private Citizen

1985 September 29, 2011 B. Sageng

Private Citizen

1986 September 29, 2011 E. Clovis

Private Citizen

1987 September 29, 2011 F. Dews

Private Citizen

1988 September 29, 2011 D. Slocum

Private Citizen

1989 September 29, 2011 P. Keliher

Private Citizen

1990 September 29, 2011 J. Goddard

Private Citizen

1991 September 29, 2011 K. Herczegh

Private Citizen
518

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

1992 September 29, 2011 J. Laudisio

Private Citizen

1993 September 29, 2011 J. Weills

Private Citizen

1994 September 29, 2011 Z. Carter

Private Citizen

1995 September 29, 2011 A. Theobald

Private Citizen

1996 September 29, 2011 M. Quandt

Private Citizen

1997 September 29, 2011 Sierra Club

Mass Comment Campaign(23,560)

1998 September 29, 2011 M. Melanson

Private Citizen

1999 September 29, 2011 E. Ray

Private Citizen

2000 September 29, 2011 Dr. M. Weigel

Private Citizen

2001 September 29, 2011 M. Call

Private Citizen

2002 September 29, 2011 G. Dailey

Private Citizen

2003 September 29, 2011 C. Weaver

Private Citizen

2004 September 29, 2011 S. Vance

Private Citizen

2005 September 29, 2011 E. Gage

Private Citizen

2006 September 29, 2011 E. Scott

Private Citizen

2007 September 29, 2011 B. Nordahl

Private Citizen

2008 September 29, 2011 Y. Autrey-Schell

Private Citizen

2009 September 29, 2011 A. Berg

Private Citizen

2010 September 29, 2011 E. Albright

Private Citizen

2011 September 29, 2011 K. Kosek

Private Citizen

2012 September 29, 2011 T. Cotter

Private Citizen

2013 September 29, 2011 N. Zora

Private Citizen

2014 September 29, 2011 R. Sargent

Private Citizen
519

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2015 September 29, 2011 L. Groves

Private Citizen

2016 September 29, 2011 S. Bender

Private Citizen

2017 September 29, 2011 Dr. C. Nazor

Private Citizen

2018 September 29, 2011 G. Clements

Private Citizen

2019 September 29, 2011 J. Ailey

Private Citizen

2020 September 29, 2011 R. Yohalem

Private Citizen

2021 September 29, 2011 D. Mueller

Private Citizen

2022 September 29, 2011 T. McClinton

Private Citizen

2023 September 29, 2011 K. Sackton

Private Citizen

2024 September 29, 2011 M. Reed

Private Citizen

2025 September 29, 2011 M. Ritti

Private Citizen

2026 September 29, 2011 Dr. R. S. Grossman

Private Citizen

2027 September 29, 2011 B. Chaisson

Private Citizen

2028 September 29, 2011 T. Shoemaker

Private Citizen

2029 September 29, 2011 R. Bichard

Private Citizen

2030 September 29, 2011 A. Swift

Private Citizen

2031 September 29, 2011 R. DeLeo

Private Citizen

2032 September 29, 2011 S. Cooper

Private Citizen

2033 September 29, 2011 M. Kaskel

Private Citizen

2034 September 29, 2011 N. Armstrong

Private Citizen

2035 September 29, 2011 A. Starun

Private Citizen

2036 September 29, 2011 K. Feinberg

Private Citizen

2037 September 29, 2011 J. Hernandez

Private Citizen
520

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2038 September 29, 2011 Dr. R. R. Johnson

Private Citizen

2039 September 29, 2011 J. Unsinn

Private Citizen

2040 September 29, 2011 T. Tereszkiewicz

Private Citizen

2041 October 4, 2011 A. Millbrooke

Private Citizen

2042 September 29, 2011 J. Mueller

Private Citizen

2043 September 29, 2011 J. Rodrick

Private Citizen

2044 September 29, 2011 A. Harlib

Private Citizen

2045 September 29, 2011 A. Camino

Private Citizen

2046 September 29, 2011 R. Rayle

Private Citizen

2047 September 29, 2011 Dr. L Wolterg

Private Citizen

2048 September 29, 2011 G. Allerton

Private Citizen

2049 September 29, 2011 F. Kloch

Private Citizen

2050 September 29, 2011 C. Bruno

Private Citizen

2051 September 29, 2011 S. Klein

Private Citizen

2052 September 29, 2011 B. Boyce

Private Citizen

2053 September 29, 2011 S. Lemoncelli

Private Citizen

2055 September 29, 2011 D. Wallach

Private Citizen

2056 September 29, 2011 Dr. M. Janes

Private Citizen

2057 September 29, 2011 J. Lindeboom

Private Citizen

2058 September 29, 2011 J. Dortch

Private Citizen

2059 September 29, 2011 B. Stevens

Private Citizen

2060 September 29, 2011 B. DeLuca

Private Citizen

2061 September 29, 2011 A. Preston

Private Citizen
521

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2062 September 29, 2011 J. Mealer

Private Citizen

2063 September 29, 2011 C. L. Townsend

Private Citizen

2064 September 29, 2011 E. Ahl

Private Citizen

2065 September 29, 2011 D. Weinberg-Kinsey

Private Citizen

2066 September 29, 2011 K. Gore

Private Citizen

2067 September 29, 2011 P. Stangeland

Private Citizen

2068 September 29, 2011 S. Betterly

Private Citizen

2069 September 29, 2011 P. Lichtenwalner

Private Citizen

2070 September 29, 2011 D. Gendvil

Private Citizen

2071 September 29, 2011 S. Garver

Private Citizen

2072 September 29, 2011 J. Marino

Private Citizen

2073 October 5, 2011 R. Amp and G. Butz

Private Citizen

2074 September 29, 2011 S. Nelson

Private Citizen

2075 September 29, 2011 Dr. C. T. Williams

Private Citizen

2076 September 29, 2011 V. Smedberg

Private Citizen

2077 September 29, 2011 B. Ranharter

Private Citizen

2078 September 29, 2011 R. Valdez

Private Citizen

2079 September 29, 2011 O. Shaw

Private Citizen

2080 September 29, 2011 M. Cole

Private Citizen

2081 September 29, 2011 A. Wolf

Private Citizen

2082 September 29, 2011 L. Lane

Private Citizen

2083 September 29, 2011 C. Steytler

Private Citizen

2084 September 29, 2011 P. Rowe

Private Citizen
522

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2085 September 29, 2011 J. Fiske

Private Citizen

2086 September 29, 2011 E. Blumensaadt

Private Citizen

2087 September 29, 2011 T. Hamilton

Private Citizen

2088 September 29, 2011 A. Gallagher

Private Citizen

2089 September 29, 2011 T. Hamilton

Private Citizen

2090 September 29, 2011 F. Welty

Private Citizen

2091 September 29, 2011 T. Aldridge

Private Citizen

2092 September 29, 2011 J. Riggs

Private Citizen

2093 September 29, 2011 S. Morris

Private Citizen

2094 September 29, 2011 J. Katz

Private Citizen

2095 September 29, 2011 M. Underwood

Private Citizen

2096 September 29, 2011 J. Ben-Ari

Private Citizen

2097 September 29, 2011 J. Carlson

Private Citizen

2098 September 29, 2011 C. Heller

Private Citizen

2099 September 29, 2011 K. Cappa

Private Citizen

2100 September 29, 2011 J. Lyles

Private Citizen

2101 September 29, 2011 S. Dvorsky

Private Citizen

2102 September 29, 2011 Dr. L. Vaughan

Private Citizen

2103 September 29, 2011 T. Kozlowski

Private Citizen

2104 September 29, 2011 G. Pace

Private Citizen

2105 September 29, 2011 K. Cramer

Private Citizen

2106 September 29, 2011 M. Vayssieres

Private Citizen

2107 September 29, 2011 J. Glover

Private Citizen
523

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2108 September 29, 2011 P. Hollenbeak

Private Citizen

2109 September 29, 2011 J. Spoon

Private Citizen

2110 September 29, 2011 A. Vollbrecht

Private Citizen

2111 September 29, 2011 J. Holabird

Private Citizen

2112 September 29, 2011 M. Grimaldo

Private Citizen

2113 September 29, 2011 Dr. M. Atherton

Private Citizen

2114 September 29, 2011 M. Murphy

Private Citizen

2115 September 29, 2011 Dr. W. Saunders

Private Citizen

2116 September 29, 2011 Dr. J. Tavener

Private Citizen

2117 September 29, 2011 K. Hauck

Private Citizen

2118 September 29, 2011 A. Swan

Private Citizen

2119 September 29, 2011 C. Fette

Private Citizen

2120 September 29, 2011 Dr. D. Drews

Private Citizen

2121 September 29, 2011 E. Allen

Private Citizen

2122 September 29, 2011 Dr. J. Goldman

Private Citizen

2123 September 29, 2011 H. Booth

Private Citizen

2124 September 29, 2011 S. and P. Furlong

Private Citizens

2125 September 29, 2011 S. Chaudhary

Private Citizen

2126 September 29, 2011 J. Janssen

Private Citizen

2127 September 29, 2011 C. Perry

Private Citizen

2128 September 29, 2011 E. Larson

Private Citizen

2129 September 29, 2011 N. Sherman

Private Citizen

2130 September 29, 2011 G. Coleman

Private Citizen
524

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2131 September 29, 2011 D. Simpson

Private Citizen

2132 September 29, 2011 G. Fullerton

Private Citizen

2133 September 29, 2011 K. Cappa

Private Citizen

2134 September 29, 2011 M. Genin

Private Citizen

2135 September 29, 2011 M. Eliades

Private Citizen

2136 September 29, 2011 M. Smith

Private Citizen

2137 September 29, 2011 R. Weiss

Private Citizen

2138 September 29, 2011 R. Powell

Private Citizen

2139 September 29, 2011 M. Hosey

Private Citizen

2140 September 29, 2011 C. Grimley

Private Citizen

2141 September 29, 2011 S. Melhorn

Private Citizen

2142 September 29, 2011 B. and C. Riggs

Private Citizens

2143 September 29, 2011 P. Petkovich

Private Citizen

2144 September 29, 2011 J. Zang

Private Citizen

2145 September 29, 2011 Dr. S. C. Jones

Private Citizen

2146 September 29, 2011 J. Wallace

Private Citizen

2147 September 29, 2011 M. Tyler

Private Citizen

2148 September 29, 2011 V. Maturen

Private Citizen

2149 September 29, 2011 B. Drew

Private Citizen

2150 September 29, 2011 E. Burn

Private Citizen

2151 September 29, 2011 C. Boughton

Private Citizen

2152 September 29, 2011 D. Cush

Private Citizen

2153 September 29, 2011 R. Shannon

Private Citizen
525

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2154 September 29, 2011 J. Medling

Private Citizen

2155 September 29, 2011 E. Webb

Private Citizen

2156 September 29, 2011 D. Frey

Private Citizen

2157 September 29, 2011 R. Powell

Private Citizen

2158 September 29, 2011 M. Cato

Private Citizen

2159 September 29, 2011 S. Williams

Private Citizen

2160 September 29, 2011 C. Casey

Private Citizen

2161 September 29, 2011 H. Hickok

Private Citizen

2162 September 29, 2011 Dr. R. McNair

Private Citizen

2163 September 29, 2011 C. Burzynski

Private Citizen

2164 September 29, 2011 B. O'Brien

Private Citizen

2165 September 29, 2011 Dr. M. Tretter

Private Citizen

2166 September 29, 2011 Dr. E. Chute

Private Citizen

2167 September 29, 2011 L. Melvin

Private Citizen

2168 September 29, 2011 S. Huffmyer

Private Citizen

2169 September 29, 2011 J. Marden

Private Citizen

2170 September 29, 2011 J. Saylor

Private Citizen

2171 September 29, 2011 Dr. K. Carney-Godley

Private Citizen

2172 September 29, 2011 B. Cope

Private Citizen

2173 September 29, 2011 Bruce B.

Private Citizen

2174 September 29, 2011 G. Merchant

Private Citizen

2175 September 29, 2011 N. Hiatt

Private Citizen

2176 September 29, 2011 R. Schmetzer

Private Citizen
526

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2177 September 29, 2011 A. McNeill

Private Citizen

2178 September 29, 2011 R. Prosek

Private Citizen

2179 September 29, 2011 M.L. Lee

Private Citizen

2180 September 29, 2011 G. Merchant

Private Citizen

2181 September 29, 2011 K. Saint

Private Citizen

2182 September 29, 2011 C. Williams

Private Citizen

2183 September 29, 2011 B. Carlson

Private Citizen

2184 September 29, 2011 M. Linck

Private Citizen

2185 September 29, 2011 C. Chatfield

Private Citizen

2186 September 29, 2011 M. Finneran

Private Citizen

2187 October 11, 2011 Anonymous Public Comment

2188 September 29, 2011 R. Buckley

Private Citizen

2189 September 29, 2011 W. Hollingshead

Private Citizen

2190 September 29, 2011 V. Rigdon

Private Citizen

2191 September 29, 2011 K. Larsen

Private Citizen

2192 September 29, 2011 S. Erickson

Private Citizen

2193 September 29, 2011 R. Wells

Private Citizen

2194 September 29, 2011 C. Pagano

Private Citizen

2195 September 29, 2011 Sister J. P. Ridgeo

Private Citizen

2196 September 29, 2011 Dr. L. Matin

Private Citizen

2197 September 29, 2011 E. M. Green

Private Citizen

2198 September 29, 2011 H. Shipps

Private Citizen

2199 September 29, 2011 A. O'Connell

Private Citizen
527

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2200 September 29, 2011 E. Firor

Private Citizen

2201 September 29, 2011 B. A. White

Private Citizen

2202 September 29, 2011 K. Roberts

Private Citizen

2203 September 29, 2011 M. Ashelman

Private Citizen

2204 September 29, 2011 C. Barnes

Private Citizen

2205 September 29, 2011 R. Terry

Private Citizen

2206 September 29, 2011 L. Allen

Private Citizen

2207 September 29, 2011 J. Maguina

Private Citizen

2208 September 29, 2011 Dr. W. Berglund

Private Citizen

2209 October 7, 2011 Anonymous public comment

2210 September 29, 2011 A. Lukaszewski

Private Citizen

2211 September 29, 2011 C. George

Private Citizen

2212 September 29, 2011 J. Romano

Private Citizen

2213 September 29, 2011 K. Owens

Private Citizen

2214 September 29, 2011 Dr. C. Riseng

Private Citizen

2215 September 29, 2011 M. Gloeckner

Private Citizen

2216 September 29, 2011 D. D. Haines

Private Citizen

2217 September 29, 2011 R. Paquin

Private Citizen

2218 September 29, 2011 P. Taccetta

Private Citizen

2219 September 29, 2011 D. Meaders

Private Citizen

2220 September 29, 2011 D. Christenson

Private Citizen

2221 September 29, 2011 C. Tice-Tomasik

Private Citizen

2222 September 29, 2011 B. Anderson

Private Citizen
528

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2223 September 29, 2011 V. Lowell

Private Citizen

2224 September 29, 2011 Dr. M. Headrick

Private Citizen

2225 September 29, 2011 M. Davidek

Private Citizen

2226 September 29, 2011 M. Corvington

Private Citizen

2227 September 29, 2011 F. Lienhard

Private Citizen

2228 October 5, 2011 C. J. Nelson

Private Citizen

2229 October 5, 2011 R. and O. Robison

Private Citizen

2230 October 5, 2011 P. Simmons

Private Citizen

2231 October 5, 2011 J. Barnes

Private Citizen

2232 October 5, 2011 N. Wiggins

Private Citizen

2233 October 6, 2011 Dr. D. Moscatello

Private Citizen

2234 October 6, 2011 P. Cunningham

Private Citizen

2235 October 6, 2011 E. Knight

Private Citizen

2236 October 7, 2011 M. Swearingen

Private Citizen

2237 October 7, 2011 S. McDougal

Private Citizen

2238 October 7, 2011 M. Knapp

Private Citizen

2239 October 8, 2011 K. & Mary Jo Haag

Private Citizen

2240 October 9, 2011 L. Garvey

Private Citizen

2241 October 10, 2011 M. Pangasa

Private Citizen

2242 October 10, 2011 R. Masur

Private Citizen

2243 October 11, 2011 J. and M. Stoltenberg

Private Citizens

2244 September 29, 2011 K. King

Private Citizen

2245 October 11, 2011 Lisa S. Beal

Interstate Natural Gas Association of America
529

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2246 September 29, 2011 J. S. Fritz

Private Citizen

2247 September 29, 2011 Dr. D. Muir

Private Citizen

2248 September 29, 2011 C. K. Ross

Private Citizen

2249 September 29, 2011 J. Fiske

Private Citizen

2250 September 29, 2011 B. A. Leonard

Private Citizen

2251 September 29, 2011 B. Sonies

Private Citizen

2252 September 29, 2011 D. Stanko

Private Citizen

2253 September 29, 2011 M. Shaw

Private Citizen

2254 September 29, 2011 J. Kirman

Private Citizen

2255 September 29, 2011 Dr. C. Walter

Private Citizen

2256 September 29, 2011 Dr. M. A. Flournoy

Private Citizen

2257 September 29, 2011 J. Mayo

Private Citizen

2258 September 29, 2011 L. M. Padilla

Private Citizen

2259 September 29, 2011 A. Rodgers

Private Citizen

2260 September 29, 2011 S. Schreckengaust

Private Citizen

2261 September 29, 2011 E. Boyles

Private Citizen

2262 September 29, 2011 D. Bell

Private Citizen

2263 September 29, 2011 J. Kelly

Private Citizen

2264 September 29, 2011 P. Mitchell

Private Citizen

2265 September 29, 2011 L. Mattimore

Private Citizen

2266 October 3, 2011 W. Lewis

Private Citizen

2267 October 3, 2011 M. Cato

Private Citizen

2268 September 29, 2011 J. Fiske

Private Citizen
530

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2269 September 29, 2011 S. J. Worthman

Private Citizen

2270 September 29, 2011 S. Flores

Private Citizen

2271 September 29, 2011 R. Stanton

Private Citizen

2272 September 29, 2011 K. Greising

Private Citizen

2273 September 29, 2011 C. Malcolm

Private Citizen

2274 September 29, 2011 D. M. Sullivan

Private Citizen

2275 September 29, 2011 M. Rosenblum

Private Citizen

2276 September 29, 2011 S. Armstrong

Private Citizen

2277 September 29, 2011 M. Markesteyn

Private Citizen

2278 September 29, 2011 G. Cheadle

Private Citizen

2279 September 29, 2011 J. Lund

Private Citizen

2280 September 29, 2011 L. Gohlke

Private Citizen

2281 September 29, 2011 V. Barragan

Private Citizen

2282 September 29, 2011 M. Holguin

Private Citizen

2283 September 29, 2011 N. Jackson

Private Citizen

2284 September 29, 2011 H. Klussman

Private Citizen

2285 September 29, 2011 R. Lazcano

Private Citizen

2286 September 29, 2011 D. Carswell

Private Citizen

2287 September 29, 2011 D. Kloe

Private Citizen

2288 September 29, 2011 S. Lee

Private Citizen

2289 September 29, 2011 Dr. D. T. Webb

Private Citizen

2290 September 29, 2011 K. Donahue

Private Citizen

2291 October 3, 2011 M. Shimizu

Private Citizen
531

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2292 October 3, 2011 M. Yolles

Private Citizen

2293 October 3, 2011 Anonymous public comment

2294 October 4, 2011 A. Apt

Private Citizen

2295 October 4, 2011 M. Johnstad

Private Citizen

2296 October 4, 2011 C. Daum

Private Citizen

2297 October 4, 2011 P. House

Private Citizen

2298 October 4, 2011 P. Borneman

Private Citizen

2299 September 29, 2011 Dr. L. Morone

Private Citizen

2300 September 29, 2011 D. Davis

Private Citizen

2301 September 29, 2011 J. Madden

Private Citizen

2302 September 29, 2011 S. V. Gorder

Private Citizen

2303 September 29, 2011 C. Tebay

Private Citizen

2304 October 4, 2011 K. Birck

Private Citizen

2305 October 4, 2011 D. Conradi

Private Citizen

2306 October 4, 2011 R. Pust

Private Citizen

2307 September 29, 2011 S. Furber

Private Citizen

2308 September 29, 2011 S. Pentrek

Private Citizen

2309 September 29, 2011 S. Holzinger

Private Citizen

2310 September 29, 2011 C. Vallance

Private Citizen

2311 October 4, 2011 J. Zankner

Private Citizen

2312 October 4, 2011 D. Miller

Private Citizen

2313 September 29, 2011 M. Filman

Private Citizen

2314 September 29, 2011 S. Gruenler

Private Citizen
532

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2315 September 29, 2011 S. Cutler

Private Citizen

2316 September 29, 2011 S. Smith

2317 September 29, 2011 I. Pribanic

Private Citizen

2318 September 29, 2011 M. Steele

Private Citizen

2319 September 29, 2011 R. Miller

Private Citizen

2320 September 29, 2011 L. E. Durr

Private Citizen

2321 September 29, 2011 Dr. S. Buesing

Private Citizen

2322 September 29, 2011 F. Kelley

Private Citizen

2323 September 29, 2011 P. Jones

Private Citizen

2324 September 29, 2011 C. S. Siegel

Private Citizen

2325 October 4, 2011 T. Crawford

Private Citizen

2326 October 4, 2011 K. Armbruster

Private Citizen

2327 October 4, 2011 H. Shoup

Private Citizen

2328 October 4, 2011 B. Hunner

Private Citizen

2329 September 29, 2011 K. Kennedy

Private Citizen

2330 September 29, 2011 D. Kuyk

Private Citizen

2331 September 29, 2011 M. Gargiullo

Private Citizen

2332 September 29, 2011 A. Lenore

Private Citizen

2333 September 29, 2011 S. Richardson

Private Citizen

2334 September 29, 2011 R. Clark

Private Citizen

2335 September 29, 2011 D. Berman

Private Citizen

2336 September 29, 2011 D. Riall

Private Citizen

2337 September 29, 2011 D. Faraci

Private Citizen
533

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2338 September 29, 2011 L. Cotts

Private Citizen

2339 September 29, 2011 T. Ciarmatori

Private Citizen

2340 September 29, 2011 E. Gravlin

Private Citizen

2341 September 29, 2011 H. Andersen

Private Citizen

2342 September 29, 2011 G. Burdick

Private Citizen

2343 September 29, 2011 A. Alsop

Private Citizen

2344 September 29, 2011 K. Fox

Private Citizen

2345 September 29, 2011 Dr. N. Jackson

Private Citizen

2346 September 29, 2011 C. Iberg

Private Citizen

2347 September 29, 2011 B. Hartung

Private Citizen

2348 September 29, 2011 L. Davidson

Private Citizen

2349 September 29, 2011 P. Cross

Private Citizen

2350 September 29, 2011 T. Bloyd

Private Citizen

2351 September 29, 2011 L. Larrabee

Private Citizen

2352 September 29, 2011 Mrs. S. P.

Private Citizen

2353 September 29, 2011 C. Fernsworth

Private Citizen

2354 September 29, 2011 D. Williamson

Private Citizen

2355 September 29, 2011 J. Danielson

Private Citizen

2356 September 29, 2011 J. Auris

Private Citizen

2357 September 29, 2011 P. Bradbury

Private Citizen

2358 September 29, 2011 J. L. Sueur

Private Citizen

2359 September 29, 2011 R. Roberts

Private Citizen

2360 September 29, 2011 K. W. Trott

Private Citizen
534

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2361 September 29, 2011 K. Nimetz

Private Citizen

2362 September 29, 2011 G. Newbold

Private Citizen

2363 September 29, 2011 A. Gress

Private Citizen

2364 September 29, 2011 J. Draper

Private Citizen

2365 September 29, 2011 S. Brodak

Private Citizen

2366 September 29, 2011 K. Trebesch

Private Citizen

2367 September 29, 2011 L. Teman

Private Citizen

2368 September 29, 2011 W. Hanks

Private Citizen

2369 September 29, 2011 L. Guignard

Private Citizen

2370 September 29, 2011 M.L. Morgenstern

Private Citizen

2371 September 29, 2011 A. Pierce

Private Citizen

2372 September 30, 2011 Mass Comment Campaign sponsoring organization 

unknown (10)

2373 September 29, 2011 A. Malden

Private Citizen

2374 September 29, 2011 B. Vaughn

Private Citizen

2375 September 29, 2011 J. Burgen

Private Citizen

2376 September 29, 2011 P. Palla

Private Citizen

2377 September 29, 2011 K. Sundar

Private Citizen

2378 September 29, 2011 J. Kerler

Private Citizen

2379 September 29, 2011 B. Havlena

Private Citizen

2380 October 4, 2011 N. and D. Jochem

Private Citizens

2381 October 4, 2011 V. Jimenez

Private Citizen

2382 October 4, 2011 M. Gilbert

Private Citizen

2383 October 4, 2011 L. Gilleon

Private Citizen
535

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2384 October 4, 2011 N. Bishop

Private Citizen

2385 October 4, 2011 M. Strainer

Private Citizen

2386 October 4, 2011 E. Morris

Private Citizen

2387 October 4, 2011 N. Schildcrout

Private Citizen

2388 October 4, 2011 J. Matthews

Private Citizen

2389 October 4, 2011 Anonymous public comment

2390 October 5, 2011 C. Gustafson

Private Citizen

2391 October 5, 2011 P. Earle

Private Citizen

2392 October 5, 2011 D. Wainwright

Private Citizen

2393 October 5, 2011 E. Denton

Private Citizen

2394 October 5, 2011 D. Sobie

Private Citizen

2395 September 29, 2011 R. Bogue

Private Citizen

2396 September 29, 2011 C. Gelinas

Private Citizen

2397 September 29, 2011 K. de Weille

Private Citizen

2398 September 29, 2011 K. Hikiji

Private Citizen

2399 September 29, 2011 M. Kein

Private Citizen

2400 September 29, 2011 B. Downey

Private Citizen

2401 September 29, 2011 B. Langan

Private Citizen

2402 September 29, 2011 J. Thompson

Private Citizen

2403 September 29, 2011 J. Price

Private Citizen

2404 September 29, 2011 N. Rutland

Private Citizen

2405 September 29, 2011 R. Epstein

Private Citizen

2406 September 29, 2011 S. Shane

Private Citizen
536

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2407 September 29, 2011 H. Findley

Private Citizen

2408 September 29, 2011 J. Silman

Private Citizen

2409 September 29, 2011 J. Berghorn

Private Citizen

2410 September 29, 2011 V. Vanderau

Private Citizen

2411 September 29, 2011 P. Hull

Private Citizen

2412 September 29, 2011 J. Hicks

Private Citizen

2413 September 29, 2011 D. Fisher

Private Citizen

2414 September 29, 2011 S. Belair

Private Citizen

2415 September 29, 2011 C. Chowen

Private Citizen

2416 September 29, 2011 L. Nabity

Private Citizen

2417 September 29, 2011 N. Walbourn

Private Citizen

2418 September 29, 2011 Dr. C. Cafarelli

Private Citizen

2419 September 29, 2011 N. Ruggles

Private Citizen

2420 September 29, 2011 S. E. Smith

Private Citizen

2421 September 29, 2011 T. Stephens

Private Citizen

2422 September 29, 2011 C. Lamet

Private Citizen

2423 September 29, 2011 D. Heaton

Private Citizen

2424 September 29, 2011 C. King

Private Citizen

2425 September 29, 2011 Dr. F. Guerrero

Private Citizen

2426 September 29, 2011 M. Hunter

Private Citizen

2427 September 29, 2011 K. Coventry

Private Citizen

2428 September 29, 2011 R. Wright

Private Citizen

2429 September 29, 2011 G. Huizenga

Private Citizen
537

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2430 September 29, 2011 E. Copp-Phelan

Private Citizen

2431 September 29, 2011 P. McWillimas

Private Citizen

2432 September 29, 2011 F. Akers

Private Citizen

2433 September 29, 2011 B. Advani

Private Citizen

2434 September 29, 2011 Dr. S. Jones

Private Citizen

2435 September 29, 2011 S. Avery

Private Citizen

2436 September 29, 2011 S. Koch

Private Citizen

2437 September 29, 2011 J. Anton

Private Citizen

2438 September 29, 2011 R. Rentner

Private Citizen

2439 September 29, 2011 M. Emery

Private Citizen

2440 September 29, 2011 S. Woerner

Private Citizen

2441 September 29, 2011 H. Gressitt

Private Citizen

2442 September 29, 2011 S. Butler

Private Citizen

2443 September 29, 2011 V. Free

Private Citizen

2444 September 29, 2011 G. Adams

Private Citizen

2445 September 29, 2011 M. J. Krul

Private Citizen

2446 September 29, 2011 S. Thomas

Private Citizen

2447 September 29, 2011 Dr. A. Grasso

Private Citizen

2448 September 29, 2011 L. Torres

Private Citizen

2449 September 29, 2011 C. Kubiak

Private Citizen

2450 September 29, 2011 B. Burgess

Private Citizen

2451 September 29, 2011 C. Prose

Private Citizen

2452 September 29, 2011 C. Lange

Private Citizen
538

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2453 September 29, 2011 R. Couture

Private Citizen

2454 September 29, 2011 A. Galvez

Private Citizen

2455 September 29, 2011 C. Fried

Private Citizen

2456 September 29, 2011 D. Horton

Private Citizen

2457 September 29, 2011 A. Loretan

Private Citizen

2458 September 29, 2011 S. Omiecinski

Private Citizen

2459 September 29, 2011 E. Dixon

Private Citizen

2460 September 29, 2011 C. Taylor

Private Citizen

2461 September 29, 2011 W. and N. Klink

Private Citizen

2462 September 29, 2011 E. Virgil

Private Citizen

2463 September 29, 2011 B. Wicklen

Private Citizen

2464 September 29, 2011 K. Rooney

Private Citizen

2465 September 29, 2011 J. Mitchell

Private Citizen

2466 September 29, 2011 L. Lindsay

Private Citizen

2467 September 29, 2011 R. Fischer

Private Citizen

2468 September 29, 2011 G. Prusaitis

Private Citizen

2469 September 29, 2011 R. Rudinger

Private Citizen

2470 September 29, 2011 B. Trevvett

Private Citizen

2471 September 29, 2011 R. Sdano

Private Citizen

2472 September 29, 2011 K. Blair

Private Citizen

2473 September 29, 2011 J. Smith

Private Citizen

2474 September 29, 2011 L. Jarsocrak

Private Citizen

2475 September 29, 2011 L. Dixon

Private Citizen
539

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2476 September 29, 2011 B. Kern

Private Citizen

2477 September 29, 2011 N. Lyman

Private Citizen

2478 September 29, 2011 B. Culp

Private Citizen

2479 September 29, 2011 M. Gardner

Private Citizen

2480 September 29, 2011 L. Lubonty

Private Citizen

2481 September 29, 2011 E. Breiling

Private Citizen

2482 September 29, 2011 E. Asher

Private Citizen

2483 September 29, 2011 J. Keevert

Private Citizen

2484 September 29, 2011 J. Spyder

Private Citizen

2485 September 29, 2011 J. Patrick

Private Citizen

2486 September 29, 2011 B. Rosenblum

Private Citizen

2487 September 29, 2011 E. Malina

Private Citizen

2488 September 29, 2011 N. H. Bernstein

Private Citizen

2489 September 29, 2011 K. Schweiss

Private Citizen

2490 September 29, 2011 M. Ellington

Private Citizen

2491 September 29, 2011 N. Engelfried

Private Citizen

2492 September 29, 2011 G. Wray

Private Citizen

2493 September 29, 2011 J. Auris

Private Citizen

2494 September 29, 2011 M. Milton

Private Citizen

2495 September 29, 2011 C. Orwick

Private Citizen

2496 September 29, 2011 S. Clark

Private Citizen

2497 September 29, 2011 B. Hurst

Private Citizen

2498 September 29, 2011 Dr. R. Trimmer

Private Citizen
540

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2499 September 29, 2011 Dr. P. Mathieson

Private Citizen

2500 September 29, 2011 D. Richardson

Private Citizen

2501 September 29, 2011 G. Neustadt

Private Citizen

2502 September 29, 2011 V. Tomasson

Private Citizen

2503 September 29, 2011 R. Smith

Private Citizen

2504 September 29, 2011 S. Parker

Private Citizen

2505 September 29, 2011 R. Peterson

Private Citizen

2506 September 29, 2011 A. Carrino

Private Citizen

2507 September 29, 2011 W. Silver

Private Citizen

2508 September 29, 2011 J. Hargleroad

Private Citizen

2509 September 29, 2011 B. Thacker

Private Citizen

2510 September 29, 2011 S. Stein

Private Citizen

2511 September 29, 2011 Dr. M. Piscitelli

Private Citizen

2512 September 29, 2011 L. Wolf

Private Citizen

2513 September 29, 2011 D. Thayer

Private Citizen

2514 September 29, 2011 A. McCarthy

Private Citizen

2515 September 29, 2011 J. Pequette

Private Citizen

2516 September 29, 2011 E. Jimenez

Private Citizen

2517 September 29, 2011 P. Lee

Private Citizen

2518 September 29, 2011 M. Fullerton

Private Citizen

2519 September 29, 2011 J. Forgione

Private Citizen

2520 September 29, 2011 D. Graeve

Private Citizen

2521 September 29, 2011 S. Marquez

Private Citizen
541

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2522 September 29, 2011 P. Grady

Private Citizen

2523 September 29, 2011 J. Alanis

Private Citizen

2524 September 29, 2011 D. Dodd

Private Citizen

2525 September 29, 2011 P. Kaiser

Private Citizen

2526 September 29, 2011 P. Jarvis

Private Citizen

2527 September 29, 2011 C. Talucci

Private Citizen

2528 September 29, 2011 N. Brosnan

Private Citizen

2529 September 29, 2011 K. Regalado

Private Citizen

2530 September 29, 2011 T. Nighswonger

Private Citizen

2531 September 29, 2011 Dr. Z. Moursi

Private Citizen

2532 September 29, 2011 V. Stone

Private Citizen

2533 September 29, 2011 M. Blair

Private Citizen

2534 September 29, 2011 E. Johnson

Private Citizen

2535 September 29, 2011 C. Swatek

Private Citizen

2536 September 29, 2011 L. Dixon

Private Citizen

2537 September 29, 2011 J. Carlin

Private Citizen

2538 September 29, 2011 D. Updegraff

Private Citizen

2539 September 29, 2011 J. Ames-Curtis

Private Citizen

2540 September 29, 2011 P. Kaminski

Private Citizen

2541 September 29, 2011 R. Webb

Private Citizen

2542 September 29, 2011 D. Melino

Private Citizen

Private Citizen

2543 September 29, 2011 M. Beuth

Private Citizen
542

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2544 September 29, 2011 E. Franklin

Private Citizen

2545 September 29, 2011 K. McLellan

Private Citizen

2546 September 29, 2011 R. Backlund

Private Citizen

2547 September 29, 2011 W. Birdwell

Private Citizen

2548 September 29, 2011 J. Vulcan

Private Citizen

2549 September 29, 2011 K. Mcconnell

Private Citizen

2550 September 29, 2011 C. Rappoport

Private Citizen

2551 September 29, 2011 A. Kuenzel

Private Citizen

2552 September 29, 2011 J. Wroe

Private Citizen

2553 September 29, 2011 J. Harris

Private Citizen

2554 September 29, 2011 B. Gallo

Private Citizen

2555 September 29, 2011 J. Norgrove

Private Citizen

2556 September 29, 2011 K. Lombardozzi

Private Citizen

2557 September 29, 2011 M. Faugno

Private Citizen

2558 September 29, 2011 L. Pohl

Private Citizen

2559 September 29, 2011 E. Carpenter

Private Citizen

2560 September 29, 2011 T. and S. Loomis

Private Citizens

2561 September 29, 2011 G. Hatfield

Private Citizen

2562 September 29, 2011 K. Kaczmarek

Private Citizen

2563 September 29, 2011 P. Pittenger

Private Citizen

2564 September 29, 2011 S. Berger

Private Citizen

2565 September 29, 2011 S. Wolff

Private Citizen

2566 September 29, 2011 M. Hanks

Private Citizen
543

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2567 September 29, 2011 B. Barton

Private Citizen

2568 September 29, 2011 C. Wyant

Private Citizen

2569 September 29, 2011 R. Swiatek

Private Citizen

2570 September 29, 2011 A. Nienaber

Private Citizen

2571 September 29, 2011 A. Hagerty

Private Citizen

2572 September 29, 2011 W. Barclay

Private Citizen

2573 September 29, 2011 D. Morace

Private Citizen

2574 September 29, 2011 M. Gauguet

Private Citizen

2575 September 29, 2011 C. Collins

Private Citizen

2576 September 29, 2011 B. Casper

Private Citizen

2577 September 29, 2011 P. Canan

Private Citizen

2578 September 29, 2011 K. Lehr

Private Citizen

2579 September 29, 2011 M. McCleskey

Private Citizen

2580 September 29, 2011 E. Bukowski

Private Citizen

2581 September 29, 2011 L. Douglass

Private Citizen

2582 September 29, 2011 C. Thompson

Private Citizen

2583 September 29, 2011 J. Maisel

Private Citizen

2584 September 29, 2011 T. Testa

Private Citizen

2585 September 29, 2011 P. Robertson

Private Citizen

2586 September 29, 2011 M. Beaver

Private Citizen

2587 September 29, 2011 L. Baxley

Private Citizen

2588 September 29, 2011 B. George

Private Citizen

2589 September 29, 2011 J. Dalnoky

Private Citizen
544

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2590 September 29, 2011 M. Barron

Private Citizen

2591 September 29, 2011 Z. Sackstein

Private Citizen

2592 September 29, 2011 D. Jacobi

Private Citizen

2593 September 29, 2011 B. Birnbaum

Private Citizen

2594 September 29, 2011 S. Taichert

Private Citizen

2595 September 29, 2011 R. Buck

Private Citizen

2596 September 29, 2011 K. Miller

Private Citizen

2597 September 29, 2011 C. Bell

Private Citizen

2598 September 29, 2011 S. Hamilton

Private Citizen

2599 September 29, 2011 R. Friday

Private Citizen

2600 September 29, 2011 R. Witbeck

Private Citizen

2601 September 29, 2011 C. Manzano

Private Citizen

2602 September 29, 2011 S. Crognale

Private Citizen

2603 September 29, 2011 J. S. Lennon

Private Citizen

2604 September 29, 2011 S. Iverson

Private Citizen

2605 September 29, 2011 J. Kruger

Private Citizen

2606 September 29, 2011 E. George

Private Citizen

2607 September 29, 2011 M. Broad

Private Citizen

2608 September 29, 2011 J. Garcia

Private Citizen

2609 September 29, 2011 G. Burke

Private Citizen

2610 September 29, 2011 V. Hauser

Private Citizen

2611 September 29, 2011 K. Reed

Private Citizen

2612 September 29, 2011 D. DiBasio

Private Citizen
545

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2613 June 29, 2011 E. Hitchcock

Private Citizen

2614 September 29, 2011 D. Rigolizzi

Private Citizen

2615 September 29, 2011 A. Drucker

Private Citizen

2616 September 29, 2011 Dr. T. Doebber

Private Citizen

2617 September 29, 2011 J. Burrie

Private Citizen

2618 September 29, 2011 M. Vane

Private Citizen

2619 September 29, 2011 B. Mansfield

Private Citizen

2620 September 29, 2011 D. Ryniec

Private Citizen

2621 September 29, 2011 J. Wald

Private Citizen

2622 September 29, 2011 M. Cloghessy

Private Citizen

2623 September 29, 2011 G. Greer

Private Citizen

2624 September 29, 2011 A. Bradley

Private Citizen

2625 September 29, 2011 N. Gallagher

Private Citizen

2626 September 29, 2011 T. Tercheck

Private Citizen

2627 September 29, 2011 L. Zielinski

Private Citizen

2628 September 29, 2011 Emily P. (no surname provided)

Private Citizen

2629 September 29, 2011 D. Horton

Private Citizen

2630 September 29, 2011 J. Pacal

Private Citizen

2631 September 29, 2011 H. Haehlen

Private Citizen

2632 September 29, 2011 M. Fusco

Private Citizen

2633 September 29, 2011 H. Van Hoozer

Private Citizen

2634 September 29, 2011 J. Siddons

Private Citizen

2635 September 29, 2011 K. Taylor

Private Citizen
546

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2636 September 29, 2011 K. Gianopulos

Private Citizen

2637 September 29, 2011 A. Blankinship

Private Citizen

2638 September 29, 2011 L. Rasmussen

Private Citizen

2639 September 29, 2011 F. Martens

Private Citizen

2640 September 29, 2011 M. Buszek

Private Citizen

2641 September 29, 2011 T. Roth

Private Citizen

2642 September 29, 2011 J. Van Dinter

Private Citizen

2643 September 29, 2011 L. Lynn

Private Citizen

2644 September 29, 2011 D. Judge-Lord

Private Citizen

2645 September 29, 2011 K. McShane

Private Citizen

2646 September 29, 2011 W. Schneider

Private Citizen

2647 September 29, 2011 A. Conklin

Private Citizen

2648 September 29, 2011 C. Brobst

Private Citizen

2649 September 29, 2011 G. Bryer

Private Citizen

2650 September 29, 2011 P. Bisesi

Private Citizen

2651 September 29, 2011 M. Fowler

Private Citizen

2652 September 29, 2011 W. Peterson

Private Citizen

2653 September 29, 2011 A. Grammatico

Private Citizen

2654 September 29, 2011 B. Snapp

Private Citizen

2655 September 29, 2011 L. Knight

Private Citizen

2656 September 29, 2011 S. Sanders

Private Citizen

2657 September 29, 2011 M. Fishel

Private Citizen

2658 September 29, 2011 M. Borich

Private Citizen
547

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2659 September 29, 2011 D. Hooper

Private Citizen

2660 September 29, 2011 D. Lifton

Private Citizen

2661 September 29, 2011 G. Creswell

Private Citizen

2662 September 29, 2011 A. Vrugtman

Private Citizen

2663 September 29, 2011 L. Wrixon

Private Citizen

2664 September 29, 2011 D. Gribschaww

Private Citizen

2665 September 29, 2011 N. Moelter

Private Citizen

2666 September 29, 2011 M. Pings

Private Citizen

2667 September 29, 2011 E. Hallinan

Private Citizen

2668 September 29, 2011 J. Nash

Private Citizen

2669 September 29, 2011 S. Eaton

Private Citizen

2670 September 29, 2011 R. Pugliese

Private Citizen

2671 September 29, 2011 M. Leonard

Private Citizen

2672 September 29, 2011 L. Hope

Private Citizen

2673 September 29, 2011 S. Carmack

Private Citizen

2674 September 29, 2011 A. Furfaro

Private Citizen

2675 September 29, 2011 A. Ploumis Bradley

Private Citizen

2676 September 29, 2011 D. Boyle-Clapp

Private Citizen

2677 September 29, 2011 J. Smythe

Private Citizen

2678 September 29, 2011 D. Raven

Private Citizen

2679 September 29, 2011 W. Jones

Private Citizen

2680 September 29, 2011 E. Sloan

Private Citizen

2681 September 29, 2011 V. Rosenstreich

Private Citizen
548

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2682 September 29, 2011 L. Falls

Private Citizen

2683 September 29, 2011 R. Elias

Private Citizen

2684 September 29, 2011 M. Orr

Private Citizen

2685 September 29, 2011 M. Henley

Private Citizen

2686 September 29, 2011 D. Freeman

Private Citizen

2687 September 29, 2011 H. Cohen

Private Citizen

2688 September 29, 2011 P. Nadler

Private Citizen

2689 September 29, 2011 M. Taylor

Private Citizen

2690 September 29, 2011 C. Shattuck

Private Citizen

2691 September 29, 2011 D. Stirling

Private Citizen

2692 September 29, 2011 D. Hull

Private Citizen

2693 September 29, 2011 C. Adams

Private Citizen

2694 September 29, 2011 R. Olsen

Private Citizen

2695 September 29, 2011 K. Trong

Private Citizen

2696 September 29, 2011 R. Shaffer

Private Citizen

2697 September 29, 2011 D. Bish

Private Citizen

2698 September 29, 2011 H. Douglas

Private Citizen

2699 September 29, 2011 S. James

Private Citizen

2700 September 29, 2011 D. Lewis

Private Citizen

2701 September 29, 2011 T. Henderson

Private Citizen

2702 September 29, 2011 C. Williams

Private Citizen

2703 September 29, 2011 K. LaFon

Private Citizen

2704 September 29, 2011 J. Boriack

Private Citizen
549

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2705 September 29, 2011 J. Pratt

Private Citizen

2706 September 29, 2011 B. Lupi

Private Citizen

2707 September 29, 2011 D. Sutherland

Private Citizen

2708 September 29, 2011 L. Graffious

Private Citizen

2709 September 29, 2011 R. Lathern-Ponneck

Private Citizen

2710 September 29, 2011 T. Stephas

Private Citizen

2711 September 29, 2011 M. Thomas

Private Citizen

2712 September 29, 2011 M. Dalnoky

Private Citizen

2713 September 29, 2011 R. Launier

Private Citizen

2714 September 29, 2011 C. Sterne

Private Citizen

2715 September 29, 2011 C. Andersen

Private Citizen

2716 September 29, 2011 C. Hahin

Private Citizen

2717 October 11, 2011 L. K. Christensen

Private Citizen

2718 October 11, 2011 Chris Daum

Oasis Montana Inc.

2719 September 29, 2011 P. King-Rediger

Private Citizen

2720 September 29, 2011 L. Helgedalen

Private Citizen

2721 September 29, 2011 P. McGee

Private Citizen

2722 September 29, 2011 E. Whitmore

Private Citizen

2723 September 29, 2011 K. Brill

Private Citizen

2724 September 29, 2011 L. Spector

Private Citizen

2725 September 29, 2011 T. Bugas

Private Citizen

2726 September 29, 2011 L. Jordan

Private Citizen

2727 September 29, 2011 O. Christopher

Private Citizen
550

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2728 September 29, 2011 J. Hardy

Private Citizen

2729 September 29, 2011 D. Schuessler

Private Citizen

2730 September 29, 2011 L. Gorsuch

Private Citizen

2731 September 29, 2011 M. Johnson

Private Citizen

2732 September 29, 2011 M. Naimark

Private Citizen

2733 September 29, 2011 A. Kiley

Private Citizen

2734 September 29, 2011 S. Verow

Private Citizen

2735 September 29, 2011 P. Schramm

Private Citizen

2736 September 29, 2011 P. Damon

Private Citizen

2737 September 29, 2011 J. Taylor

Private Citizen

2738 September 29, 2011 R. Gebert

Private Citizen

2739 September 29, 2011 K. Fedorov

Private Citizen

2740 September 29, 2011 Dr. L. Black

Private Citizen

2741 September 29, 2011 S. Bacon

Private Citizen

2742 September 29, 2011 H. De Marne

Private Citizen

2743 September 29, 2011 D. Utevsky

Private Citizen

2744 September 29, 2011 L. Lawson

Private Citizen

2745 September 29, 2011 Jill Godmilow

Private Citizen

2746 September 29, 2011 M. Sinclair

Private Citizen

2747 September 29, 2011 C. Baril

Private Citizen

2748 September 29, 2011 M. Fitzgerald

Private Citizen

2749 September 29, 2011 T. Chaudhry

Private Citizen

2750 September 14, 2011 Peter D. Robertson

America's Natural Gas Alliance
551

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2751 October 16, 2011 E. Karnowski

Private Citizen

2752 September 29, 2011 K. Rockett

Private Citizen

2753 September 29, 2011 J. Wagner

Private Citizen

2754 September 29, 2011 L. Dameron

Private Citizen

2755 September 29, 2011 M. Vogl

Private Citizen

2756 September 29, 2011 N. Cianchetta

Private Citizen

2757 September 29, 2011 R. Strack

Private Citizen

2758 September 29, 2011 Dr. S. LaBine

Private Citizen

2759 September 29, 2011 J. Pettit

Private Citizen

2760 September 29, 2011 G. Boderke

Private Citizen

2761 October 12, 2011 M. Pangasa

Private Citizen

2762 October 12, 2011 Anonymous public comment

2763 September 29, 2011 S. Bedford

Private Citizen

2764 October 12, 2011 T. Ream

Private Citizen

2765 October 14, 2011 B. Brown

Private Citizen

2766 October 11, 2011 N. Lusskin

Private Citizen

2767 October 13, 2011 L. Liller

Private Citizen

2768 October 13, 2011 M. Yoder

Private Citizen

2769 September 29, 2011 M. Finley

Private Citizen

2770 September 29, 2011 J. Horne

Private Citizen

2771 September 29, 2011 S. Getter

Private Citizen

2772 September 29, 2011 J. Felker

Private Citizen

2773 September 29, 2011 K. Clifton

Private Citizen
552

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2774 September 29, 2011 M. Schab

Private Citizen

2775 September 29, 2011 R. Franco

Private Citizen

2776 September 29, 2011 M. Schmotzer

Private Citizen

2777 September 29, 2011 M. Engelman

Private Citizen

2778 September 29, 2011 R. Tiedemann

Private Citizen

2779 September 29, 2011 B. Ames

Private Citizen

2780 September 29, 2011 R. Brown

Private Citizen

2781 September 29, 2011 D. and A. Riley

Private Citizen

2782 September 29, 2011 M. Savrasova

Private Citizen

2783 September 29, 2011 K. Scott

Private Citizen

2784 September 29, 2011 N. Coslar

Private Citizen

2785 September 29, 2011 L. Frank

Private Citizen

2786 September 29, 2011 S. Johnston

Private Citizen

2787 September 29, 2011 Dr. F. Schwartzwald

Private Citizen

2788 September 29, 2011 A. McLeod

Private Citizen

2789 September 29, 2011 J. Steele

Private Citizen

2790 September 29, 2011 C. Hall

Private Citizen

2791 September 29, 2011 A. Encarnacao

Private Citizen

2792 September 29, 2011 M. Smith

Private Citizen

2793 September 29, 2011 J. Hitchcock

Private Citizen

2794 September 29, 2011 T. Hash

Private Citizen

2795 September 29, 2011 H. Findley

Private Citizen

2796 September 29, 2011 H. Schlicker

Private Citizen
553

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2797 October 17, 2011 Anonymous public comment

2798 September 29, 2011 M. Joyce

Private Citizen

2799 September 29, 2011 K. Klein

Private Citizen

2800 October 8, 2011 G. D. Bateman

Private Citizen

2801 October 12, 2011 L. Todd

Private Citizen

2802 September 29, 2011 T. Hocott

Private Citizen

2803 October 12, 2011 Shaun Porter

Arkansas Water Protection Alliance

2804 September 29, 2011 J. Janecki

Private Citizen

2805 September 29, 2011 J. Sherman

Private Citizen

2806 September 29, 2011 T. Myers

Private Citizen

2807 October 14, 2011 C. A. Dimon

Private Citizen

2808 September 29, 2011 P. Chow

Private Citizen

2809 September 29, 2011 N. Wilkison

Private Citizen

2810 September 29, 2011 C. Kuster

Private Citizen

2811 September 29, 2011 B. Tague

Private Citizen

2812 September 29, 2011 A. Letey

Private Citizen

2813 September 29, 2011 P. Valek

Private Citizen

2814 September 29, 2011 A. Young

Private Citizen

2815 September 29, 2011 T. Hempel

Private Citizen

2816 September 29, 2011 R. Nielsen

Private Citizen

2817 September 29, 2011 S. Rekdal

Private Citizen

2818 September 29, 2011 S. Rekdal

Private Citizen

2819 September 29, 2011 C. Russell

Private Citizen
554

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2820 September 29, 2011 M. Miller

Private Citizen

2821 October 17, 2011 Anonymous public comment

2822 October 17, 2011 Anonymous public comment

2823 October 17, 2011 K. Spring

Private Citizen

2824 October 17, 2011 A. Macdonald

Private Citizen

2825 October 17, 2011 L. Harter

Private Citizen

2826 October 17, 2011 A. Lindsey

Private Citizen

2827 October 17, 2011 D. Van Buren

Private Citizen

2828 October 17, 2011 C. Hoyer

Private Citizen

2829 October 17, 2011 J. Phillips

Private Citizen

2830 October 17, 2011 G. Gardner

Private Citizen

2831 October 17, 2011 A. C. Hander

Private Citizen

2832 October 17, 2011 Dr. J. Perlman

Private Citizen

2833 October 17, 2011 C. Stewart

Private Citizen

2834 October 17, 2011 E. Gilbertson

Private Citizen

2835 October 17, 2011 G. Nuckels

Private Citizen

2836 October 17, 2011 S. Moffitt

Private Citizen

2837 October 17, 2011 J. Gillmar

Private Citizen

2838 October 17, 2011 R. Walter

Private Citizen

2839 October 17, 2011 Dr. E. Robbins

Private Citizen

2840 October 17, 2011 A. Bowen

Private Citizen

2841 October 17, 2011 W. Handley

Private Citizen

2842 October 17, 2011 P. Jerrells

Private Citizen

2843 October 17, 2011 M. Badaloni

Private Citizen
555

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2844 October 17, 2011 R. Holloway

Private Citizen

2845 October 17, 2011 A. Teruel

Private Citizen

2846 October 17, 2011 R. Hyer II

Private Citizen

2847 October 17, 2011 L. Wadley

Private Citizen

2848 October 17, 2011 E. Mcguire

Private Citizen

2849 October 17, 2011 M. Herrera

Private Citizen

2850 October 17, 2011 D. Krolick

Private Citizen

2851 October 17, 2011 S. Ebershoff-Coles

Private Citizen

2852 October 17, 2011 F. Portell

Private Citizen

2853 October 17, 2011 P. Sladek

Private Citizen

2854 October 17, 2011 N. Paterno

Private Citizen

2855 October 17, 2011 D. Vogel

Private Citizen

2856 October 17, 2011 R. Bennett

Private Citizen

2857 October 17, 2011 A. Cone

Private Citizen

2858 October 17, 2011 A. Cone

Private Citizen

2859 October 17, 2011 J. Broadbent

Private Citizen

2860 October 17, 2011 S. Stoudemire

Private Citizen

2861 October 17, 2011 L. Patten

Private Citizen

2862 October 17, 2011 C. McVie

Private Citizen

2863 October 17, 2011 T. Nass

Private Citizen

2864 October 17, 2011 A. Young

Private Citizen

2865 October 17, 2011 L. Weinberg

Private Citizen

2866 October 17, 2011 Dr. L. Riebel

Private Citizen
556

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2867 October 17, 2011 P. Ayres

Private Citizen

2868 October 17, 2011 L. Taylor

Private Citizen

2869 October 17, 2011 E. Dehuff

Private Citizen

2870 October 17, 2011 E. Waldow

Private Citizen

2871 October 17, 2011 G. Ross

Private Citizen

2872 October 17, 2011 S. Pomeroy

Private Citizen

2873 October 17, 2011 O. Tice

Private Citizen

2874 October 17, 2011 J. Schall

Private Citizen

2875 October 17, 2011 M. Smither

Private Citizen

2876 October 17, 2011 M. Puett

Private Citizen

2877 October 17, 2011 J. Cooper

Private Citizen

2878 October 17, 2011 J. Pelton

Private Citizen

2879 October 17, 2011 M. Wendorf

Private Citizen

2880 October 17, 2011 W. Lachman

Private Citizen

2881 October 17, 2011 N. Werne

Private Citizen

2882 October 17, 2011 Dr. D. Snyder

Private Citizen

2883 October 17, 2011 N. Kasper

Private Citizen

2884 October 17, 2011 L. Pearson

Private Citizen

2885 October 17, 2011 Dr. E. Riser-Roberts

Private Citizen

2886 October 17, 2011 Dr. R. Meierotto

Private Citizen

2887 October 17, 2011 J. Bennett

Private Citizen

2888 October 17, 2011 F. Werner

Private Citizen

2889 October 17, 2011 Dr. C. Mullin

Private Citizen
557

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2890 October 17, 2011 M. H. Stephens

Private Citizen

2891 October 17, 2011 S. Parsons

Private Citizen

2892 October 17, 2011 D. Jordan

Private Citizen

2893 October 17, 2011 D. Scacciaferro

Private Citizen

2894 October 17, 2011 V. Richards-Taylor

Private Citizen

2895 October 17, 2011 C. Shermer

Private Citizen

2896 October 17, 2011 K. Williams

Private Citizen

2897 October 17, 2011 T. Follett

Private Citizen

2898 October 17, 2011 W. P. Abrams

Private Citizen

2899 October 17, 2011 R. Allen

Private Citizen

2900 October 17, 2011 C. Seibold

Private Citizen

2901 October 17, 2011 A. Botwin

Private Citizen

2902 October 17, 2011 J. Shuttleworth

Private Citizen

2903 October 17, 2011 L. J. Solomon

Private Citizen

2904 October 17, 2011 Dr. M. Campbell

Private Citizen

2905 October 17, 2011 L. Landsverk

Private Citizen

2906 October 18, 2011 L. Peck

Private Citizen

2907 October 17, 2011 G. Zidbeck

Private Citizen

2908 October 18, 2011 A. Presler

Private Citizen

2909 October 17, 2011 D. Giles

Private Citizen

2910 October 17, 2011 A. Brownstein

Private Citizen

2911 October 17, 2011 H. Whitfield

Private Citizen

2912 October 17, 2011 Dr. L. Stein

Private Citizen
558

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2913 October 18, 2011 C. McCann

Private Citizen

2914 October 17, 2011 E. Omalley

Private Citizen

2915 October 17, 2011 S. Lyon

Private Citizen

2916 October 17, 2011 L. Overbey

Private Citizen

2917 October 18, 2011 Dr. T. Ettinger

Private Citizen

2918 October 17, 2011 Dr. K. Comess

Private Citizen

2919 October 17, 2011 D. Wasko

Private Citizen

2920 October 17, 2011 C. Weston

Private Citizen

2921 October 17, 2011 R. Thompson

Private Citizen

2922 October 17, 2011 R. Koos

Private Citizen

2923 October 17, 2011 Dr. D. Wirth

Private Citizen

2924 October 17, 2011 S. Lores

Private Citizen

2925 October 17, 2011 S. Clark

Private Citizen

2926 October 17, 2011 H. Schlaff

Private Citizen

2927 October 17, 2011 G. Cooper Jr.

Private Citizen

2928 October 17, 2011 M. A. Hawxhurst

Private Citizen

2929 October 17, 2011 E. Greisch

Private Citizen

2930 October 18, 2011 J. Urbanas

Private Citizen

2931 October 18, 2011 R. Rodriguez

Private Citizen

2932 October 18, 2011 Dr. M. Rudnick

Private Citizen

2933 October 18, 2011 S. Clay

Private Citizen

2934 October 18, 2011 D. Johnson

Private Citizen

2935 October 18, 2011 J. Amos

Private Citizen
559

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2936 October 18, 2011 Dr. G. Marsh

Private Citizen

2937 October 17, 2011 A. Schneider

Private Citizen

2938 October 17, 2011 T. Milligan

Private Citizen

2939 October 17, 2011 E. Davidson

Private Citizen

2940 October 17, 2011 N. Casale

Private Citizen

2941 October 17, 2011 B. George

Private Citizen

2942 October 17, 2011 Dr. G. Thomsen

Private Citizen

2943 October 17, 2011 N. Zorn

Private Citizen

2944 October 18, 2011 D. Magrina

Private Citizen

2945 October 18, 2011 S. Stauffer

Private Citizen

2946 October 18, 2011 T. Tweedale

2947 October 18, 2011 Anonymous public comment

2948 October 18, 2011 SRF (initials only provided)

Private Citizen

2949 October 16, 2011 S. Logan

Private Citizen

2950 October 16, 2011 P. Orthwein

Private Citizen

2951 October 16, 2011 Anonymous public comment

2952 October 15, 2011 D. Komlosy

Private Citizen

2953 October 16, 2011 D. West

Private Citizen

2954 October 17, 2011 J. Dortch

Private Citizen

2955 October 16, 2011 W. Dent

Private Citizen

2956 October 16, 2011 A. Leimanis

Private Citizen

2957 October 16, 2011 E. Rencher

Private Citizen

2958 October 17, 2011 C. Deveny

Private Citizen

2959 October 17, 2011 D. Hammang

Private Citizen
560

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2960 October 17, 2011 E. Jacobson

Private Citizen

2961 October 17, 2011 C. Hunt

Private Citizen

2962 October 17, 2011 J. Fletcher

Private Citizen

2963 October 17, 2011 T. Richman

Private Citizen

2964 October 17, 2011 G. Crouse

Private Citizen

2965 October 18, 2011 J. Thacker

Private Citizen

2966 October 18, 2011 B. Michalski

Private Citizen

2967 October 17, 2011 M. Trifon

Private Citizen

2968 October 18, 2011 T. Heislen

Private Citizen

2969 October 18, 2011 J. Gau

Private Citizen

2970 October 18, 2011 A. Lynch

Private Citizen

2971 October 18, 2011 G. Nicholson

Private Citizen

2972 October 18, 2011 R. Collins

Private Citizen

2973 October 18, 2011 T. Wargo

Private Citizen

2974 October 18, 2011 T. Heywood

Private Citizen

2975 October 18, 2011 J. Kauth

Private Citizen

2976 October 18, 2011 M. Bailey

Private Citizen

2977 October 18, 2011 L. Kauffman

Private Citizen

2978 October 18, 2011 M. Broughton

Private Citizen

2979 October 17, 2011 A. Smith

Private Citizen

2980 October 17, 2011 C. Marson

Private Citizen

2981 October 18, 2011 L. Cook

Private Citizen

2982 October 18, 2011 K. O'Connell

Private Citizen
561

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

2983 October 18, 2011 J. Reel

Private Citizen

2984 October 18, 2011 C. Meeker

Private Citizen

2985 October 18, 2011 Dr. W. Loftus

Private Citizen

2986 October 18, 2011 L. Healy

Private Citizen

2987 October 18, 2011 N. Petersen

Private Citizen

2988 October 18, 2011 A. Cash

Private Citizen

2989 October 18, 2011 B. Pittenger

Private Citizen

2990 October 18, 2011 J. Dinkmeyer

Private Citizen

2991 October 18, 2011 F. Lurz

Private Citizen

2992 October 18, 2011 L. Gerard

Private Citizen

2993 October 18, 2011 E. Van den Bossche

Private Citizen

2994 October 18, 2011 J. Durfee

Private Citizen

2995 October 18, 2011 H. Schulze

Private Citizen

2996 October 18, 2011 T. O'Neill

Private Citizen

2997 October 18, 2011 H. Carr

Private Citizen

2998 October 18, 2011 F. Hammer

Private Citizen

2999 October 18, 2011 P. Meyers

Private Citizen

3000 October 18, 2011 S. Baird

Private Citizen

3001 October 18, 2011 C. Schneider

Private Citizen

3002 October 18, 2011 K. Noaker

Private Citizen

3003 October 18, 2011 R. Schneider

Private Citizen

3004 October 18, 2011 K. Johnson

Private Citizen

3005 October 18, 2011 Dr. T. Jiunta

Private Citizen
562

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3006 October 18, 2011 J. Stephen

Private Citizen

3007 October 18, 2011 T. O. Nass

Private Citizen

3008 October 18, 2011 K. Armstrong

Private Citizen

3009 October 18, 2011 E. Vaughn

Private Citizen

3010 October 18, 2011 J. Schultes

Private Citizen

3011 October 18, 2011 T. MacKenzie

Private Citizen

3012 October 18, 2011 J. Young

Private Citizen

3013 October 18, 2011 R. Harris

Private Citizen

3014 October 18, 2011 T. Calliope

Private Citizen

3015 October 18, 2011 T. Keane

Private Citizen

3016 October 18, 2011 G. and F. Alderson

Private Citizens

3017 October 18, 2011 J. Pearson

Private Citizen

3018 October 18, 2011 L. Larason

Private Citizen

3019 October 18, 2011 R. Reed

Private Citizen

3020 October 18, 2011 L. Yarbrough

Private Citizen

3021 October 18, 2011 R. Tonachel

Private Citizen

3022 October 18, 2011 A. McNeill

Private Citizen

3023 October 18, 2011 J. Matthews

Private Citizen

3024 October 18, 2011 S. Alex

Private Citizen

3025 October 18, 2011 W. Griffith

Private Citizen

3026 October 18, 2011 F. Rao

Private Citizen

3027 October 18, 2011 E. Daniels

Private Citizen

3028 October 19, 2011 K. Foley

Private Citizen
563

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3029 October 19, 2011 B. Friedman

Private Citizen

3030 October 18, 2011 F. Schilling

Private Citizen

3031 October 18, 2011 B. McHenry

Private Citizen

3032 October 18, 2011 J. Briones

Private Citizen

3033 October 18, 2011 L. A. Pizzolon

Private Citizen

3034 October 18, 2011 J. Lynn

Private Citizen

3035 October 19, 2011 A. Jennings

Private Citizen

3036 October 19, 2011 P. Langford

Private Citizen

3037 October 17, 2011 B. Dahms

Private Citizen

3038 October 18, 2011 J. Hicks

Private Citizen

3039 October 18, 2011 A. Savett

Private Citizen

3040 October 18, 2011 S. Eastman

Private Citizen

3041 October 18, 2011 J. Wilson

Private Citizen

3042 October 18, 2011 S. DenBraber

Private Citizen

3043 October 18, 2011 Dr. J. Witte

Private Citizen

3044 October 18, 2011 R. Shorin

Private Citizen

3045 October 18, 2011 J. Horkulic

Private Citizen

3046 October 18, 2011 C. Fischer

Private Citizen

3047 October 18, 2011 M. Martin

Private Citizen

3048 October 18, 2011 L. Salter

Private Citizen

3049 October 18, 2011 T. White

Private Citizen

3050 October 18, 2011 B. Breckenridge

Private Citizen

3051 October 18, 2011 P. Gudava

Private Citizen
564

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3052 October 18, 2011 G. Gomez

Private Citizen

3053 October 18, 2011 R. Hoover

Private Citizen

3054 October 18, 2011 M. Wagner

Private Citizen

3055 October 18, 2011 L. Horowitz

Private Citizen

3056 October 18, 2011 L. Winslow

Private Citizen

3057 October 18, 2011 D. Young

Private Citizen

3058 October 18, 2011 E. Wedlock

Private Citizen

3059 October 19, 2011 C. Reom

Private Citizen

3060 October 19, 2011 K. R. Pence

Private Citizen

3061 October 19, 2011 E. Barry

Private Citizen

3062 October 19, 2011 N. Roberts

Private Citizen

3063 October 18, 2011 D. Stutzenburg

Private Citizen

3064 October 18, 2011 E. Polesny

Private Citizen

3065 October 18, 2011 P. Schramm

Private Citizen

3066 October 18, 2011 M. Freeland

Private Citizen

3067 October 18, 2011 J. Flatt

Private Citizen

3068 October 18, 2011 R. Sandefur

Private Citizen

3069 October 18, 2011 S. Altman

Private Citizen

3070 October 19, 2011 K. Newman

Private Citizen

3071 October 19, 2011 L. Hollings

Private Citizen

3072 October 19, 2011 Susan B.

Private Citizen

3073 October 19, 2011 G. Monroe

Private Citizen

3074 October 19, 2011 H. Dunn

Private Citizen
565

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3075 October 18, 2011 Dr. M. Mehdy

Private Citizen

3076 October 18, 2011 W. Reed

Private Citizen

3077 October 18, 2011 R. Lichty

Private Citizen

3078 October 18, 2011 G. and J. Richardson

Private Citizen

3079 October 18, 2011 D. Jentgen

Private Citizen

3080 October 18, 2011 S. Sherman

Private Citizen

3081 October 18, 2011 S. Ambler

Private Citizen

3082 October 18, 2011 J. Feulner

Private Citizen

3083 October 18, 2011 G. Adams

Private Citizen

3084 October 18, 2011 B. Hameister

Private Citizen

3085 October 18, 2011 M. Magruder

Private Citizen

3086 October 18, 2011 T. Anglim

Private Citizen

3087 October 18, 2011 P. Helm

Private Citizen

3088 October 18, 2011 B. Green

Private Citizen

3089 October 18, 2011 J. Corcoran

Private Citizen

3090 October 18, 2011 S. Selbin

Private Citizen

3091 October 18, 2011 M. Pratt

Private Citizen

3092 October 19, 2011 J. Cleghorn

Private Citizen

3093 October 19, 2011 K. Yearsley

Private Citizen

3094 October 19, 2011 J. K. Miller

Private Citizen

3095 October 19, 2011 J. Porter

Private Citizen

3096 October 18, 2011 D. Collis

Private Citizen

3097 October 18, 2011 D. Hawley

Private Citizen
566

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3098 October 18, 2011 J. Archuleta

Private Citizen

3099 October 18, 2011 L. Jolliffe

Private Citizen

3100 October 18, 2011 P. Mechow

Private Citizen

3101 October 18, 2011 L. Wimberly

Private Citizen

3102 October 18, 2011 G. Casey

Private Citizen

3103 October 19, 2011 S. Fitzpatrick

Private Citizen

3104 October 19, 2011 T. Armao

Private Citizen

3105 October 19, 2011 M. Merold

Private Citizen

3107 October 18, 2011 D. Williams

Private Citizen

3108 October 18, 2011 T. Palmer

Private Citizen

3109 October 18, 2011 W. Fast

Private Citizen

3110 October 18, 2011 L. Bartell

Private Citizen

3111 October 18, 2011 E. Bonzo-Savage

Private Citizen

3112 October 19, 2011 S. DeRosa

Private Citizen

3113 October 19, 2011 J. Roelof

Private Citizen

3114 October 19, 2011 R. Downing

Private Citizen

3115 October 19, 2011 C. Simon

Private Citizen

3116 October 19, 2011 P. Ghenoiu

Private Citizen

3117 October 19, 2011 R. Langworthy

Private Citizen

3118 October 18, 2011 K. Ash

Private Citizen

3119 October 18, 2011 S. Christenson

Private Citizen

3120 October 18, 2011 D. Winkel

Private Citizen

3121 October 18, 2011 P. Elliott

Private Citizen
567

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3122 October 18, 2011 G. Holden

Private Citizen

3123 October 18, 2011 B. Brinker

Private Citizen

3124 October 19, 2011 N. Gannon

Private Citizen

3125 October 19, 2011 A. Carissimi

Private Citizen

3126 October 19, 2011 F. Schwartzwald

Private Citizen

3127 October 19, 2011 S. Serafin

Private Citizen

3128 October 19, 2011 W. Quinn

Private Citizen

3129 October 19, 2011 H. Alto

Private Citizen

3130 October 19, 2011 S. McGuire

Private Citizen

3131 October 19, 2011 K. Richard

Private Citizen

3132 October 19, 2011 M. Nall

Private Citizen

3133 October 19, 2011 R. Mihaly

Private Citizen

3134 October 19, 2011 F. Whiteside

Private Citizen

3135 October 19, 2011 R. Smith

Private Citizen

3136 October 18, 2011 D. Janiak

Private Citizen

3137 October 18, 2011 J. Fontaine

Private Citizen

3138 October 18, 2011 J. Glenn

Private Citizen

3139 October 18, 2011 L. Dumey

Private Citizen

3140 October 18, 2011 C. Fotia

Private Citizen

3141 October 18, 2011 M. Hill

Private Citizen

3142 October 18, 2011 E. Jamieson

Private Citizen

3143 October 19, 2011 S. Hoskin

Private Citizen

3144 October 19, 2011 M. Wellington

Private Citizen
568

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3145 October 18, 2011 B. Speidel

Private Citizen

3146 October 18, 2011 J. A. Hall

Private Citizen

3147 October 18, 2011 K. Schultes

Private Citizen

3148 October 18, 2011 Z. Henderson

Private Citizen

3149 October 18, 2011 V. Mosca-Clark

Private Citizen

3150 October 18, 2011 R. Kasan

Private Citizen

3151 October 19, 2011 M. Ferrero

Private Citizen

3152 October 18, 2011 H. Hanna

Private Citizen

3153 October 19, 2011 M. Lindsay

Private Citizen

3154 October 19, 2011 D. Addison

Private Citizen

3155 October 19, 2011 D. Fitzpatrick

Private Citizen

3156 October 19, 2011 J. Bogle

Private Citizen

3157 October 19, 2011 N. Gyetko

Private Citizen

3158 October 19, 2011 S. McNall

Private Citizen

3159 October 19, 2011 M. MacDonald

Private Citizen

3160 October 19, 2011 M. Metje

Private Citizen

3161 October 19, 2011 T. A. Hoffman

Private Citizen

3162 October 19, 2011 R. Siegfried

Private Citizen

3163 October 19, 2011 M. Wood

Private Citizen

3164 October 19, 2011 S. Morgan

Private Citizen

3165 October 19, 2011 D. Low

Private Citizen

3166 October 19, 2011 M. Cansler

Private Citizen

3167 October 19, 2011 C. Rieden

Private Citizen
569

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3168 October 18, 2011 J. Furlan

Private Citizen

3169 October 19, 2011 L. Wally

Private Citizen

3170 October 19, 2011 M. Ritter

Private Citizen

3171 October 18, 2011 M. O'Brien

Private Citizen

3172 October 18, 2011 T. Wilson

Private Citizen

3173 October 18, 2011 D. Waldron

Private Citizen

3174 October 19, 2011 R. Kingsbery

Private Citizen

3175 October 19, 2011 G. Macy

Private Citizen

3176 October 18, 2011 J. Furlan

Private Citizen

3177 October 19, 2011 R. Bonny

Private Citizen

3178 October 19, 2011 D. Artemis

Private Citizen

3179 October 19, 2011 M. Jameson

Private Citizen

3180 October 19, 2011 Anonymous public comment

3181 October 19, 2011 S. D'Onofrio

Private Citizen

3182 October 19, 2011 N. Gyetko

Private Citizen

3183 October 19, 2011 D. Luck

Private Citizen

3184 October 19, 2011 J. and S. Clewell

Private Citizens

3185 October 19, 2011 R. Scco

Private Citizen

3186 October 19, 2011 A. Birney

Private Citizen

3187 October 19, 2011 L. Towne

Private Citizen

3188 October 19, 2011 N. Weil

Private Citizen

3189 October 19, 2011 J. Iskowitz

Private Citizen

3190 October 19, 2011 R. Nelson

Private Citizen
570

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3191 October 19, 2011 C. Kuehnl and E. Burke

Private Citizens

3192 October 19, 2011 T. Herlache

Private Citizen

3193 October 19, 2011 B. Koehler

Private Citizen

3194 October 19, 2011 J. Elder

Private Citizen

3195 October 19, 2011 M. Lukasiewicz

Private Citizen

3196 October 19, 2011 K. Vogel

Private Citizen

3197 October 19, 2011 G. Deary

Private Citizen

3198 October 19, 2011 W. McMullin

Private Citizen

3199 October 19, 2011 J. Tache

Private Citizen

3200 October 19, 2011 N. Cubbage

Private Citizen

3201 October 19, 2011 K. Walsh

Private Citizen

3202 October 19, 2011 S. Plowman

Private Citizen

3203 October 19, 2011 P. Guthrie

Private Citizen

3204 October 19, 2011 M. Duran

Private Citizen

3205 October 19, 2011 J. Kinzie

Private Citizen

3206 October 18, 2011 R. Seaton

Private Citizen

3207 October 19, 2011 K. Gougler

Private Citizen

3208 October 19, 2011 T. Gilkyson

Private Citizen

3209 October 19, 2011 L. S. Gewiss

Private Citizen

3210 October 19, 2011 A. Shrestha

Private Citizen

3211 October 19, 2011 R. Chilcoat

Private Citizen

3212 October 18, 2011 L. Johnson

Private Citizen

3213 October 18, 2011 R. Sdano

Private Citizen
571

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3214 October 19, 2011 N. Septoff

Private Citizen

3215 October 19, 2011 R. Kofler

Private Citizen

3216 October 19, 2011 J. Shepherd

Private Citizen

3217 October 18, 2011 R. Gentry

Private Citizen

3218 October 18, 2011 J. Dart

Private Citizen

3219 October 18, 2011 T. Travis

Private Citizen

3220 October 18, 2011 M. Dillon

Private Citizen

3221 October 18, 2011 B. Newsome

Private Citizen

3222 October 19, 2011 Dr. L. Murray

Private Citizen

3223 October 19, 2011 J. McLane

Private Citizen

3224 October 18, 2011 R. Stanley

Private Citizen

3225 October 19, 2011 K. Peterson

Private Citizen

3226 October 19, 2011 A. Hamilton

Private Citizen

3227 October 19, 2011 C. J. Patterson

Private Citizen

3228 October 18, 2011 E. von Hoffmann

Private Citizen

3229 October 18, 2011 L. Ponist

Private Citizen

3230 October 19, 2011 W. Roberson

Private Citizen

3231 October 19, 2011 K. Bryan

Private Citizen

3232 October 19, 2011 M. Fish

Private Citizen

3233 October 19, 2011 L. Walsh

Private Citizen

3234 October 19, 2011 R. Umstattd

Private Citizen

3235 October 19, 2011 A. Michel

Private Citizen

3236 October 19, 2011 K. Gholson

Private Citizen
572

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3237 October 19, 2011 A. Lewis

Private Citizen

3238 October 19, 2011 M. Tolpin

Private Citizen

3239 October 19, 2011 Dr. E. Cole

Private Citizen

3240 October 19, 2011 S. Robinson

Private Citizen

3241 October 19, 2011 A. Malkin

Private Citizen

3242 October 19, 2011 N. Engelfried

Private Citizen

3243 October 19, 2011 Dr. P. Silveston

Private Citizen

3244 October 19, 2011 W. Daniel

Private Citizen

3245 October 19, 2011 R. Zucchi

Private Citizen

3246 October 19, 2011 R. Barker

Private Citizen

3247 October 19, 2011 L. and J. Patrie

Private Citizen

3248 October 18, 2011 J. Stevenson

Private Citizen

3249 October 18, 2011 E. Franzen

Private Citizen

3250 October 19, 2011 J. Trimarchi

Private Citizen

3251 October 19, 2011 E. Wolf

Private Citizen

3252 October 19, 2011 B. Casper

Private Citizen

3253 October 19, 2011 P. Rizzo

Private Citizen

3254 October 19, 2011 J. Broadbent

Private Citizen

3255 October 18, 2011 J. Botsko

Private Citizen

3256 October 18, 2011 S. Brady

Private Citizen

3257 October 18, 2011 E. Riebschlaeger, Sr.

Private Citizen

3258 October 19, 2011 A. Weber

Private Citizen

3259 October 19, 2011 D. Boylan

Private Citizen
573

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3260 October 19, 2011 M. Shimizu

Private Citizen

3261 October 19, 2011 J. Charrier

Private Citizen

3262 October 19, 2011 S. Jordan

Private Citizen

3263 October 19, 2011 J. Zarate

Private Citizen

3264 October 19, 2011 L. Parisi

Private Citizen

3265 October 20, 2011 S. Richardson

Private Citizen

3266 October 19, 2011 L. Anderson

Private Citizen

3267 October 19, 2011 S. Skrivanek

Private Citizen

3268 October 19, 2011 M. Birmingham

Private Citizen

3269 October 19, 2011 L. Vasquez

Private Citizen

3270 October 19, 2011 J. Archuleta

Private Citizen

3271 October 19, 2011 G. Gray

Private Citizen

3272 October 19, 2011 W. Davis

Private Citizen

3273 October 19, 2011 C. Wiley

Private Citizen

3274 October 19, 2011 J. Wiley

Private Citizen

3275 October 19, 2011 K. Smith

Private Citizen

3276 October 19, 2011 T. Nass

Private Citizen

3277 October 19, 2011 A. Smith

Private Citizen

3278 October 19, 2011 B. Qutizow

Private Citizen

3279 October 19, 2011 M. Stock

Private Citizen

3280 October 19, 2011 N. Gladfelter

Private Citizen

3281 October 19, 2011 G. Uransky

Private Citizen

3282 October 19, 2011 A. Douglass

Private Citizen
574

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3283 October 19, 2011 P. Braganza

Private Citizen

3284 October 19, 2011 G. Baruch

Private Citizen

3285 October 19, 2011 Dr. J. Weinstein

Private Citizen

3286 October 19, 2011 G. Theobald

Private Citizen

3287 October 19, 2011 K. Burroughs

Private Citizen

3288 October 19, 2011 K. Swistak

Private Citizen

3289 October 20, 2011 P. Brown

Private Citizen

3290 October 19, 2011 R. Placone

Private Citizen

3291 October 19, 2011 J. Hall

Private Citizen

3292 October 19, 2011 M. Pezzati

Private Citizen

3293 October 19, 2011 W. Schreier

Private Citizen

3294 October 19, 2011 A. Whitlock

Private Citizen

3295 October 19, 2011 R. Hosek

Private Citizen

3296 October 19, 2011 K. Rowlett

Private Citizen

3297 October 19, 2011 N. Gladfelter

Private Citizen

3298 October 20, 2011 S. Friedman

Private Citizen

3299 October 20, 2011 S. Toland

Private Citizen

3300 October 19, 2011 L. Villasenor

Private Citizen

3301 October 20, 2011 B. Schumacher

Private Citizen

3302 October 20, 2011 P. Luehrmann

Private Citizen

3303 October 20, 2011 D. Devo

Private Citizen

3304 October 20, 2011 K. Simoniki

Private Citizen

3305 October 20, 2011 V. Watson

Private Citizen
575

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3306 September 16, 2011 Mass Comment Campaign sponsoring organization 

unknown (12)

3307 September 16, 2011 Mass Comment Campaign sponsoring organization 

unknown (14)

3308 September 30, 2011 Mass Comment Campaign sponsoring organization 

unknown (27)

3309 October 14, 2011 National Wildlife Federation Action Fund 

mass comment campaign (17,787)

3310 October 18, 2011 Mass Comment Campaign sponsoring organization 

unknown (4,701)

3311 October 19, 2011 D. Kates

Private Citizen

3312 October 19, 2011 R. Hiers

Private Citizen

3313 October 19, 2011 C. Shermer

Private Citizen

3314 October 19, 2011 K. Randall

Private Citizen

3315 October 19, 2011 N. Benoit

Private Citizen

3316 October 19, 2011 T. Burdick

Private Citizen

3317 October 19, 2011 H. Kermath-Vick

Private Citizen

3318 October 19, 2011 P. Vellenga

Private Citizen

3319 October 19, 2011 N. Kolwey

Private Citizen

3320 October 19, 2011 B. Carter

Private Citizen

3321 October 19, 2011 L. Wallin

Private Citizen

3322 October 19, 2011 C. Miller

Private Citizen

3323 October 19, 2011 Dr. D. Shoemaker

Private Citizen

3324 October 19, 2011 J. Chase

Private Citizen

3325 October 19, 2011 N. Bennett

Private Citizen

3326 October 19, 2011 L. Stevens

Private Citizen

3327 October 19, 2011 M. Roam

Private Citizen

3328 October 19, 2011 P. Gallenkamp

Private Citizen
576

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3329 October 19, 2011 J. Capozzelli

Private Citizen

3330 October 19, 2011 D. Spremulli

Private Citizen

3331 October 19, 2011 J. Dinkmeyer

Private Citizen

3332 October 19, 2011 K. Saunders

Private Citizen

3333 October 19, 2011 A. Liberman

Private Citizen

3334 October 19, 2011 D. Malone

Private Citizen

3335 October 19, 2011 Dr. L. Jaffee

Private Citizen

3336 October 19, 2011 S. Sparks

Private Citizen

3337 October 19, 2011 D. Mynott

Private Citizen

3338 October 19, 2011 C. Turner

Private Citizen

3339 October 20, 2011 T. Sheridan

Private Citizen

3340 October 19, 2011 G. Scott Clemson

Private Citizen

3341 October 19, 2011 T. Kline

Private Citizen

3342 October 19, 2011 C. Pisoni

Private Citizen

3343 October 20, 2011 L. Stough

Private Citizen

3344 October 20, 2011 D. and T. Herron

Private Citizens

3345 October 20, 2011 C. Burritt

Private Citizen

3346 October 20, 2011 J. Boylston

Private Citizen

3347 October 19, 2011 P. Russell

Private Citizen

3348 October 19, 2011 L. Hanratty

Private Citizen

3349 October 19, 2011 E. Stark

3350 October 20, 2011 Adam Peshek

Reason Foundation

Robin Millican

Institute for Energy Research
577

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3351 October 20, 2011 David L. Klemp

Montana Dept. of Environmental Quality

3352 October 19, 2011 W. Elton

Private Citizen

3353 October 20, 2011 R. Dreesman

Private Citizen

3354 October 20, 2011 R. Couston

Private Citizen

3355 October 20, 2011 S. Rice

Private Citizen

3356 October 20, 2011 G. Hart

Private Citizen

3357 October 20, 2011 S. Forrest

Private Citizen

3358 October 20, 2011 M. Wood

Private Citizen

3359 October 20, 2011 J. Gillette

Private Citizen

3360 October 20, 2011 A. Septoff

Private Citizen

3361 October 20, 2011 D. Ryder

Private Citizen

3362 October 20, 2011 Y. Ruben

Private Citizen

3363 October 20, 2011 B. Stearns

Private Citizen

3364 October 20, 2011 D. Deloff

Private Citizen

3365 October 20, 2011 C. Johnson

Private Citizen

3366 October 20, 2011 S. Barrett

Private Citizen

3367 October 20, 2011 J. Nickels

Private Citizen

3368 October 20, 2011 J. Farah

Private Citizen

3369 October 20, 2011 C. Westhaver

Private Citizen

3370 October 20, 2011 D. Thomas

Private Citizen

3371 October 20, 2011 D. Lindsay

Private Citizen

3372 October 20, 2011 D. Royle

Private Citizen

3373 October 20, 2011 B. Nesmith

Private Citizen
578

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3374 October 20, 2011 K. Kron

Private Citizen

3375 October 20, 2011 P. Johnson

Private Citizen

3376 October 21, 2011 S. White

Private Citizen

3377 October 21, 2011 R. Gaebe

Private Citizen

3378 October 21, 2011 W. Bernard

Private Citizen

3379 October 21, 2011 B. Trentlyon

Private Citizen

3380 October 21, 2011 D. Goodman

Private Citizen

3381 October 21, 2011 P. Stocker

Private Citizen

3382 October 21, 2011 C. Tillotson

Private Citizen

3383 October 21, 2011 J. Hodie

Private Citizen

3384 October 21, 2011 B. Bennett

Private Citizen

3385 October 20, 2011 A. Beath

Private Citizen

3386 October 21, 2011 T. Giesy

Private Citizen

3387 October 21, 2011 K. O'Neill

Private Citizen

3388 October 21, 2011 S. Bratcher

Private Citizen

3389 October 21, 2011 A. Ross

Private Citizen

3390 October 21, 2011 A. Ryan

Private Citizen

3391 October 21, 2011 C. Hall

Private Citizen

3392 October 21, 2011 J. Leonard

Private Citizen

3393 October 21, 2011 K. Coventry

Private Citizen

3394 October 21, 2011 E. Walters

Private Citizen

3395 October 21, 2011 M. Strawn

Private Citizen

3396 October 21, 2011 D. Beckwith

Private Citizen
579

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3397 October 21, 2011 M. Barr

Private Citizen

3398 October 23, 2011 Anonymous public comment

3399 October 20, 2011 Chelsa Wagner, 

Representative 22nd District 

PA House of Representatives

3400 October 17, 2011 Truschel (no first name provided)

Private Citizen

3401 October 23, 2011 C. Lish

Private Citizen

3402 October 21, 2011 G. Amalfitano

Private Citizen

3403 October 21, 2011 D. Hammes

Private Citizen

3404 October 21, 2011 Z. Kerr

Private Citizen

3405 October 21, 2011 E. Saunders

Private Citizen

3406 October 24, 2011 J. McLaughlin

Private Citizen

3407 October 24, 2011 Anonymous public comment

3408 October 24, 2011 Christine Griffin

Smithfield Township

3409 October 24, 2011 Vera Scroggins

Citizens For Clean Water

3410 October 24, 2011 L. T. Atkinson

Private Citizen

3411 October 21, 2011 M. Osipchuk

Private Citizen

3412 October 21, 2011 N. Miller

Private Citizen

3413 October 21, 2011 P. Lesica

Private Citizen

3414 October 21, 2011 D. Douglas

Private Citizen

3415 October 21, 2011 K. Manning

Private Citizen

3416 October 21, 2011 S. Kee

Private Citizen

3417 October 24, 2011 D. Decker

Private Citizen

3418 October 24, 2011 Anonymous public comment

3419 October 21, 2011 N. Sprecher

Private Citizen

3420 October 22, 2011 R. Leibowitz

Private Citizen
580

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3421 October 22, 2011 C. Hubel

Private Citizen

3422 October 22, 2011 R. Ciao

Private Citizen

3423 October 22, 2011 J. Forbes

Private Citizen

3424 October 22, 2011 T. Miller

Private Citizen

3425 October 22, 2011 M. Enk

Private Citizen

3426 October 22, 2011 A. Pereau

Private Citizen

3427 October 22, 2011 L. Isbell

Private Citizen

3428 October 22, 2011 S. van der Voort

Private Citizen

3429 October 24, 2011 E. Brown

Private Citizen

3430 October 24, 2011 G. Giacomantonio

Private Citizen

3431 October 24, 2011 T. Gough

Private Citizen

3432 October 24, 2011 K. Feridun

Private Citizen

3433 October 24, 2011 Anonymous public comment

3434 October 24, 2011 B. Shields

Private Citizen

3435 October 24, 2011 D. Samardjian

Private Citizen

3436 October 24, 2011 L. S. Abra

Private Citizen

3437 October 22, 2011 K. Beel

Private Citizen

3438 October 22, 2011 K. Sendall

Private Citizen

3439 October 22, 2011 S. McNeil

Private Citizen

3440 October 22, 2011 P. Williams

Private Citizen

3441 October 22, 2011 J. Peascoe

Private Citizen

3442 October 22, 2011 S. Hughes

Private Citizen

3443 October 22, 2011 B. Schmitt

Private Citizen
581

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3444 October 22, 2011 E. Bartlett

Private Citizen

3445 October 23, 2011 L. Monkemeyer

Private Citizen

3446 October 23, 2011 J. Goodwin

Private Citizen

3447 October 24, 2011 Brad Richards

Illinois Oil & Gas Association

3448 October 24, 2011 C. Gagnon

Private Citizen

3449 October 24, 2011 R. Nash

Private Citizen

3450 October 24, 2011 M. Torchio

Private Citizen

3451 October 24, 2011 E. Brown

Private Citizen

3452 October 24, 2011 L. Hasselberger

Private Citizen

3453 October 24, 2011 Anonymous public comment

3454 October 24, 2011 Veronica Nasser

REM Technology

3455 October 22, 2011 G. and J. Hearne

Private Citizens

3456 October 21, 2011 Patrick Dowd

Member of Council

City of Pittsburgh, Pennsylvania

3457 October 24, 2011 Anonymous public comment

3458 October 24, 2011 Anonymous public comment

3459 October 20, 2011 Lon Burnam, State Representative 

House District 90

Fort Worth, Texas

3460 October 24, 2011 Phyllis Mundy

Pennsylvania House of Representatives

3461 October 24, 2011 Anonymous public comment

3462 October 24, 2011 T. Farm, Jr.

Private Citizen

3463 October 24, 2011 C. Cubas

Private Citizen

3464 October 24, 2011 A. Lane

Private Citizen

3465 October 24, 2011 E. Lane

Private Citizen

3466 October 21, 2011 Camille "Bud" George

State Representative

Commonwealth of PA
582

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3467 October 24, 2011 John K. Baillie

Citizens for Pennsylvania's Future

3468 October 24, 2011 Frank L. Lindsey

Indiana Oil and Gas Association

3469 October 24, 2011 Randall R. LaBauve

NextEra Energy, Inc.

3470 October 24, 2011 Denny Larson

Global Community Monitor et al

3471 October 24, 2011 T. Korinek

Private Citizen

3472 October 25, 2011 B. Coyne

Private Citizen

3473 October 25, 2011 Eugene A. Depasquale

State Representative, 95th Legislative District

House of Representatives, PA, Harrisburg

3474 October 24, 2011 Andrew Browning

Consumer Energy Alliance 

3475 October 24, 2011 Barry T. Smitherman

Railroad Commission of Texas

3476 October 24, 2011 Frank I. Lindsey

CountryMark Energy Resources, LLC

3477 October 25, 2011 Alby Modiano

US Oil & Gas Association

3478 October 24, 2011 Members of the Pennsylvania House of 

Representatives

3479 October 23, 2011 M. Gallagher

Private Citizen

3480 October 23, 2011 S. Forde

Private Citizen

3481 October 23, 2011 M. Mack

Private Citizen

3482 October 23, 2011 M. Decker

Private Citizen

3483 October 23, 2011 S. Barchas

Private Citizen

3484 October 23, 2011 L. Carroll

Private Citizen

3485 October 23, 2011 E. Miniscalco

Private Citizen

3486 October 23, 2011 L. Carroll

Private Citizen

3487 October 23, 2011 Anonymous public comment

3488 October 23, 2011 N. Rapp

Private Citizen

3489 October 23, 2011 M. and J. Gatlin

Private Citizens
583

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3490 October 23, 2011 J. Eisnaugle

Private Citizen

3491 October 24, 2011 P. Palthe

Private Citizen

3492 October 24, 2011 Bill Belitskus

Allegheny Defense Project

3493 October 24, 2011 D. Emard

Private Citizen

3494 October 24, 2011 N. Ross

Private Citizen

3495 October 24, 2011 Charles E. Smith

Countrymark Cooperative Holding Corp.

3496 October 24, 2011 John (no surname provided)

Private Citizen

3497 October 24, 2011 S. P. Kearns

Private Citizen

3498 October 24, 2011 B. Bean

Private Citizen

3499 October 24, 2011 L. Dimin

Private Citizen

3500 October 25, 2011 T. Billel

Private Citizen

3501 October 26, 2011 E. McRae

Private Citizen

3502 October 26, 2011 A. Hemenway

Private Citizen

3503 October 24, 2011 J. Edgar

Private Citizen

3504 October 24, 2011 J. Allen

Private Citizen

3505 October 24, 2011 L. Atkinson

Private Citizen

3506 October 24, 2011 A. Walker

Private Citizen

3507 October 24, 2011 G. Sieg

Private Citizen

3508 October 24, 2011 J. Pope

Private Citizen

3509 October 24, 2011 P. Fellows

Private Citizen

3510 October 24, 2011 C. Feinberg

Private Citizen

3511 October 24, 2011 A. Sisenstein

Private Citizen

3512 October 24, 2011 W. Ernsberger

Private Citizen
584

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3513 October 24, 2011 G. Wiley

Private Citizen

3514 October 24, 2011 W. Sieg

Private Citizen

3515 October 24, 2011 J. Morgan

Private Citizen

3516 October 24, 2011 T. Lam

Private Citizen

3517 October 24, 2011 A. and R. Cross

Private Citizens

3518 October 24, 2011 Anonymous public comment

3519 October 24, 2011 L. Thompson

Private Citizen

3520 October 24, 2011 P. Hackley

Private Citizen

3521 October 24, 2011 Anonymous public comment

3522 October 24, 2011 J. Wagner

Private Citizen

3523 October 24, 2011 J. Edgar

Private Citizen

3524 October 24, 2011 Anonymous public comment

3525 October 25, 2011 D. Moderacki

Private Citizen

3526 October 25, 2011 D. Whitfield

Private Citizen

3527 October 24, 2011 Veronica Nasser

REM Technology

3528 October 24, 2011 Steven G. Folk

Red Willow Production Company, LLC

3529 October 25, 2011 Scott C. Blauvelt

East Management Services, LP 

3530 October 27, 2011 Anonymous Public Comment

3531 October 19, 2011 Clear Air Council mass comment campaign (237)

3532 October 19, 2011 PennEnvironment mass comment campaign (3,879)

3534 October 27, 2011 K. Theden

Private Citizen

3535 October 28, 2011 P. Roberts

Private Citizen

3536 October 26, 2011 K. Murphy

Private Citizen

3537 October 26, 2011 B. Fleming

Private Citizen

3538 October 26, 2011 J. Mitchem

Private Citizen
585

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3539 October 27, 2011 T. Robinson

Private Citizen

3540 October 27, 2011 M. Scott

Private Citizen

3541 October 27, 2011 S. Asmus

Private Citizen

3542 October 27, 2011 J. Marvin

Private Citizen

3543 October 27, 2011 A. Rutledge and D. Leverenz

Private Citizens

3544 October 27, 2011 N. Monaco

Private Citizen

3545 October 27, 2011 G. Pais

Private Citizen

3546 October 28, 2011 M. Lauver

Private Citizen

3547 October 28, 2011 D. Furry

Private Citizen

3548 October 29, 2011 J. Stugrin

Private Citizen

3549 October 24, 2011 A. Amonette

Private Citizen

3550 October 27, 2011 G. K. Neustadt

Private Citizen

3551 October 27, 2011 Cathy Purves

Trout Unlimited

3552 October 22, 2011 Michelle Naccarati-Chapkis

Women for a Healthy Environment

3553 October 28, 2011 P. Hodgson

Private Citizen

3554 October 28, 2011 E. Francis

Private Citizen

3555 October 29, 2011 D. Wiseman

Private Citizen

3556 October 29, 2011 A. Steiner

Private Citizen

3557 October 30, 2011 E. Scherzer

Private Citizen

3558 October 30, 2011 M. Breton

Private Citizen

3559 October 31, 2011 E. Hiedeman

Private Citizen

3560 October 31, 2011 Steve Henke

New Mexico Oil and Gas Association

3561 October 27, 2011 Mass Comment Campaign sponsoring organization 

unknown (420)
586

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3562 October 20, 2011 Johns S. Lyons

Division for Air Quality, Department for 

Environmental Protection, Energy and Environment 

Cabinet, Commonwealth of Kentucky

3563 October 24, 2011 A. Gwartney

Private Citizen

3564 October 24, 2011 J. Archuleta

Private Citizen

3565 October 24, 2011 M. Darilek

Private Citizen

3566 October 24, 2011 S. Seibert

Private Citizen

3567 October 24, 2011 T. Priselac

Private Citizen

3568 October 24, 2011 S. Laase

Private Citizen

3569 October 24, 2011 W. Johnson

Private Citizen

3570 October 24, 2011 W. Palmquist

Private Citizen

3571 October 24, 2011 A. Pickering

Private Citizen

3572 October 24, 2011 R. Stambaugh

Private Citizen

3573 October 24, 2011 J. Humphrey

Private Citizen

3574 October 24, 2011 M. Lanskey

Private Citizen

3575 October 24, 2011 S. Two Bears

Private Citizen

3576 October 24, 2011 K. Richter

Private Citizen

3577 October 24, 2011 C. Holmgren

Private Citizen

3578 October 24, 2011 P. Neola

Private Citizen

3579 October 24, 2011 G. Blake

Private Citizen

3580 October 24, 2011 Ty (no surname provided)

Private Citizen

3581 October 24, 2011 J. Hoggard

Private Citizen

3582 November 2, 2011 N. Valdez
587

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3583 November 1, 2011 Senator James Ferlo

38th District

Senate of 

Pennsylvania

3584 November 24, 2011 L. Barnes

Private Citizen

3585 October 24, 2011 J. Charvat

Private Citizen

3586 October 24, 2011 B. Sabo

Private Citizen

3587 October 24, 2011 L. Edwards

Private Citizen

3588 October 24, 2011 B. Bean

Private Citizen

3589 October 21, 2011 J. and T. Greenwald

Private Citizens

3590 October 24, 2011 E. Bentley

Private Citizen

3591 October 24, 2011 S. Zevian

Private Citizen

3592 October 24, 2011 C. Louwsma

Private Citizen

3593 October 31, 2011 Mass Comment Campaign sponsoring organization 

unknown (916)

3594 October 27, 2011 C. Franklin

Private Citizen

3595 October 27, 2011 L. Cooper

Private Citizen

3596 October 27, 2011 S. Sharp

Private Citizen

3597 October 27, 2011 V. Schulman

Private Citizen

3598 October 28, 2011 M. Houghton

Private Citizen

3599 October 28, 2011 S. Teal

Private Citizen

3600 October 28, 2011 A. Swanson

Private Citizen

3601 November 24, 2011 C. Kramer

Private Citizen

3602 October 24, 2011 T. Imajo

Private Citizen

3603 October 24, 2011 S. Gale

Private Citizen

3604 October 31, 2011 B. Blakney

Private Citizen
588

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3605 October 31, 2011 K. McMahen

Private Citizen

3606 October 24, 2011 K. Lynch

Private Citizen

3607 October 25, 2011 M. Shapiro

Private Citizen

3608 October 25, 2011 C. Ascher

Private Citizen

3609 October 25, 2011 L. Tedder

Private Citizen

3610 October 25, 2011 G. and L. Schwaller

Private Citizen

3611 October 25, 2011 T. Dubarr

Private Citizen

3612 October 31, 2011 S. Westervelt

Private Citizen

3613 October 31, 2011 L. Sturm

Private Citizen

3614 October 31, 2011 G. Richcreek

Private Citizen

3615 October 27, 2011 S. Jaillet

Private Citizen

3616 October 25, 2011 B. Gudac

Private Citizen

3617 October 25, 2011 P. Priest

Private Citizen

3618 November 3, 2011 Mark Burroughs

North Texas Clean Air Steering Committee 

3619 November 3, 2011 Mark Burroughs and Jungus Jordan

North Texas Clean Air Steering Committee

3620 October 29, 2011 J. Stugrin and M. Troisi

Private Citizens

3621 October 31, 2011 S. Roth

Private Citizen

3622 October 31, 2011 L. Kain

Private Citizen

3623 October 31, 2011 L. and D. Padilla

Private Citizens

3624 November 1, 2011 Claire (no surname provided)

Private Citizen

3625 November 2, 2011 R. Brewer

Private Citizen

3626 October 31, 2011 B. McClain

Private Citizen

3627 November 2, 2011 J. Josie

Private Citizen
589

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3628 November 3, 2011 B. Vinson

Private Citizen

3629 November 5, 2011 C. Schoen

Private Citizen

3630 November 6, 2011 L. Butler

Private Citizen

3631 November 8, 2011 Anonymous public comment

3632 November 8, 2011 A. Badami

Private Citizen

3633 November 9, 2011 B. Mills

Private Citizen

3634 November 9, 2011 H. Albaugh

Private Citizen

3635 November 9, 2011 J. Bridy

Private Citizen

3636 November 9, 2011 G. and J. Krow

Private Citizen

3637 November 13, 2011 Anonymous public comment

3638 November 7, 2011 Eugene Depasquale

PA House of Representatives

3639 November 9, 2011 John S. Lyons

Kentucky Dept. for Environmental Protection

3640 November 14, 2011 N. Kasper

Private Citizen

3641 November 14, 2011 M. Sickinger

Private Citizen

3642 November 14, 2011 K. Crawbuck

Private Citizen

3643 November 14, 2011 J. Bartley

Private Citizen

3644 November 14, 2011 R. Desy

Private Citizen

3645 November 14, 2011 W. J. Steinbacher

Private Citizen

3646 November 14, 2011 C. McMullen

Private Citizen

3647 November 14, 2011 F. Schwacke

Private Citizen

3648 November 14, 2011 J. Remington

Private Citizen

3649 November 14, 2011 C. Saint-Clair

Private Citizen

3650 November 14, 2011 D. Eyermann

Private Citizen

3651 November 14, 2011 T. Baer

Private Citizen
590

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3652 November 14, 2011 L. Smith

Private Citizen

3653 November 14, 2011 D. Publow

Private Citizen

3654 November 14, 2011 D. Kisor

Private Citizen

3655 November 14, 2011 O. Pruett

Private Citizen

3656 November 14, 2011 C. Alperstein

Private Citizen

3657 November 14, 2011 E. Vaughn

Private Citizen

3658 November 14, 2011 F. Strawser

Private Citizen

3659 November 14, 2011 D. SanMiguel

Private Citizen

3660 November 14, 2011 S. Benton

Private Citizen

3661 November 14, 2011 D. Craig

Private Citizen

3662 November 14, 2011 M. Bailey

Private Citizen

3663 November 14, 2011 D. Gordillo

Private Citizen

3664 November 14, 2011 L. Yow

Private Citizen

3665 November 14, 2011 H. Kahn

Private Citizen

3666 November 14, 2011 R. Elias

Private Citizen

3667 November 14, 2011 L. Milstead

Private Citizen

3668 November 14, 2011 B. Kloos

Private Citizen

3669 November 14, 2011 T. Taylor

Private Citizen

3670 November 14, 2011 E. Venstra

Private Citizen

3671 November 14, 2011 V. Peyer

Private Citizen

3672 November 14, 2011 J. Nickels

Private Citizen

3673 November 14, 2011 E. Cohen

Private Citizen

3674 November 14, 2011 S. Robinson

Private Citizen
591

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3675 November 14, 2011 D. Levering

Private Citizen

3676 November 14, 2011 L. Ashford

Private Citizen

3677 November 15, 2011 R. Zampino

Private Citizen

3678 November 14, 2011 P. Menyuk

Private Citizen

3679 November 14, 2011 G. Dykstra

Private Citizen

3680 November 14, 2011 V. Frazzetta

Private Citizen

3681 November 14, 2011 G. Dunsmith

Private Citizen

3682 November 14, 2011 E. Clark

Private Citizen

3683 November 14, 2011 K. Kirk

Private Citizen

3684 November 14, 2011 Dr. J. Witte

Private Citizen

3685 November 14, 2011 Dr. A. Ng

Private Citizen

3686 November 14, 2011 J. Groshardt

Private Citizen

3687 November 14, 2011 J. Irvine

Private Citizen

3688 November 14, 2011 B. Hyer

Private Citizen

3689 November 14, 2011 P. Allen

Private Citizen

3690 November 14, 2011 Dr. D. Baker

Private Citizen

3691 November 14, 2011 D. Sher

Private Citizen

3692 November 14, 2011 R. Racimora

Private Citizen

3693 November 14, 2011 D. Hix

Private Citizen

3694 November 14, 2011 A. Pringle

Private Citizen

3695 November 14, 2011 D. Oppelt

Private Citizen

3696 November 14, 2011 G. Whitcomb

Private Citizen

3697 November 14, 2011 Dr. H. Wendel

Private Citizen
592

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3698 November 14, 2011 S. Kitzes

Private Citizen

3699 November 14, 2011 J. Reardon

Private Citizen

3700 November 14, 2011 Dr. B. Sowder

Private Citizen

3701 November 14, 2011 E. Jones

Private Citizen

3702 November 14, 2011 P. Gregg

Private Citizen

3703 November 14, 2011 P. Musick

Private Citizen

3704 November 14, 2011 C. Jackson

Private Citizen

3705 November 14, 2011 B. Birks

Private Citizen

3706 November 14, 2011 D. Stryker

Private Citizen

3707 November 14, 2011 C. Tansey

Private Citizen

3708 November 14, 2011 S. Lang

Private Citizen

3709 November 14, 2011 G. Adams

Private Citizen

3710 November 15, 2011 Dr. D. Dow

Private Citizen

3711 November 14, 2011 B. V. Weg

Private Citizen

3712 November 14, 2011 L. Goin

Private Citizen

3713 November 14, 2011 L. Hargreaves

Private Citizen

3714 November 14, 2011 P. Glasson

Private Citizen

3715 November 14, 2011 C. Whiting

Private Citizen

3716 November 14, 2011 Dr. J. Perlman

Private Citizen

3717 November 14, 2011 S. Geurkink

Private Citizen

3718 November 14, 2011 J. Lukas

Private Citizen

3719 November 14, 2011 C. O’Meara Dietrich

Private Citizen

3720 November 14, 2011 R. L. Davis

Private Citizen
593

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3721 November 15, 2011 T. Hunt

Private Citizen

3722 November 14, 2011 J. Schreiber

Private Citizen

3723 November 14, 2011 F. Bassow

Private Citizen

3724 November 14, 2011 M. Brenner

Private Citizen

3725 November 14, 2011 J. Howard

Private Citizen

3726 November 14, 2011 J. Doerr

Private Citizen

3727 November 14, 2011 Dr. Rev. J. Ekman

Private Citizen

3728 November 14, 2011 D. Boom

Private Citizen

3729 November 14, 2011 Dr. V. Feldman

Private Citizen

3730 November 14, 2011 V. Buzeta

Private Citizen

3731 November 14, 2011 Elaine K.

Private Citizen

3732 November 14, 2011 M. A. Dimand

Private Citizen

3733 November 14, 2011 Dr. J. Jordan

Private Citizen

3734 November 14, 2011 W. Montgomery

Private Citizen

3735 November 14, 2011 M. Yoder

Private Citizen

3736 November 14, 2011 L. Winslow

Private Citizen

3737 November 14, 2011 H. Carr

Private Citizen

3738 November 14, 2011 Dr. J. Smith

Private Citizen

3739 November 14, 2011 N. Scott

Private Citizen

3740 November 14, 2011 D. Finlayson

Private Citizen

3741 November 14, 2011 T. MacKenzie

Private Citizen

3742 November 14, 2011 L. Seifried

Private Citizen

3743 November 14, 2011 L. Elliot

Private Citizen
594

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3744 November 14, 2011 J. Andrews

Private Citizen

3745 November 14, 2011 R. Hueston

Private Citizen

3746 November 14, 2011 D. Carswell

Private Citizen

3747 November 14, 2011 D. Neel

Private Citizen

3748 November 14, 2011 Dr. S. Rodriguez

Private Citizen

3749 November 14, 2011 D. Martens

Private Citizen

3750 November 14, 2011 B. Meyer

Private Citizen

3751 November 14, 2011 H. Russell

Private Citizen

3752 November 14, 2011 Dr. C. A. Lowry

Private Citizen

3753 November 14, 2011 M. Goulart

Private Citizen

3754 November 14, 2011 Dr. C. Steinhart

Private Citizen

3755 November 14, 2011 B. Enson

Private Citizen

3756 November 14, 2011 J. Engelking

Private Citizen

3757 November 14, 2011 L. Poole

Private Citizen

3758 November 14, 2011 R. Springer

Private Citizen

3759 November 14, 2011 R. D. Flynn-Webb

Private Citizen

3760 November 14, 2011 A. Bowen

Private Citizen

3761 November 14, 2011 Dr. M. Kornacker

Private Citizen

3762 November 14, 2011 M. Ingalls

Private Citizen

3763 November 14, 2011 D. Kosak

Private Citizen

3764 November 14, 2011 L. Hunt

Private Citizen

3765 November 14, 2011 A. Buffer

Private Citizen

3766 November 14, 2011 M. Meek

Private Citizen
595

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3767 November 14, 2011 Dr. M. Pellegrini

Private Citizen

3768 November 14, 2011 M. McKennon

Private Citizen

3769 November 14, 2011 T. Moore

Private Citizen

3770 November 14, 2011 J. Borstelmann

Private Citizen

3771 November 14, 2011 H. Fitzgerald

Private Citizen

3772 November 14, 2011 J. Dunlap

Private Citizen

3773 November 14, 2011 G. Saum

Private Citizen

3774 November 14, 2011 D. Dimock

Private Citizen

3775 November 14, 2011 Dr. W. Aller

Private Citizen

3776 November 14, 2011 J. Enkoji

Private Citizen

3777 November 14, 2011 Dr. L. Bowman

Private Citizen

3778 November 14, 2011 G. Anderson

Private Citizen

3779 November 14, 2011 C. Mellors

Private Citizen

3780 November 15, 2011 R. Smith

Private Citizen

3781 November 15, 2011 V. Weinblatt

Private Citizen

3782 November 15, 2011 A. Ellis

Private Citizen

3783 November 14, 2011 Dr. S. Stafford

Private Citizen

3784 November 14, 2011 R. Chan

Private Citizen

3785 November 14, 2011 Dr. J. Weinstein

Private Citizen

3786 November 14, 2011 K. Feil

Private Citizen

3787 November 14, 2011 R. Gedrim

Private Citizen

3788 November 15, 2011 N. McNaughton

Private Citizen

3789 November 15, 2011 D. Crist

Private Citizen
596

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3790 November 14, 2011 L. Yow

Private Citizen

3791 November 15, 2011 K. Young

Private Citizen

3792 November 15, 2011 N. Hanks

Private Citizen

3793 November 15, 2011 M. Morrison

Private Citizen

3794 November 14, 2011 J. Maguire

Private Citizen

3795 November 14, 2011 Dr. L. Levitt

Private Citizen

3796 November 14, 2011 N. Tingen

Private Citizen

3797 November 14, 2011 D. Davis

Private Citizen

3798 November 14, 2011 T. Falconer

Private Citizen

3799 November 15, 2011 B. Berger

Private Citizen

3800 November 15, 2011 C. Nelson

Private Citizen

3801 November 15, 2011 Y. Ruben

Private Citizen

3802 November 15, 2011 J. Rosell

Private Citizen

3803 November 15, 2011 M. Switzer

Private Citizen

3804 November 15, 2011 D. Flores

Private Citizen

3805 November 15, 2011 R. Godes

Private Citizen

3806 November 14, 2011 Dr. R. Donnelly

Private Citizen

3807 November 14, 2011 B. Condley

Private Citizen

3808 November 14, 2011 J. Dart

Private Citizen

3809 November 14, 2011 Dr. M. and A. Roberts

Private Citizens

3810 November 14, 2011 D. Schneck

Private Citizen

3811 November 14, 2011 D. G. Clair

Private Citizen

3812 November 14, 2011 A. Wasgatt

Private Citizen
597

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3813 November 14, 2011 N. Kamp

Private Citizen

3814 November 14, 2011 J. Chamberlin

Private Citizen

3815 November 14, 2011 S. M. Camarillo

Private Citizen

3816 November 14, 2011 J. Cain

Private Citizen

3817 November 14, 2011 K. Gordon

Private Citizen

3818 November 14, 2011 Dr. F. O'Brien

Private Citizen

3819 November 14, 2011 S. Tingen

Private Citizen

3820 November 14, 2011 G. Scott Hansen

Private Citizen

3821 November 14, 2011 Dr. R. Rico

Private Citizen

3822 November 14, 2011 V. Jimenez

Private Citizen

3823 November 14, 2011 D. R. Nelson

Private Citizen

3824 November 15, 2011 D. Jitchotvisut

Private Citizen

3825 November 15, 2011 G. Kennelly

Private Citizen

3826 November 14, 2011 Dr. P. Richard-Amato

Private Citizen

3827 November 15, 2011 D. Dean

Private Citizen

3828 November 15, 2011 B. Winholtz

Private Citizen

3829 November 15, 2011 J. Chafe

Private Citizen

3830 November 15, 2011 Dr. H. Dentinger

Private Citizen

3831 November 15, 2011 L. Hanratty

Private Citizen

3832 November 15, 2011 J. A. Pierson

Private Citizen

3833 November 15, 2011 A. Zima

Private Citizen

3834 November 15, 2011 M. Herbold

Private Citizen

3835 November 15, 2011 A. Pearce

Private Citizen
598

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3836 November 15, 2011 B. Ulbrich

Private Citizen

3837 November 15, 2011 J. Zaso

Private Citizen

3838 November 14, 2011 C. Armerding

Private Citizen

3839 November 14, 2011 S. Blakemore

Private Citizen

3840 November 15, 2011 J. Gau

Private Citizen

3841 November 15, 2011 Dr. S. Hnatowich

Private Citizen

3842 November 15, 2011 D. Bullock

Private Citizen

3843 November 15, 2011 I. Botvin

Private Citizen

3844 November 15, 2011 D. Brest

Private Citizen

3845 November 14, 2011 T. Twitchell

Private Citizen

3846 November 14, 2011 L. Mcdevitt

Private Citizen

3847 November 15, 2011 M. McDonald

Private Citizen

3848 November 15, 2011 N. Poore

Private Citizen

3849 November 15, 2011 C. Hunt

Private Citizen

3850 November 15, 2011 D. Kelly

Private Citizen

3851 November 15, 2011 G. Paquin

Private Citizen

3852 November 15, 2011 G. Cook

Private Citizen

3853 November 15, 2011 L. Lambeth

Private Citizen

3854 November 15, 2011 M. Whitney

Private Citizen

3855 November 15, 2011 A. Bill

Private Citizen

3856 September 28, 2011 Judy Raab

Quicksilver Resources Inc.

3857 November 14, 2011 R. Zucchi

Private Citizen

3858 November 15, 2011 V. Smith

Private Citizen
599

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3859 November 15, 2011 S. Mullins

Private Citizen

3860 November 11, 2011 R. Thomas

Private Citizen

3861 November 11, 2011 G. Carter

Private Citizen

3862 November 11, 2011 A. Green

Private Citizen

3863 November 11, 2011 J. Clarke

Private Citizen

3864 November 14, 2011 K. Bedard

Private Citizen

3865 November 14, 2011 S. Bannister

Private Citizen

3866 November 15, 2011 Dr. L. R. Jaffee

Private Citizen

3867 November 15, 2011 P. Sweeny

Private Citizen

3868 November 15, 2011 D. Hawley

Private Citizen

3869 November 15, 2011 S. White

Private Citizen

3870 November 15, 2011 K. Reede

Private Citizen

3871 November 15, 2011 M. Herlin

Private Citizen

3872 November 15, 2011 C. Stoutamyer

Private Citizen

3873 November 15, 2011 T. Rieve

Private Citizen

3874 November 14, 2011 Dr. M. Hein

Private Citizen

3875 November 14, 2011 B. Van Noord

Private Citizen

3876 November 14, 2011 L. Wimberly

Private Citizen

3877 November 14, 2011 P. Servidio

Private Citizen

3878 November 14, 2011 Dr. V. Colin

Private Citizen

3879 November 15, 2011 F. Schilling

Private Citizen

3880 November 15, 2011 Dr. L. Young

Private Citizen

3881 November 15, 2011 R. Hutchinson

Private Citizen
600

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3882 November 15, 2011 J. Dietrick

Private Citizen

3883 November 15, 2011 K. Smith

Private Citizen

3884 November 15, 2011 A. Jolles

Private Citizen

3885 November 15, 2011 C. Gholson

Private Citizen

3886 November 15, 2011 M. Sukiennik

Private Citizen

3887 November 15, 2011 S. Davidson

Private Citizen

3888 November 15, 2011 B. Haberly

Private Citizen

3889 November 15, 2011 J. Nickels

Private Citizen

3890 November 15, 2011 S. Wheeler

Private Citizen

3891 November 15, 2011 A. Cortese

Private Citizen

3892 November 15, 2011 C. Guthrie

Private Citizen

3893 November 15, 2011 E. Hansen

Private Citizen

3894 November 15, 2011 L. Scharin

Private Citizen

3895 November 15, 2011 J. Furlong

Private Citizen

3896 November 15, 2011 C. Griggs

Private Citizen

3897 November 15, 2011 D. Kellogg

Private Citizen

3898 November 15, 2011 D. Schwamb

Private Citizen

3899 November 15, 2011 J. Jarvis

Private Citizen

3900 November 15, 2011 B. Flowers

Private Citizen

3901 November 15, 2011 J. Boone

Private Citizen

3902 November 15, 2011 J. Wojdak

Private Citizen

3903 November 11, 2011 D. Bentley

Private Citizen

3904 November 11, 2011 C. Gillham

Private Citizen
601

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3905 November 11, 2011 P. Bryan

Private Citizen

3906 November 11, 2011 A. Fiallos

Private Citizen

3907 November 11, 2011 J. Rohrs

Private Citizen

3908 November 11, 2011 S. McNall

Private Citizen

3909 November 12, 2011 A. Willis

Private Citizen

3910 November 12, 2011 R. Talley

Private Citizen

3911 November 12, 2011 A. Lewandowski

Private Citizen

3912 November 15, 2011 J. and K. Schermerhorn

Private Citizens

3913 November 15, 2011 L. Pillsbury

Private Citizen

3914 November 13, 2011 C. Finley

Private Citizen

3915 November 13, 2011 L. Van Horn

Private Citizen

3916 November 13, 2011 C. Wood

Private Citizen

3917 November 13, 2011 J. Bianculli

Private Citizen

3918 November 13, 2011 R. Gaebe

Private Citizen

3919 November 13, 2011 R. Howard

Private Citizen

3920 November 13, 2011 D. Cote

Private Citizen

3921 November 15, 2011 D. Harris

Private Citizen

3922 November 15, 2011 H. Ross

Private Citizen

3923 November 15, 2011 K. Steele

Private Citizen

3924 November 15, 2011 W. Roberson

Private Citizen

3926 November 14, 2011 M. Bentz

Private Citizen

3927 November 14, 2011 L. Sternberg

Private Citizen

3928 November 17, 2011 Thomas Y. Au

Clean Air Board of Central Pennsylvania
602

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3929 November 13, 2011 Z. Schirg

Private Citizen

3930 November 14, 2011 I. Hughes

Private Citizen

3931 November 15, 2011 R. Milburn

Private Citizen

3932 November 15, 2011 D. Roth

Private Citizen

3933 November 15, 2011 S. McKee

Private Citizen

3934 November 15, 2011 G. Rubio

Private Citizen

3935 November 15, 2011 V. Meluskey

Private Citizen

3936 November 15, 2011 D. Yarger

Private Citizen

3937 November 15, 2011 L. Freese

Private Citizen

3938 November 15, 2011 S. Huybensz

Private Citizen

3939 November 15, 2011 J. Vischulis

Private Citizen

3940 November 15, 2011 M. Wood

Private Citizen

3941 November 15, 2011 J. Curotto

Private Citizen

3942 November 15, 2011 R. Martin

Private Citizen

3943 November 15, 2011 G. Chester

Private Citizen

3944 November 15, 2011 G. Sletten

Private Citizen

3945 November 15, 2011 S. Saxe

Private Citizen

3946 November 15, 2011 B. Hillway

Private Citizen

3947 November 16, 2011 E. Hecker

Private Citizen

3948 November 15, 2011 A. Banwart

Private Citizen

3949 November 15, 2011 S. McNeil

Private Citizen

3950 November 15, 2011 K. Schneller-McDonald

Private Citizen

3951 November 15, 2011 E. Lebowitz

Private Citizen
603

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3952 November 15, 2011 L. Fraley

Private Citizen

3953 November 15, 2011 B. Hodgin

Private Citizen

3954 November 15, 2011 L. Ghelfi

Private Citizen

3955 November 15, 2011 J. DiNardo

Private Citizen

3956 November 15, 2011 J. Steitz

Private Citizen

3957 November 15, 2011 H. Turner

Private Citizen

3958 November 15, 2011 D. Witcher

Private Citizen

3959 November 15, 2011 J. Archuleta

Private Citizen

3960 November 15, 2011 M. Damero

Private Citizen

3961 November 15, 2011 J. Castiano

Private Citizen

3962 November 15, 2011 T. Donaghy

Private Citizen

3963 November 15, 2011 J. Sharon

Private Citizen

3964 November 15, 2011 K. Brush

Private Citizen

3965 November 15, 2011 K. Hogg

Private Citizen

3966 November 15, 2011 K. Nussbaum

Private Citizen

3967 November 15, 2011 B. Olson

Private Citizen

3968 November 15, 2011 G. Lee

Private Citizen

3969 November 15, 2011 K. Burroughs

Private Citizen

3970 November 15, 2011 G. Singer

Private Citizen

3971 November 15, 2011 R. Siegfried

Private Citizen

3972 November 15, 2011 T. Sparkman

Private Citizen

3973 November 15, 2011 J. Maryanski

Private Citizen

3974 November 15, 2011 T. Stanley

Private Citizen
604

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3975 November 15, 2011 P. Gampper

Private Citizen

3976 November 15, 2011 A. Salinas

Private Citizen

3977 November 15, 2011 E. Marshall

Private Citizen

3978 November 15, 2011 J. Rex

Private Citizen

3979 November 15, 2011 H. Allen

Private Citizen

3980 November 15, 2011 S. Bhakti

Private Citizen

3981 November 15, 2011 S. Bishop

Private Citizen

3982 November 15, 2011 K. Prak

Private Citizen

3983 November 15, 2011 J. Jones

Private Citizen

3984 November 15, 2011 Dr. D. Stanford

Private Citizen

3985 November 15, 2011 R. Palmatier

Private Citizen

3986 November 15, 2011 I. S. Smith

Private Citizen

3987 November 15, 2011 E. Mayer

Private Citizen

3988 November 15, 2011 L. Radice

Private Citizen

3989 November 15, 2011 R. Little

Private Citizen

3990 November 15, 2011 T. Blake

Private Citizen

3991 November 15, 2011 D. Shawver

Private Citizen

3992 October 31, 2011 T. Cook

Private Citizen

3993 October 31, 2011 T. Carter

Private Citizen

3994 October 29, 2011 R. Palmeiro

Private Citizen

3995 October 31, 2011 R. Pierce

Private Citizen

3996 October 31, 2011 R. Medlin

Private Citizen

3997 November 1, 2011 K. Smith

Private Citizen
605

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

3998 November 1, 2011 G. Miller

Private Citizen

3999 November 1, 2011 J. Wylie

Private Citizen

4000 November 1, 2011 L. Marshall

Private Citizen

4001 November 16, 2011 S. Byrd

Private Citizen

4002 November 16, 2011 S. Wallace

Private Citizen

4003 November 15, 2011 J. D. Bloom

Private Citizen

4004 November 16, 2011 J. Mayer

Private Citizen

4005 November 16, 2011 B. Menkart

Private Citizen

4006 November 16, 2011 S. Wallace

Private Citizen

4007 November 16, 2011 P. Davis

Private Citizen

4008 November 16, 2011 R. Longo

Private Citizen

4009 November 16, 2011 L. Sendejo

Private Citizen

4010 November 16, 2011 A. Mendelsohn

Private Citizen

4011 November 16, 2011 H. Jones

Private Citizen

4012 November 16, 2011 C. Crutcher

Private Citizen

4013 November 16, 2011 T. Imajo

Private Citizen

4014 November 16, 2011 M. Alexander

Private Citizen

4015 November 16, 2011 E. Muir

Private Citizen

4016 November 16, 2011 L. Miller

Private Citizen

4017 November 16, 2011 C. Fasanella

Private Citizen

4018 November 16, 2011 A. Ashcraft

Private Citizen

4019 November 16, 2011 W. Ebersberger

Private Citizen

4020 November 16, 2011 D. Turner

Private Citizen
606

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4021 November 16, 2011 B. Riversmith

Private Citizen

4022 November 16, 2011 R. Mc Nair

Private Citizen

4023 November 16, 2011 M. Rhodes

Private Citizen

4024 November 16, 2011 B. Chambers

Private Citizen

4025 November 16, 2011 D. Gilbert

Private Citizen

4026 November 16, 2011 C. Porter

Private Citizen

4027 November 16, 2011 J. Harvey

Private Citizen

4028 November 16, 2011 J. Capozzelli

Private Citizen

4029 November 16, 2011 M. Fogg

Private Citizen

4030 November 16, 2011 J. Trautman

Private Citizen

4031 November 16, 2011 P. Dobrovic

Private Citizen

4032 November 16, 2011 A. Botwin

Private Citizen

4033 November 16, 2011 S. Wilber

Private Citizen

4034 November 16, 2011 N. Rapp

Private Citizen

4035 November 17, 2011 K. Coventry

Private Citizen

4036 November 16, 2011 M. Coventry

Private Citizen

4037 November 17, 2011 R. Marshall

Private Citizen

4038 November 17, 2011 K. Hlynsky

4039 November 18, 2011 Pamela F. Faggert

Dominion Resources Services, Inc.

4040 November 17, 2011 K. Davis

Private Citizen

4041 November 18, 2011 Shana K. Yelverton

City of Southlake, Texas

4042 November 21, 2011 John A. Paul

Regional Air Pollution Control Agency, Dayton, 

Ohio

4043 November 17, 2011 B. Chally

Private Citizen
607

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4044 November 17, 2011 M. Snyder

Private Citizen

4045 November 17, 2011 J. Church

Private Citizen

4046 November 17, 2011 C. Kubik

Private Citizen

4047 November 17, 2011 C. Wayland

Private Citizen

4048 November 17, 2011 R. Love

Private Citizen

4049 November 17, 2011 L. Kissel

Private Citizen

4050 November 15, 2011 P. Green

Private Citizen

4051 November 15, 2011 J. Gilday

Private Citizen

4052 November 17, 2011 V. and S.Vanacore

Private Citizens

4053 November 18, 2011 J. Hubbard

Private Citizen

4054 November 18, 2011 J. Hakam

Private Citizen

4055 November 18, 2011 M. Wood

Private Citizen

4056 November 21, 2011 Gregory J. Wilkins

Marathon Petroleum Company

4057 November 18, 2011 L. Lowry

Private Citizen

4058 November 21, 2011 B. Seymour-Linder

Private Citizen

4059 November 18, 2011 J. Lukas

Private Citizen

4060 November 18, 2011 S. Kay

Private Citizen

4061 November 18, 2011 M. McIntosh

Private Citizen

4062 November 18, 2011 R. Little

Private Citizen

4063 November 18, 2011 M. Walling

Private Citizen

4064 November 18, 2011 R. Gowins

Private Citizen

4065 November 18, 2011 T. Crossland

Private Citizen

4066 November 18, 2011 B. Duncan

Private Citizen
608

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4067 November 18, 2011 R. Butler

Private Citizen

4068 November 18, 2011 P. Baker

Private Citizen

4069 November 18, 2011 S. Li

Private Citizen

4070 November 19, 2011 R. Fanniff

Private Citizen

4071 November 19, 2011 G. Spates

Private Citizen

4072 November 19, 2011 T. Johnson

Private Citizen

4073 November 20, 2011 J. Jarvis

Private Citizen

4074 November 20, 2011 R. Talley

Private Citizen

4075 November 20, 2011 S. Matheis

Private Citizen

4076 November 20, 2011 P. Pynchon

Private Citizen

4077 November 20, 2011 E. Cabell

Private Citizen

4078 November 20, 2011 H. Curtler

Private Citizen

4079 November 20, 2011 J. Drucker

Private Citizen

4080 November 20, 2011 F. Harkins

Private Citizen

4081 November 20, 2011 M. Oalbano

Private Citizen

4082 November 20, 2011 D. Hughes

Private Citizen

4083 November 20, 2011 R. Creshkoff

Private Citizen

4084 November 15, 2011 M. Erickson

Private Citizen

4085 November 15, 2011 W. Gawne

Private Citizen

4086 November 15, 2011 C. Stonecipher

Private Citizen

4087 November 15, 2011 D. Cherf

Private Citizen

4088 November 16, 2011 H. McFadden

Private Citizen

4089 November 16, 2011 J. Poole

Private Citizen
609

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4090 November 16, 2011 M. Hecht

Private Citizen

4091 November 16, 2011 S. Myers

Private Citizen

4092 November 21, 2011 William L. Driscoll

Ozone Transport Commission

4093 November 20, 2011 N. Haenn

Private Citizen

4094 November 15, 2011 S. Babbitt

Private Citizen

4095 November 15, 2011 R. Thill

Private Citizen

4096 November 15, 2011 J. Moore

Private Citizen

4097 November 15, 2011 L. Bracken

Private Citizen

4098 November 15, 2011 P. Chase

Private Citizen

4099 November 15, 2011 M. de Alba

Private Citizen

4100 November 15, 2011 J. Allen

Private Citizen

4101 November 15, 2011 M. Bradley

Private Citizen

4102 November 15, 2011 G. Castellane

Private Citizen

4103 November 15, 2011 J. Mendoza

Private Citizen

4104 November 22, 2011 Lisa S. Beal

Interstate Natural Gas Association of America

4105 November 17, 2011 C. Spencer

Private Citizen

4106 November 17, 2011 K. Kockritz

Private Citizen

4107 November 17, 2011 F. Evans

Private Citizen

4108 November 17, 2011 R. Sanderson

Private Citizen

4109 November 17, 2011 M. May

Private Citizen

4110 November 17, 2011 J. Abrams

Private Citizen

4111 November 17, 2011 C. Wooldridge

Private Citizen

4112 November 17, 2011 B. Todd

Private Citizen
610

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4113 November 4, 2011 R. Saretsky

Private Citizen

4114 November 7, 2011 C. Pinkston

Private Citizen

4115 November 7, 2011 R. Ross

Private Citizen

4116 November 7, 2011 G. Anderson

Private Citizen

4117 November 7, 2011 K. Hurley

Private Citizen

4118 November 8, 2011 R. Talley

Private Citizen

4119 November 8, 2011 E. Warner

Private Citizen

4120 November 14, 2011 L. Manter

Private Citizen

4121 November 8, 2011 N. Spray

Private Citizen

4122 November 22, 2011 S. Jackson

Private Citizen

4123 November 21, 2011 J. and R. Lyon

Private Citizen

4124 November 21, 2011 D. Sprang

Private Citizen

4125 November 21, 2011 R. Smith

Private Citizen

4126 November 21, 2011 J. Dabrowski

Private Citizen

4127 November 21, 2011 M. Judson

Private Citizen

4128 November 21, 2011 J. Avett

Private Citizen

4129 November 22, 2011 D. Watson

Private Citizen

4130 November 22, 2011 Anonymous public comment

4131 November 22, 2011 M. Sloan

Private Citizen

4132 November 22, 2011 M. Perry

Private Citizen

4133 November 23, 2011 R. Williams

Private Citizen

4134 November 27, 2011 A. Francisco

Private Citizen

4135 November 25, 2011 John V. Corra

Wyoming Dept of Environmental Quality
611

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4136 November 27, 2011 J. E. Rosenberg

Private Citizen

4137 November 23, 2011 Mike Brownell, Chesapeake Energy Corp

4138 November 22, 2011 M. Badgett

Private Citizen

4139 November 22, 2011 L. Rice

Private Citizen

4140 November 22, 2011 O. Altiok

Private Citizen

4141 November 22, 2011 M. Warren

Private Citizen

4142 November 22, 2011 A. Brown

Private Citizen

4143 November 22, 2011 M. Quinlan

Private Citizen

4144 November 22, 2011 L. Barnett

Private Citizen

4145 November 22, 2011 J. Schloz

Private Citizen

4146 November 22, 2011 T. Stuart

Private Citizen

4147 November 22, 2011 L. Zweber

Private Citizen

4148 November 22, 2011 J. Schneider

Private Citizen

4149 November 22, 2011 C. Burger

Private Citizen

4150 November 22, 2011 P. Leighton-Burwell

Private Citizen

4151 November 22, 2011 M. Lueg

Private Citizen

4152 November 23, 2011 M. Ham

Private Citizen

4153 November 25, 2011 B. Williams

Private Citizen

4154 November 25, 2011 J. Waller-Eling

Private Citizen

4155 November 26, 2011 L. Thompson

Private Citizen

4156 November 27, 2011 S. Region

Private Citizen

4157 November 28, 2011 G. Murphy

Private Citizen

4158 November 28, 2011 Trinh M. Tran

El Paso Corporation
612

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4159 November 28, 2011 J. Kelly Robbins

Arkansas Independent Producers & Royalty Owners 

Assoc

4160 November 28, 2011 Susan Combs

Texas Comptroller of Public Accounts

4161 November 28, 2011 Bryce C. Bird

Utah Division of Air Quality

4162 November 29, 2011 Jon A. Mueller

Chesapeake Bay Foundation, Inc. 

4163 November 29, 2011 Grant Maki

Ohio Environmental Council

4164 November 29, 2011 Leslie Witherspoon

Solar Turbines Inc.

4165 November 29, 2011 Doug Flanders

Colorado Oil & Gas Association

4166 November 28, 2011 Ali Mirzakhalili

Division of Air Quality, Delaware Dept. of Natural 

Resources & Environmental Control

4167 November 29, 2011 Teddy Carter

Texas Independent Producers and Royalty Owners 

Association

4168 November 29, 2011 C. Louis Renaud

Energy Resources, General Land Office, TX

4169 November 29, 2011 Anonymous public comment

4170 November 29, 2011 Michael L. Krancer

PA Dept. of Environmental Protection 

4171 November 29, 2011 Anonymous public comment

4172 November 29, 2011 Anonymous public comment

4173 November 30, 2011 Anonymous public comment

4174 November 30, 2011 Richard Metcalf

Louisiana Mid-Continent Oil and Gas Assoc

4175 November 30, 2011 John Dutton

Gas Compressor Assoc.

4176 November 28, 2011 David L. Klemp

Air Resources Management Bureau,

Montana Dept. of Environmental Quality

4177 November 30, 2011 Deb Hastings

Texas Oil & Gas Association

4178 November 28, 2011 Laura J. Finley

Oklahoma Dept. of Environmental Quality

4179 November 29, 2011 S. Polefka

Private Citizen

4180 November 29, 2011 E. and M. Griffin

Private Citizens

4181 November 29, 2011 Anonymous public comment
613

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4182 November 30, 2011 J. Wolf

Private Citizen

4183 November 25, 2011 A. Hofer

Private Citizen

4184 November 30, 2011 J. Jared Snyder

NY State Dept. of Environmental Conservation

4185 November 30, 2011 Thomas Bach

Kinder Morgan Energy Partners

4186 November 28, 2011 R. and B. Stippec

Private Citizens

4187 November 28, 2011 G. Garrison

Private Citizen

4188 November 28, 2011 J. Wiener

Private Citizen

4189 November 30, 2011 Earthjustice on behalf of:

Berks Gas Truth

Biodiversity Conservation Alliance 

Californians for Western Wilderness 

Center for Biological Diversity

Center for Health, Environment and Justice

Clean Water Action 

Colorado Environmental Coalition

Delaware Riverkeeper Network 

Drilling Mora County

Earthworks 

EcoFlight

Environmental Defense Fund

National Parks Conservation Association

National Wildlife Federation 

Natural Resources Defense Council

Pennsylvania Environmental Defense Foundation

Pennsylvania Forest Coalition

Powder River Basin Resource Council

Protecting Our Waters

Riverkeeper, Inc.

San Juan Citizens Alliance

Sierra Club

Southern Utah Wilderness Alliance

Upper Green River Alliance

Western Environmental Law Center

Western Organization of Resource Councils

Western Resource Advocates

WildEarth Guardians

Wilderness Workshop

WV Surface Owners' Rights Organization
614

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4190 November 29, 2011 A. Tonsmeire

Private Citizen

4191 November 30, 2011 William C. Allison V

Colorado Dept. of Public Health and Environment

4192 November 30, 2011 Jeff Applekamp

Gas Processors Association

4193 November 30, 2011 Fred Carl

Black Hills Exploration And Production and 

Midstream 

4194 November 28, 2011 G. Jeung

Private Citizen

4195 November 28, 2011 G. Holden

Private Citizen

4196 November 28, 2011 J. Bautista

Private Citizen

4197 November 28, 2011 G. Salatrik

Private Citizen

4198 November 30, 2011 C. Rorke and S. Batkins

Private Citizens

4199 November 29, 2011 G. Callas

Private Citizen

4200 November 29, 2011 E. Heyward

Private Citizen

4201 November 28, 2011 G. Russi

Private Citizen

4202 November 29, 2011 E. Morris

Private Citizen

4203 November 29, 2011 E. Caton

Private Citizen

4204 November 28, 2011 C. Millsapps

Private Citizen

4205 November 28, 2011 P. Janzen

Private Citizen

4206 November 28, 2011 C. Wackerbarth

Private Citizen

4207 November 29, 2011 J. Real

Private Citizen

4208 November 30, 2011 S. William Becker

National Association of Clean Air Agencies

4209 November 30, 2011 Angie Burckhalter

Oklahoma Independent Petroleum Assoc

4210 November 30, 2011 Veronica Nasser

REM Technology, Inc.

4211 November 30, 2011 C. Churba

Private Citizen
615

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4212 November 30, 2011 Veronica Nasser

REM Technology, Inc.

4213 November 30, 2011 Lisa Yoho

BG Americas & Global LNG

4214 November 30, 2011 Nicholas DeMarco

West Virginia Oil and Natural Gas Association

4215 November 30, 2011 Holly Propst

Western Business Roundtable

4216 November 30, 2011 Lee Fuller

Independent Petroleum Association of America

4217 November 30, 2011 Dan F. Hunter

ConocoPhillips Company

4218 November 30, 2011 Jessica L. Keiser

Targa Resources Corp.

4219 November 30, 2011 Patrick J. Nugent

Texas Pipeline Association

4220 November 30, 2011 John Robitaille

Petroleum Association of Wyoming

4221 November 30, 2011 Wyoming Outdoor Council

Environmental Defense Fund

4222 November 30, 2011 Daniel S. Sullivan

Dept of Natural Resources

Larry Hartig

Dept. of Environmental Conservation, Alaska

4223 November 30, 2011 National Wildlife Federation Action Fund, mass 

comment campaign (17,961)

4224 November 30, 2011 M. Bamberger, et al.

4225 November 30, 2011 Stan Dempsey, Jr.

Colorado Petroleum Association

4226 November 29, 2011 Vince Alaimo

CONSOL Energy Inc.

4227 November 30, 2011 Mike Wasson

Exterran

4228 November 30, 2011 Lee Hinman

Noble Energy

4229 November 30, 2011 Amy D. Kapuga

Consumers Energy

4230 November 30, 2011 John A. Benedict

West Virginia Dept. of Environmental Protection

4231 November 29, 2011 Kathleen M. Sgamma

Western Energy Alliance et al.

4232 November 30, 2011 Credo Action mass comment campaign (58,678)

4233 November 30, 2011 Richard Luedecke

Devon Energy Corporation

4234 November 30, 2011 Pamela A. Lacey

American Gas Association
616

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4235 November 30, 2011 Stan Dempsey, Jr.

Colorado Petroleum Association

4236 November 30, 2011 Charlie Burd

Independent Oil and Gas Association of West 

Virginia

4237 November 30, 2011 Ted Robinson 

Citizen Power

4238 November 30, 2011 Cathy S. Woollums

MidAmerican Energy Holdings Company

4239 November 30, 2011 Daniel S. Sullivan

State of Alaska 

Dept. of Natural Resources

Department of Environmental Conservation

4240 November 30, 2011 Craig H. Segall

Sierra Club

4241 November 30, 2011 Amy Farrell

America's Natural Gas Alliance and 

Bruce Thompson

American Exploration and Petroleum Council

4242 November 30, 2011 Sparsh Khandeshi

Environmental Integrity Project 

4243 November 30, 2011 Katten Muchin Rosenman LLP 

Air Permitting Forum

4244 December 1, 2011 Michael Pontiff

Newfield Exploration Company

4245 November 30, 2011 Ben Shepperd

Permian Basin Petroleum Association

4246 November 30, 2011 Kathryn Z. Klaber

Marcellus Shale Coalition

4247 November 30, 2011 Kate Williams

Alaska Oil and Gas Association

4248 November 30, 2011 Ann M. Mason

American Chemistry Council

4249 November 30, 2011 Gregory L. Ryan

DTE Energy

4250 November 30, 2011 Group Against Smog and Pollution (GASP)

4251 November 30, 2011 Gretchen C. Kern

Pioneer Natural Resources USA, Inc.

4252 November 30, 2011 William W. (Bill) Grygar II

Anadarko Petroleum Corporation

4253 November 30, 2011 Janice E. Nolen

American Lung Association et al.

4254 November 30, 2011 Stuart M. Kowalski

Slawson Exploration Company, Inc.

4255 November 30, 2011 Anthony J. Giuliani

Ohio Oil and Gas Association
617

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4256 November 30, 2011 David A. Galt

Montana Petroleum Association

4257 November 30, 2011 Elizabeth Paranhos and Peter Zalzal

Environmental Defense Fund 

Bruce Pendery

Wyoming Outdoor Council

4258 November 30, 2011 Steve P. Henke

New Mexico Oil & Gas Association

4259 November 30, 2011 Christi Zeller

La Plata County Energy Council

4260 November 30, 2011 Ritu Talwar

Spectra Energy Corp

4261 November 30, 2011 Sam L. Phillips

Louisiana Dept. of Environmental Quality

4262 November 30, 2011 John C. Bosch

J. Bosch Ltd.

4263 November 30, 2011 Kenneth A. Malmquist

AECOM

4264 November 30, 2011 Lisa Barry

Chevron Corporation

4265 November 30, 2011 Gregory L. Ryan

DTE Energy

4266 November 30, 2011 Howard J. Feldman

American Petroleum Institute

4267 November 30, 2011 Dan Girand

Mack Energy Corp.

4268 November 30, 2011 John Dutton

Gas Compressor Association

4269 November 30, 2011 Tommy Taylor

Texas Alliance of Energy Producers

4270 November 30, 2011 George P. Williams

Sempra Energy

4271 November 30, 2011 S. Gilbert

Private Citizen

4272 November 30, 2011 N. and J. Miller

Private Citizens

4273 November 30, 2011 Shannon S. Broome, et al.

Katten Muchin Rosenman LLP 

Air Permitting Forum

4274 November 29, 2011 Emily Krafjack

Wyoming County, Pennsylvania

4275 November 30, 2011 Bruce Baizel

Earthworks' Oil & Gas Accountability Project 

(OGAP)

4276 November 30, 2011 Susan Knoll

Argyle-Bartonville Community Alliance, et al.
618

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4277 November 30, 2011 I. Bloom

Private Citizen

4278 November 30, 2011 E. Esch

Private Citizen

4279 November 30, 2011 J. Foulk

Private Citizen

4280 November 30, 2011 P. Saberi

Private Citizen

4281 November 30, 2011 R. Douglas Rogers

Marathon Oil Company

4282 November 30, 2011 Scott Crump

Quantum Resources Management

4283 November 23, 2011 C. and M. Ham

Private Citizens

4284 November 30, 2011 R. Platt

Private Citizen

4285 November 30, 2011 K. Kin

Private Citizen

4286 November 30, 2011 T. Devaney

Private Citizen

4287 November 30, 2011 S. Pickard

Private Citizen

4288 November 30, 2011 A. Pentecost-Farren

Private Citizen

4289 November 30, 2011 J. Norkin

Private Citizen

4290 November 30, 2011 W. Dent

Private Citizen

4291 November 30, 2011 A. Payne

Private Citizen

4292 November 30, 2011 S. and G. Skoloff

Private Citizens

4293 November 30, 2011 P. MacDonald

Private Citizen

4294 November 30, 2011 S. Strahs

Private Citizen

4295 November 30, 2011 B. Hay

Private Citizen

4296 November 30, 2011 Ralph Kisberg, et. al.

Responsible Drilling Alliance

4297 November 30, 2011 G. Crouse

Private Citizen

4298 November 30, 2011 B. Bennett

Private Citizen

4299 November 30, 2011 J. Dillard

Private Citizen
619

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4300 November 30, 2011 J. Prettyman

Private Citizen

4301 November 30, 2011 L. Lindsey

Private Citizen

4302 November 30, 2011 B. Clifford

Private Citizen

4303 November 30, 2011 F. Bowers

Private Citizen

4304 November 30, 2011 E. Flower

Private Citizen

4305 October 12, 2011 A. Palmer

Private Citizen

4306 September 29, 2011 C. Vosecky

Private Citizen

4307 November 30, 2011 B. Bender

Private Citizen

4308 November 30, 2011 M. Steakley

Private Citizen

4309 November 30, 2011 K. Bradshaw

Private Citizen

4310 November 30, 2011 H. and M. Weichel

Private Citizens

4311 November 30, 2011 G. Pace

Private Citizen

4312 November 15, 2011 L. Atkinson

Private Citizen

4313 November 30, 2011 D. Davis

Private Citizen

4314 November 30, 2011 R. Downs

Private Citizen

4315 November 30, 2011 E. Berry

Private Citizen

4316 November 30, 2011 Charles A. Whitehead, President

Linear Motion Technologies

4317 December 1, 2011 Carla L. Suszkowski

Appalachia, LLC

4318 November 30, 2011 E. Rodney

4319 November 30, 2011 D. Brown

4320 November 30, 2011 Todd L. Normane

Talisman Energy USA, Inc.

4321 November 30, 2011 S. Patterson

Private Citizen

4322 November 30, 2011 A. Crowe

4323 September 15, 2011 Anonymous public comment

4324 November 30, 2011 C. Ristow

Private Citizen
620

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4325 September 15, 2011 Anonymous public comment

4326 September 15, 2011 Anonymous public comment

4327 September 15, 2011 Anonymous public comment

4328 September 15, 2011 Anonymous public comment

4329 September 15, 2011 Anonymous public comment

4330 September 15, 2011 Anonymous public comment

4331 September 16, 2011 Anonymous public comment

4332 September 19, 2011 Anonymous public comment

4333 November 30, 2011 G. Aird

Private Citizen

4334 September 25, 2011 Anonymous public comment

4335 September 25, 2011 Nancy (no last name provided)

4336 September 26, 2011 Anonymous public comment

4337 September 26, 2011 Anonymous public comment

4338 October 6, 2011 Anonymous public comment

4339 October 9, 2011 Anonymous public comment

4340 October 11, 2011 D. Newton

Private Citizen

4341 October 17, 2011 Anonymous public comment

4342 October 17, 2011 H. Oriano

Private Citizen

4343 October 17, 2011 Anonymous public comment

4344 October 17, 2011 T. Alcorn

Private Citizen

4345 October 17, 2011 Anonymous public comment

4346 October 17, 2011 Anonymous public comment

4347 October 17, 2011 Sergei (no surname provided)

4348 October 17, 2011 Anonymous public comment

4349 October 18, 2011 Anonymous public comment

4350 November 30, 2011 T. Held

Private Citizen

4351 November 30, 2011 K. Higgins

Private Citizen

4352 November 30, 2011 D. Mondejar

Private Citizen

4353 November 30, 2011 S. Thomason

Private Citizen

4354 November 30, 2011 Matthew Todd

The Residual Risk Coalition

4355 October 5, 2011 Nancy Wiggins

Yellowstone Valley Audubon Society

4356 November 30, 2011 Mark R. Vickery

Texas Commission on Environmental Quality 

4357 November 30, 2011 Michael R. Woelk

Picarro
621

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4358 December 5, 2011 Catherine H. Reheis-Boyd

Western States Petroleum Association

4359 November 30, 2011 A. Monderewicz

Private Citizen

4360 November 30, 2011 E. Echevarria

Private Citizen

4361 November 30, 2011 S. Baldwin

Private Citizen

4362 November 30, 2011 V. Strange

Private Citizen

4363 November 30, 2011 M. Ciaccia

Private Citizen

4364 November 30, 2011 R. Caputo

Private Citizen

4365 November 30, 2011 B. McDonald

Private Citizen

4366 November 30, 2011 D. Mondejar

Private Citizen

4367 November 30, 2011 K. Michaelis

Private Citizen

4368 November 30, 2011 C. Benson

Private Citizen

4369 November 30, 2011 A. Monderewicz

Private Citizen

4370 November 30, 2011 D. Bulla

Private Citizen

4371 November 30, 2011 T. Wade

Private Citizen

4372 November 30, 2011 J. Balling

Private Citizen

4373 November 30, 2011 K. Rowlett

Private Citizen

4374 November 30, 2011 K. Rowlett

Private Citizen

4375 November 30, 2011 Joseph Otis Minott

Clean Air Council

4376 December 8, 2011 A. Rourke

Private Citizen

4377 November 25, 2011 R. Shroy

Private Citizen

4378 November 25, 2011 R. Chomo

Private Citizen

4379 November 25, 2011 M. Whelchel

Private Citizen

4380 November 25, 2011 J. Hensen

Private Citizen
622

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4381 November 25, 2011 D. Stanko

Private Citizen

4382 November 25, 2011 T. Schock

Private Citizen

4383 November 25, 2011 L. Adkins

Private Citizen

4384 November 25, 2011 J. Smith

Private Citizen

4385 November 25, 2011 M. Spahr

Private Citizen

4386 November 30, 2011 D. Guernsey

Private Citizen

4387 November 29, 2011 I. Kunin

Private Citizen

4388 November 29, 2011 M. Papakhian

Private Citizen

4389 November 30, 2011 R. E. Rutkowski

Private Citizen

4390 November 28, 2011 Dr. R. Jameson

Private Citizen

4391 November 22, 2011 M. Greer

Private Citizen

4392 November 23, 2011 Dr. K. W. Hess

Private Citizen

4393 November 23, 2011 Dr. L. Michalove

Private Citizen

4394 November 23, 2011 Dr. L. Michalove

Private Citizen

4395 November 23, 2011 Dr. L. Michalove

Private Citizen

4396 November 28, 2011 A. Bieliauskas

Private Citizen

4397 November 23, 2011 D. Staudenmeir

Private Citizen

4398 November 23, 2011 C. Friedman

Private Citizen

4399 November 23, 2011 K. Mizelle

Private Citizen

4400 November 23, 2011 M. Bandy-Zalatoris

Private Citizen

4401 November 23, 2011 L. Dahill

Private Citizen

4402 November 23, 2011 J. Stender

Private Citizen

4403 November 23, 2011 A. Lundberg

Private Citizen
623

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4404 November 23, 2011 L. Hegstrand

Private Citizen

4405 November 23, 2011 V. van Buchem

Private Citizen

4406 November 23, 2011 M. Fenton

Private Citizen

4407 November 23, 2011 J. Pintner

Private Citizen

4408 November 28, 2011 E. Taylor

Private Citizen

4409 November 25, 2011 S. Righi

Private Citizen

4410 November 25, 2011 C. Hatten

Private Citizen

4411 November 25, 2011 K. Allen

Private Citizen

4412 November 25, 2011 K. Carolus

Private Citizen

4413 November 25, 2011 U. Hopfer

Private Citizen

4414 October 27, 2011 Natural Resources Defense Council

mass comment campaign (10,769)

4415 November 9, 2011 Mass Comment Campaign sponsoring organization 

unknown (163)

4416 October 19, 2011 Mass Comment Campaign sponsoring organization 

unknown (1,883)

4417 October 18, 2011 Anonymous public comment

4418 October 19, 2011 Anonymous public comment

4419 October 19, 2011 Anonymous public comment

4420 October 19, 2011 Anonymous public comment

4421 October 19, 2011 Anonymous public comment

4422 October 20, 2011 Anonymous public comment

4423 November 21, 2011 Anonymous public comment

4424 November 28, 2011 M. Lewchuk

Private Citizen

4425 December 12, 2011 Shannon S. Broome, et al., Katten Muchin Rosenman 

LLP

Air Permitting Forum

4426 November 28, 2011 Sierra Club mass comment campaign (175)

4427 October 30, 2011 Anonymous public comment

4428 November 21, 2011 C. Elejoste

Private Citizen

4429 November 19, 2011 S. Lynch

Private Citizen
624

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4430 November 21, 2011 K. Castillo

Private Citizen

4431 November 21, 2011 A. Smith

Private Citizen

4432 November 21, 2011 M. Leitch

Private Citizen

4433 November 21, 2011 J. Kirkpatrick

Private Citizen

4434 November 19, 2011 E. Paulsworth

Private Citizen

4435 November 21, 2011 F. Harkins

Private Citizen

4436 November 18, 2011 M. Rose

Private Citizen

4437 November 18, 2011 S. Edwards

Private Citizen

4438 November 19, 2011 R. Menke

Private Citizen

4439 November 18, 2011 K. Gresham

Private Citizen

4440 November 18, 2011 C. Lehman

Private Citizen

4441 November 18, 2011 P. Jordan

Private Citizen

4442 November 18, 2011 P. Yingst

Private Citizen

4443 November 21, 2011 C. Mac Low

Private Citizen

4444 November 18, 2011 M. Ibarra

Private Citizen

4445 November 21, 2011 R. Freriks

Private Citizen

4446 November 21, 2011 P. Bordenet

Private Citizen

4447 November 21, 2011 C. Valdez

Private Citizen

4448 November 18, 2011 J. Wilkinson

Private Citizen

4449 November 21, 2011 W. Pruess

Private Citizen

4450 November 21, 2011 J. Blaisdell

Private Citizen

4451 November 21, 2011 C. Rutherford

Private Citizen

4452 November 21, 2011 D. Campbell

Private Citizen
625

EPA-HQ-OAR-2010-0505

Document ID Date Submitted Name and Affiliation (number of commenters)

4453 November 21, 2011 R. Hilgenberg

Private Citizen

4454 November 21, 2011 E. Greding

Private Citizen

4455 November 21, 2011 M. Hogan

Private Citizen

4456 December 13, 2011 Lou D'Amico

Pennsylvania Independent Oil and Gas Assoc

4457 November 30, 2011 Devorah Ancel

Sierra Club et al. (Part 1 of 7)

4458 November 30, 2011 Devorah Ancel

Sierra Club et al. (Part 2 of 7)

4459 November 30, 2011 Devorah Ancel

Sierra Club et al. (Part 3 of 7)

4460 November 30, 2011 Devorah Ancel

Sierra Club et al. (Part 4 of 7)

4461 November 30, 2011 Devorah Ancel

Sierra Club et al. (Part 5 of 7)

4462 November 30, 2011 Devorah Ancel

Sierra Club et al. (Part 6 of 7)

4463 November 30, 2011 Devorah Ancel

Sierra Club et al. (Part 7 of 7)

4467 January 6, 2012 Clean Air Council mass comment campaign (33)

4468 January 30, 2012 Craig Holt Segall

Sierra Club Environmental Law Program et al.

4469 February 15, 2012 William C. Allison V

Colorado Department of Public Health and 

Environment (Supplemental comment to 4191)

4471 February 17, 2012 Craig Holt Segall

Sierra Club Environmental Law Program et al.

4472 March 7, 2012 Elizabeth Ames Jones

Railroad Commission of Texas

4472 October 25, 2011 Railroad Commission of Texas

4475 November 30, 2011 Sierra Club