Response to Public Comments on 

Greenhouse Gas Reporting Rule:

2014 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems

`
November 2014

Response to Public Comments on the Greenhouse 

Gas Reporting Rule: 2014 Revisions and 

Confidentiality Determinations for Petroleum and 

Natural Gas Systems

U. S. Environmental Protection Agency

Office of Atmospheric Programs

Climate Change Division

Washington, D.C.

`
FOREWORD

This document provides EPA’s responses to public comments on the Revisions and 

Confidentiality Determinations for Petroleum and Natural Gas Systems. The EPA published a 

Notice of Proposed Rulemaking in the Federal Register on March 10, 2014 (79 FR 13394). 

The proposed amendments were designed to correct ambiguities or minor inconsistencies in 

greenhouse gas monitoring, calculation, and reporting requirements; amend monitoring and 

quality assurance methods to provide flexibility for certain facilities; clarify certain terms and 

definitions, and make other corrections identified as a result of working with the affected sources 

during rule implementation and outreach. In conjunction with this action, we proposed 

confidentiality determinations for the new and substantially revised (i.e., requiring additional or 

different data to be reported) data elements contained in these amendments and proposed to 

revise the confidentiality determination for one existing data element. 

During the 45-day public comment period, EPA received comment letters from industry 

representatives and associations, environmental organizations, and private citizens in response to 

the March 10, 2014 proposal. This document provides EPA’s responses to the significant public 

comments regarding these proposals. The verbatim text of each comment extracted from the 

original comment letters is included in this document, arranged by subject. For each comment, 

the name and affiliation of the commenter, the document control number (DCN) assigned to the 

comment letter, and the number of the comment excerpt are provided. Where possible, EPA 

separated comments on specific topics into their respective data categories. However, in some 

cases, commenters made broad statements about the proposed amendments to subpart W or 

general comments on the approach that could not be easily separated by topic or data category 

without potentially affecting the intended meaning of the commenter’s statements. In such cases, 

we either repeated the comment excerpt in its entirety in each of the relevant sections of this 

document or referred the reader to the response to another similar comment. 

EPA’s responses to comments are generally provided immediately following each comment 

excerpt. In some cases, 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, EPA has referenced the preamble to the final rule. In some cases, a commenter 

incorporated by reference the comments of another company or organization. Rather than repeat 

these comment excerpts for each commenter, EPA has listed the comment excerpt only once 

under the name of the person, company or organization who submitted the comment and 

included a list of commenters who indicated their support for that comment in a footnote. Copies 

of all comment letters submitted are available at the EPA Docket Center Public Reading Room 

or electronically through http://www.regulations.gov by searching Docket Id. No. EPA-HQOAR-2011-0512.

iii
The primary contact regarding questions or comments on this document is:

Carole Cook (202) 343-9263

U.S. Environmental Protection Agency

Office of Atmospheric Programs

Climate Change Division

Mail Code 6207-A

1200 Pennsylvania Avenue, NW

Washington, D.C. 20460

For technical information, contact the Greenhouse Gas Reporting Rule Hotline at: 

http://www.epa.gov/ghgreporting/contactus.html.

iv
TABLE OF CONTENTS

Page

FOREWORD ....................................................................................................................iii

List of Commenters..........................................................................................................ix

Acronyms and Abbreviations........................................................................................... x

1.0 General Comments................................................................................................. 1

2.0 Revisions to Provide Consistency Throughout Subpart W................................ 5

2.1 Revisions for the consistency of the units of measure for reporting .............................5

2.2 Definition of onshore petroleum and natural gas production........................................5

2.3 Definition of sub-basin category ...................................................................................8

3.0 Natural Gas Pneumatic Device Venting............................................................... 9

3.1 Use of site-specific gas composition data for natural pneumatic devices in revisions 

to Eqn. W-1 .................................................................................................................9

3.2 Comments on other minor revisions and restructuring of reporting requirements for 

natural gas pneumatic device venting........................................................................10

4.0 Acid Gas Removal Vents...................................................................................... 10

5.0 Dehydrators........................................................................................................... 12

5.1 Minor Revisions to Calculation Methods (e.g., accounting for venting to vapor 

recovery or flare).......................................................................................................12

5.2 Comments on other minor revisions and restructuring of reporting requirements for 

dehydrators................................................................................................................15

6.0 Well Venting for Liquids Unloading .................................................................. 18

6.1 Revisions to Calculation Method 1 to allow for annualizing venting data (Equations 

W-7A and W-7B) ......................................................................................................18

6.2 Revisions to Calculation Method 1 and 2 to separate calculation of emissions from 

wells with plunger lifts and wells without plunger lifts............................................21

6.3 Revisions to term "SPp"ed (well shut-in pressure or surface pressure) of Equation W8 .................................................................................................................................22

6.4 Comments on other minor revisions and restructuring of reporting requirements for 

well venting for liquids unloading.............................................................................22

v
Table of Contents (Continued)

Page

7.0 Gas Well Completions and Workovers with Hydraulic Fracturing................ 24

7.1 Comments on proposed definitions for "reduced emissions completion," "reduced 

emissions workover," and "well completions"..........................................................24

7.2 Revisions to Equations W-10A and W-10B................................................................27

7.3 Clarifications to §98.233(g)(1) and (g)(2)...................................................................29

7.4 Comments on other minor revisions and restructuring of reporting requirements for 

gas well completions and workovers with hydraulic fracturing................................32

8.0 Gas Well Completions and Workovers Without Hydraulic Fracturing......... 36

9.0 Blowdown Vents................................................................................................... 37

9.1 Revisions to Equations W-14A and W-14B to add a compressibility term (includes 

harmonizing changes to Equations W-33 and W-34)................................................37

9.2 Revisions to require reporting of aggregated blowdown emissions (in lieu of by 

"unique physical volume") ........................................................................................50

9.3 Optional calculation method where a flow meter is in use on a blow down vent -

proposed §98.233(i)(3)..............................................................................................55

9.4 Comments on other minor revisions and restructuring of reporting requirements for 

blowdown vents.........................................................................................................56

10.0 Onshore Production Storage Tanks ................................................................... 56

11.0 Transmission Storage Tanks............................................................................... 58

11.1 Revisions to methods for quantifying emissions from the tank vapor vent stack .....58

11.2 Comments on other minor revisions and restructuring of reporting requirements for 

onshore transmission condensate storage tanks ........................................................59

12.0 Well Testing Venting and Flaring....................................................................... 60

13.0 Associated Gas Venting and Flaring .................................................................. 61

14.0 Flare Stack Emissions .......................................................................................... 63

15.0 Centrifugal and Reciprocating Compressors .................................................... 65

15.1 Comments on proposed requirements for conducting volumetric emissions 

measurements for centrifugal or reciprocating compressors vented to common 

manifold or flare ........................................................................................................65

15.2 Proposed definitions for "compressor mode", compressor source", "manifolded

compressor source", and "manifolded group of compressor sources" ......................76

15.3 Revisions to calculation and reporting of emissions for compressors routed to a flare79

15.4 Revisions to 3-year cycle requirement, schedule to measure compressors in the notoperating-depressurized mode, & schedule to measure compressors in the operating 

mode ..........................................................................................................................80

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Table of Contents (Continued)

Page

15.5 Use of as found leak measurements to develop reporter emission factors in 

Equations W-23 and W-28. .......................................................................................96

15.6 Comments on other minor revisions and restructuring of reporting requirements for 

centrifugal and reciprocating compressors................................................................99

15.7 Comments on emission factor approach for compressors.......................................128

15.8 Other comments on issues not proposed related to centrifugal and reciprocating 

compressors.............................................................................................................135

16.0 Leak Detection Equipment and Emissions from Components ......................145

16.1 Revisions to §98.233(q) and (r) and calculation of facility meter/regulator run 

emission factor.........................................................................................................145

16.2 Calculation of emissions from above grade transmission-distribution (T-D) transfer 

stations.....................................................................................................................145

16.3 Calculation of emissions from below grade Emissions from below grade metering 

regulating stations, below grade transmission-distribution transfer stations, 

distribution mains, and distribution services. ..........................................................149

16.4 Comments on applicable definitions and other minor revisions and restructuring of 

reporting requirements for leak detection and emissions from components...........150

17.0 Calculation of GHG Emissions from Natural Gas Volume Emissions .........155

17.1 Comments on the use of default or site-specific gas composition ..........................155

17.2 Comments on the need to use “actual” versus “standard” conditions.....................159

18.0 Onshore Petroleum and Natural Gas Production and Natural Gas 

Distribution Combustion Sources.....................................................................161

19.0 Revisions to Missing Data Provisions...............................................................162

19.1 Revisions to §98.235 to specify the use, treatment, and reporting of missing data 162

19.2 Provisions for newly acquired wells or sources..................................................183

20.0 Best Available Monitoring Methods.................................................................186

20.1 Removal of BAMM requirements for 2015 and beyond.........................................186

20.2 Requests for transitional BAMM for 2015..............................................................198

20.3 Dehydrators .............................................................................................................202

21.0 General Revisions to Reporting Requirements (including addition of new 

reporting elements).............................................................................................208

22.0 Confidentiality Determinations and Data Category Assignments for New or 

Revised Data Elements.......................................................................................218

22.1 EPA’s Approach to confidentiality determinations and data category assignments 

for new or revised data elements.............................................................................218

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Table of Contents (Continued)

Page

22.2 Comments on proposed confidentiality determinations for data elements that are not 

inputs to emission equations....................................................................................219

22.3 Comments on evaluation of inputs to emissions equations for new or revised data 

elements...................................................................................................................233

22.4 Concerns related to exploratory wells.....................................................................236

23.0 Impacts of the Proposed Amendments.............................................................252

24.0 Out of Scope Comments: General Comments Outside of the Scope of the 

Amendments .......................................................................................................262

viii
List of Commenters

Document Control Number Commenter Name Commenter Affiliation

EPA-HQ-OAR-2011-0512-0069 Kathleen McNeil None

EPA-HQ-OAR-2011-0512-0070 D. E. Ortman None

EPA-HQ-OAR-2011-0512-0071 Anonymous 

Commenter

None

EPA-HQ-OAR-2011-0512-0072 Gary W. Smith None

EPA-HQ-OAR-2011-0512-0073-A1 Pamela Faggert Dominion Resources Services, Inc.

EPA-HQ-OAR-2011-0512-0074-A1 Bert Kalisch American Public Gas Association

EPA-HQ-OAR-2011-0512-0075 Charlotte Lewis None

EPA-HQ-OAR-2011-0512-0076-A1 Kelly Guertin DTE Energy

EPA-HQ-OAR-2011-0512-0077-A1 Thomas J. Bach Kinder Morgan Energy Partners, 

L.P

EPA-HQ-OAR-2011-0512-0078-A1 Thure Cannon Texas Pipeline Association (TPA)1

EPA-HQ-OAR-2011-0512-0079-A1 Ritu Talwar Spectra Energy Corp

EPA-HQ-OAR-2011-0512-0080-A1 Carrie B. Crumpton CONSOL Energy, Inc.

EPA-HQ-OAR-2011-0512-0081-A1

through -A6

Lisa Beal Interstate Natural Gas Association 

of America (INGAA)1

EPA-HQ-OAR-2011-0512-0082-A1 Eldon Lindt Xcel Energy, Inc. 2

EPA-HQ-OAR-2011-0512-0083-A1 Pamela Lacey American Gas Association 

(AGA)2

EPA-HQ-OAR-2011-0512-0084-A2 Karin Ritter American Petroleum Institute 

(API) 3

EPA-HQ-OAR-2011-0512-0085-A2 V. Bruce 

Thompson

American Exploration & 

Production Council (AXPC)4

EPA-HQ-OAR-2011-0512-0086-A2 Darrell R. Johnson Southern California Gas Company 

(SoCal Gas)1

EPA-HQ-OAR-2011-0512-0087-A2 Brian Korpics Environmental Defense Fund5

EPA-HQ-OAR-2011-0512-0089-A2

and -A3

Jeff Applekamp Gas Processors Association 

(GPA)1,3

EPA-HQ-OAR-2011-0512-0091-A2 Glen Jasek Williams Partners, LP

1 The comments by INGAA were also supported by the Texas Pipeline Association (Docket Id. No. EPA-HQ-OAR2011-0512-0078-A1), Southern California Gas Company (Docket Id. No. EPA-HQ-OAR-2011-0512-0086-A2), and 

Gas Processors Association (Docket Id. No. EPA-HQ-OAR-2011-0512-0089-A2).

2 The comments by American Gas Association (AGA) were also supported by Xcel Energy, Inc. (Docket Id. No. 

EPA-HQ-OAR-2011-0512-0082-A1).

3 The comments by American Petroleum Institute (API) were also supported by the Gas Processors Association 

(Docket Id. No. EPA-HQ-OAR-2012-0934-0089-A2).

4 The comments submitted by V. Bruce Thompson of the American Exploration & Production Council (AXPC) 

represent the comments from AXPC and the Western Energy Alliance.

5 The comments submitted by Brian Korpics of the Environmental Defense Fund represent the comments from 

Environmental Defense Fund, Clean Air Task Force, Earthjustice, Natural Resources Defense Council, and Sierra 

Club.

ix

 
Acronyms and Abbreviations

AGA American Gas Association

API American Petroleum Institute

ARP Acid Rain Program

AXPC American Exploration & Production Council 

BAMM best available monitoring methods

bbl barrels

CAA Clean Air Act

CBI confidential business information

CFR Code of Federal Regulations

CH4 methane

CO2 carbon dioxide

CO2e carbon dioxide equivalent

DR designated representative

EPA U.S. Environmental Protection Agency

FERC Federal Energy Regulatory Commission

FR Federal Register

GHG greenhouse gas

GHGRP Greenhouse Gas Reporting Program

GHGRR Greenhouse Gas Reporting Rule

GOR gas to oil ratio

GPA Gas Processors Association

GWP global warming potential

INGAA Interstate Natural Gas Association of America

IR infrared

LNG liquefied natural gas

mmBtu million British thermal units

MMscf million standard cubic feet

N2O nitrous oxide

NAICS North American Industry Classification System

NESHAP National Emission Standards for Hazardous Air Pollutants

NGL natural gas liquids

NOD not-operating-depressurized

x
NSPS New Source Performance Standards

NSR New Source Review

NTTAA National Technology Transfer and Advancement Act

OMB Office of Management and Budget

psig pound per square inch gauge

QA/QC quality assurance/quality control

REC reduced emissions completion

RFA Regulatory Flexibility Act

scf standard cubic feet

SoCal Gas Southern California Gas Company

T-D transmission-distribution

T&S transmission and storage

TPA Texas Pipeline Association

TSD Technical Support Document

U.S. United States

xi
1.0 General Comments 

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 3

Comment: Starting with the 2009 proposed rule, there have been ten Subpart W rulemakings in 

less than five years. This does not include other GHGRP amendments related to the Subpart A 

general provisions and Subpart C combustion equipment that also affect Subpart W facilities. 

The sheer number of rulemakings is unprecedented in our experience with numerous air quality 

regulations over several decades. In previous Subpart W comments, INGAA recommended a 

delayed or staged implementation approach to address the challenges evident in earlier versions 

of the rule. The iterative rulemaking process needed to support the initial years of Subpart W 

implementation appear to confirm the validity of INGAA’s request.

To support Subpart W improvement, INGAA has expended extraordinary effort over the last five 

years. In addition to the commenting on multiple rulemakings, EPA has provided additional 

material to EPA. For example, in 2011 INGAA provided a quick response to EPA requests to 

recommend Subpart W revisions related to errors and lack of clarity in the compressor emission 

sections. Unfortunately, EPA failed to respond to this requested material in the two late 2011 

rulemakings, and the material was re-submitted in subsequent INGAA comments4

.

Despite these challenges, INGAA remains committed to providing constructive comments and 

working with EPA to improve Subpart W. Although there have been numerous Subpart W 

rulemakings, the Proposed Rule is the first substantive revision of compressor-related emission 

estimation issues since the 2010 re-proposal. Several issues remain that have been longstanding 

concerns.

INGAA comments in response to primary Subpart W rulemakings are referenced within these 

comments and provided as attachments, including:

• Docket document number EPA-HQ-OAR-2008-0508-0480.1; INGAA June 9, 2009 

comments in response to April 10, 2009 GHGRP Proposed Rule (Attachment 1);

• Docket document number EPA-HQ-OAR-2009-0923-1039; INGAA June 11, 2010 

comments in response to the April 12, 2010 Proposed Subpart W Rule which significantly 

revised the original 2009 Subpart W proposal (Attachment 2);

• Docket document number EPA-HQ-OAR-2011-0147-0029; INGAA September 19, 2011 

comments in response to August 4, 2011 Proposed Subpart W Amendments (Attachment 3);

• Docket document number EPA-HQ-OAR-2011-0512-0029; INGAA October 24, 2011 

comments in response to September 9, 2011 Proposed Subpart W Amendments (Attachment 

4);

1
• Docket document number EPA-HQ-OAR-2011-0147-0047; INGAA June 20, 2012 

comments in response to May 21, 2012 Proposed Subpart W Amendments (Attachment 5).

Footnotes:

4 "INGAA Comments Regarding the Proposed Rule, Mandatory Reporting of Greenhouse Gases, 

dated September 9, 2011; Attachment 2," EPA-HQ-OAR-2011-0512-0029 (October 24, 2011).

Response: The EPA appreciates the commenter's concern regarding the ongoing development 

of the subpart W requirements for calculating and reporting GHG emissions. During the 

development of subpart W, the EPA has proposed and finalized rulemakings that establish and 

improve the reporting methods of this subpart. The 2014 proposed rule amendments (79 FR 

13394, March 10, 2014), further improve reporting methods for subpart W and address many of 

issues identified by the commenter and other stakeholders. However, the EPA is not addressing 

comments on prior Subpart W rulemakings in this final rule, as these comments are beyond the 

scope of the revisions and clarifications included in this rulemaking. The EPA appreciates the 

commenter's continued commitment to subpart W. The EPA has considered and, where 

appropriate, revised the proposed rule to address the comments on the proposed amendments and 

the additional data provided during the public comment period, as discussed in this document

and in the preamble to the final rule. 

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 1

Comment: We appreciate EPA's response to concerns regarding calculation methodologies and 

definitions. EPA has made several changes that will assist reporters in providing consistent and 

accurate data by making clarifying and simplifying changes to calculations and inputs without 

significantly increasing the reporting burden. Several proposed changes will clarify or simplify 

calculations and provide consistency throughout the rule by more closely aligning the calculation 

methods with the reporting requirements, more clearly identifying emission sources, and 

allowing sources alternative ways to address missing data.

Response: The EPA thanks the commenter for their support. The EPA has considered and, 

where appropriate, revised the proposed rule to address the comments on the proposed 

amendments and the additional data provided during the public comment period, as discussed in 

this document and in the preamble to the final rule.

Commenter Name: Charlotte Lewis

Commenter Affiliation:

Document Control Number: EPA-HQ-OAR-2011-0512-0075

Comment Excerpt Number: 1

2
Comment: I believe this proposed rule is of utmost importance given the need for more data 

concerning the quantity of methane emissions during the lifetime of a well. Methane (CH4) is a 

more potent greenhouse gas than carbon dioxide (CO2), though it has a shorter life span (12.4 

years) than CO2 (100 years) in the atmosphere. The Contribution of Working Group 1 to the 

Fifth Report of the Intergovernmental Panel on Climate Change indicates that the global 

warming potential (GWP) of CH4 is 86 in a 20-year span and 34 in a span of 100 years. NASA 

Goddard Institute of Space Studies scientists Drew T. Shindell, Greg Faluvegi, Dorothy M. 

Koch, Gavin A. Schmidt, Nadine Unger, and Susanne E. Bauer in "Improved Attribution to 

Climate Forcing to Emissions", an article in the American Association for the Advancement of 

Science online magazine in 2009, the GWP of CH4 in a 20-year span is 105, and in 100 years, 

33. According to James Hansen, Makiko Sato, Pushker Kharecha, Gary Russell, David W Lea, 

and Mark Siddal (“Climate change and trace gases.” Philosophical Transactions of the Royal 

Society (2007): 1925-1928. Web.), CH4 is responsible for 40% more positive radiative forcing in 

the atmosphere due to causing tropospheric ozone (O3) emissions in the troposphere and water 

vapor in the stratosphere.

To keep methane emissions and other short-lived greenhouse gas emissions from throwing 

humanity beyond the 2 degree Celsius tipping point established by the 16th Session of the Parties 

to the U.N. Framework on Climate Change, there needs to be transparency concerning how 

much of these emissions are being released into the atmosphere. The confidentially 

determinations and removal of the “Best Available Monitoring Methods” with refined 

measurement methodology as proposed in the rule, will sufficiently do so. And based on what 

research has been done, particularly by The National Oceanic and Atmospheric Administration 

and the University of Colorado, the levels of methane from natural gas production are offsetting 

its lesser CO2 emissions during burning, and derailing climate change mitigation.

According to the Energy Information Administration's “Annual Energy Outlook 2013”, shale-gas 

production is projected to grow 113% by 2040. In any swiftly growing industry, scientific 

research and legislative protection of performing research, should be at the forefront to ensure 

the safety of human and other species' communities. This rule proposal is essential to the United 

States, the world's second highest producer of greenhouse gases (according to the Energy 

Information Administration). If we are to meet the Intergovernmental Panel on Climate Change's 

emission targets, data on methane emissions must be transparent. The consequences from this 

potent greenhouse gas are enormous, on a world-wide scale if left unchecked.

Please pass the Environmental Protection Agency Proposed Rule: Greenhouse Gas Reporting: 

Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems.

Response: The EPA thanks the commenter for their support. The EPA has considered and, 

where appropriate, revised the proposed rule to address the comments on the proposed 

amendments and the additional data provided during the public comment period, as discussed in 

this document and in the preamble to the final rule.

Commenter Name: Gary W. Smith

Commenter Affiliation:

Document Control Number: EPA-HQ-OAR-2011-0512-0072

Comment Excerpt Number: 1

3
Comment: It is neither rational, reasonable nor prudent that the level of intrusive reporting 

contained in the proposed update to 40 CFR Part 98 be imposed on an already over-burdened 

industry that is effectively the only engine of economic success currently operating within the 

United States. By its very nature, the detail imposed by this change will add operating expense to 

provide the data on gasses, the very nature of which is not scientifically established as 

detrimental to the nation nor the world, in fact, the opposite by their very nature. I urge you to 

suspend this update and reconsider the negative impact of the entire concept that has been 

implemented by such regulatory acts.

Response: The EPA thanks the commenter for their input and appreciates the commenter's 

concern over the complexity and burden of the subpart W requirements for calculating and 

reporting GHG emissions. However, the overall approach of estimating and reporting GHG 

emissions for subpart W is driven in part by the goal of providing flexibility to accommodate the 

needs of a number of different reporters. The 2014 proposed rule amendments (79 FR 13394, 

March 10, 2014), further improve reporting methods for subpart W and address many of issues 

identified by various stakeholders. In many cases, the revisions that are being made reduce the 

burden on those facilities required to report GHG emissions. The EPA has considered and, where 

appropriate, revised the proposed rule to address the comments on the proposed amendments and 

the additional data provided during the public comment period, as discussed in this document 

and in the preamble to the final rule.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 21

Comment: For the reasons API describes herein, and in its November 29, 2013 comments, if 

unchanged, the issues API raised will result in requirements that are overly burdensome, harmful 

to industry, infeasible to implement, and constitute arbitrary and capricious decision making. 

While API supports the bulk of EPA’s proposed revisions, we respectfully request that EPA 

address the specific issues outlined here, in the final rule, to avoid arbitrary and capricious 

action.

Response: The EPA appreciates the concerns expressed by the commenter as well as their 

support for many on the proposed rule revisions. We strongly disagree with the commenter that 

the final rule constitutes arbitrary and capricious decision making. The EPA has considered and, 

where appropriate, revised the proposed rule to address the comments on the proposed 

amendments and the additional data provided during the public comment period, as discussed in 

this document and in the preamble to the final rule.

4
2.0 Revisions to Provide Consistency Throughout Subpart W

2.1 Revisions for the consistency of the units of measure for reporting

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 2

Comment: Changes in the units of measure for emissions reporting will lead to less confusion 

and easier inter-comparisons with other sectors, without introducing inconsistent conversion 

calculation methodologies. EPA is proposing to require reporting in units of metric tons of 

methane, carbon dioxide, and nitrous oxide instead of the current units of their carbon dioxide 

equivalent (CO2e) of these constituents. This proposed change is intended to increase 

consistency between the reporting requirements for Subpart W and the rest of the Mandatory 

Reporting Rule which generally require reporting in terms of the individual GHGs rather than 

their CO2e. We support this proposed change.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 1

Comment: Proposed EPA Amendment: Revise the reporting of GHG emissions in Subpart W 

from metric tons of CO2e of each reported GHG to metric tons of the individual GHG.

Williams supports the proposed amendment, as it aligns Subpart W with other subparts of Part 

98 with respect to GHG reporting. It also affects a more meaningful comparison of GHG 

emissions between reporting years where global warming potentials are different.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

2.2 Definition of onshore petroleum and natural gas production

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 3

5
Comment: Several definitions are proposed to be changed or added to provide needed clarity to 

the rule. The changes in definitions will clarify and provide consistency going forward in our 

understanding of these terms. The definition of “onshore petroleum and natural gas production” 

is proposed to be changed to clarify the equipment types that are covered by the rule. We support 

these changes that provide needed clarity.

Response: The EPA thanks the commenter for their support. The EPA is finalizing the 

definition of “onshore petroleum and natural production” with minor revisions. See Section 

II.A.2 of the preamble to the final rule for additional information.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 4

Comment: Onshore Production Source Category: API supports EPA’s proposal to revise the 

source category definition of onshore petroleum and natural gas production found at 40 C.F.R. 

98.230(a)(2) to improve the clarity of the emission sources in onshore petroleum and natural gas 

production to which the reporting requirements apply. Specifically, API supports the removal of 

non-transportation related equipment from the source category definition.

Response: The EPA thanks the commenter for their support. The EPA is finalizing the 

definition of “onshore petroleum and natural production” with minor revisions. See Section 

II.A.2 of the preamble to the final rule for additional information.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 43

Comment: Revisions to §98.230: EPA is proposing to revise the definition of the onshore 

petroleum and natural gas production source category. 

API supports the removal of “auxiliary non-transportation related equipment”, which API 

requested in comments on the September 9, 2011 proposed amendments to Subpart W. However, 

the revisions to the language include the addition of “maintenance and repair equipment” in the 

list of portable non-self propelled equipment.

Based on the current rule language, maintenance and repair equipment is not included in the 

onshore production industry segment because this equipment is not directly used in the 

production, extraction, recovery, lifting, stabilization, separation, or treating of petroleum and 

natural gas. This is supported by the description of stationary and portable fuel combustion 

equipment at 40 CFR 98.232(c)(22) as follows:

6
Stationary or portable equipment are the following equipment, which are integral to the 

extraction, processing, or movement of oil or natural gas: well drilling and completion 

equipment, workover equipment, natural gas dehydrators, natural gas compressors, electrical 

generators, steam boilers, and process heaters.

Also, tracking and reporting emissions from combustion equipment used for maintenance and 

repair purposes, such as welding machines and pressure washers, would be burdensome in terms 

of time and effort required to maintain logs of this equipment, and provide little benefit due to 

the relatively small emissions from these sources in comparison to the equipment that is integral 

to the drilling and production operation, such as the prime movers. Therefore, EPA should 

remove the reference to maintenance and repair equipment in the definition of onshore petroleum 

and natural gas production.

As an example of the small contribution these units make to overall emissions, emissions from

maintenance equipment were tracked for one onshore well site during RY2012. This well site 

performed drilling activities during the entire reporting year. Over the year, the well site tracked 

engine runtimes on 170 pieces of equipment that came on the well pad. There were 16 pieces of 

equipment that would be considered “maintenance and repair,” including welding machines, 

pressure washers, and stormwater pumps, representing 9% of the total combustion equipment 

tracked. These 16 maintenance and repair engines were small in terms of HP rating, the largest of 

which had a HP rating of 41 and the average size of 22 hp. Additionally, the average time spent 

onsite was only 16 days out of the year with an average runtime of 53 hours. Total GHG 

emissions from these units equaled 10.7 tonnes CO2e, in comparison to the total emissions of 

8974.4 tonnes CO2e that this well site contributed to the basin. Consequently, tracking these 16 

additional engines over the very brief time periods they were onsite only increased emissions by 

0.12%.

API urges EPA to remove the addition of “maintenance and repair equipment” from the list of 

portable non-self propelled equipment as this equipment is not use in the production, extraction, 

recovery, lifting, stabilization, separation, or treating of petroleum and natural gas. This 

equipment is frequently moved between well sites, such that even tracking the count of this 

equipment is extremely burdensome with no relative benefit to improving emissions estimation.

Response: The EPA is removing the reference to “maintenance and repair equipment” from the 

source category definition for the onshore petroleum and natural gas production segment in this 

final rule. See Section II.A.2 of the preamble to the final rule for additional discussion 

responding to this comment.

Commenter Name: V. Bruce Thompson

Commenter Affiliation: American Exploration & Production Council (AXPC)

Document Control Number: EPA-HQ-OAR-2011-0512-0085-A2

Comment Excerpt Number: 9

Comment: AXPC and the Alliance request that EPA reconsider the inclusion of maintenance 

and repair equipment in the portable combustion source category. As has been clearly stated in 

7
the rule since initially promulgated, the portable emissions are required to be reported are limited 

to those that are involved in the extraction of hydrocarbons. The extension of this source 

category, which is already one of the most challenging reporting categories in terms of third 

party data collection efforts, is unjustified and in conflict with what EPA initially intended to be 

reported. As such we request that EPA remove “maintenance and repair equipment” from the 

§98.230(2) definition of the onshore production sector.

Response: The EPA is removing the reference to “maintenance and repair equipment” from the

source category definition for the onshore petroleum and natural gas production segment in this 

final rule. See Section II.A.2 of the preamble to the final rule for additional discussion 

responding to this comment.

2.3 Definition of sub-basin category

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 42

Comment: (§98.230) Revised definition for Sub-basin category: Sub-basin category, for 

onshore natural gas production, means a subdivision of a basin into the unique combination of 

wells with the surface coordinates within the boundaries of an individual county and subsurface 

completion in one or more of each of the following five formation types: Oil, high permeability 

gas, shale gas, coal seam, or other tight gas reservoir rock. The distinction between high 

permeability gas and tight gas reservoirs shall be designated as follows: High permeability gas 

reservoirs with >0.1 millidarcy permeability, and tight gas reservoirs with ≤0.1 millidarcy 

permeability. Permeability for a reservoir type shall be determined by engineering estimate. 

Wells that produce only from high permeability gas, shale gas, coal seam, or other tight gas 

reservoir rock are considered gas wells; gas wells producing from more than one of these 

formation types shall be classified into only one type based on the formation with the most 

contribution to production as determined by engineering knowledge. All wells that produce 

hydrocarbon liquids (with or without gas) and do not meet the definition of a gas well in this subbasin category definition are considered to be in the oil formation. All emission sources that 

handle condensate from gas wells in high permeability gas, shale gas, or tight gas reservoir rock 

formations are considered to be in the formation that the gas well belongs to and not in the oil 

formation.

API supports these revisions.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

8
3.0 Natural Gas Pneumatic Device Venting

3.1 Use of site-specific gas composition data for natural pneumatic devices in 

revisions to Eqn. W-1

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 4

Comment: Proposed EPA Amendment: For natural gas pneumatic devices in the onshore 

natural gas transmission, compression, and underground storage segment, allow the use of either 

site-specific data on gas composition, or the default gas composition (95 percent CH4 and 1 

percent CO2).

Williams supports the proposed amendment because it allows reporters the option of using sitespecific (versus mandatory default) gas composition data.

Response: The EPA thanks the commenter for their support. The EPA is finalizing revisions to 

allow natural gas transmission compression and underground natural gas storage facilities the 

option to use either site-specific composition data or to use a default gas composition to calculate 

emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural gas 

pneumatic devices. See Sections II.B.1 and II.B.13 of the preamble to the final rule for additional 

discussion responding to this comment.

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 8

Comment: Natural Gas Pneumatic Device Venting. The calculation method used for natural 

gas pneumatic device venting is proposed to be changed to expand the use of site-specific data 

for gas composition, if available. This proposal is similar to the one discussed above, but is 

specific to the determination of pneumatic device venting. Currently, a default gas composition 

of 95% methane and 1% carbon dioxide is used in the calculations. This change would allow for 

a more accurate emissions estimate, if site-specific information is available; however, the current 

default provides a conservative estimate and the additional cost of conducting gas analysis where 

data is not available is not justified. EPA has specifically requesting comment on whether or not 

the use of site-specific gas composition data for calculating emissions should be mandatory or

optional and requests specific details on when a facility would not have site-specific data 

available. Gas composition information is maintained by most natural gas companies only to the 

extent needed to document compliance with the specifications in the FERC tariff. Most 

companies, including ours, do not maintain site-specific gas compositions at each station and the 

logistics and cost of conducting additional gas analysis will increase the program costs. We 

9
request the agency not make the use of site-specific gas composition mandatory because the 

default value of 95% methane and 1% carbon dioxide is conservative in that most gas 

compositions that are significantly different than the default would have a lower CO2e than that 

of the default composition. We request that the rule allow the option of using site-specific gas 

composition if it is available and, if not, to continue to use the default composition.

Response: The EPA is finalizing revisions to allow natural gas transmission compression and 

underground natural gas storage facilities the option to use either site-specific composition data 

or to use a default gas composition to calculate emissions from continuous high bleed, 

continuous low bleed, and intermittent bleed natural gas pneumatic devices. See Section II.B.1

and II.B.13 of the preamble to the final rule for additional discussion responding to this 

comment.

3.2 Comments on other minor revisions and restructuring of reporting 

requirements for natural gas pneumatic device venting

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 30

Comment: Pneumatic device reporting: In 98.236(b), it appears that EPA is removing the 

requirement to report information separately for each pneumatic controllers type (continuous 

high bleed, continuous low bleed, intermittent bleed), and is instead requesting that all 

information from all three categories be lumped together. This seems like a backwards step in 

data collection and, given the current high interest in pneumatic controllers in oil and gas sector 

studies and by the EPA in NSPS OOOO White Papers, it seems illogical for EPA to stop 

collecting this device-type-specific information. It appears that EPA may be unsure if the data is 

being collected as a total or per device type as the proposed rule text at 98.236(b) says, “you 

must report the information specified in paragraphs (b)(1) through (b)(4) of this section” while 

the memorandum entitled “Revisions to the Subpart W Reporting Requirements as proposed in 

the Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems; Proposed Rule” says, “you must report the information 

specified in paragraphs (b)(1) through (b)(4) of this section for each device type.” (emphasis 

added).

Response: The EPA agrees with the commenter. It was not our intent to collect aggregated data 

for each type of pneumatic controller and the proposed rule text is incorrect. As such, the EPA 

has revised §98.236(b) in the final rule to clarify that the data must be reported for each device 

type.

4.0 Acid Gas Removal Vents

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

10
Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 93

Comment: Acid gas removal (AGR) vents Revisions to §98.233(d)(10): EPA proposes to revise 

paragraph (10) as indicated: (10) Calculate annual mass CO2 emissions at standard conditions 

Mass CO2 emissions shall be calculated from volumetric CO2 emissions using calculations in 

paragraph (v) of this section.

The reference to standard conditions is not relevant for mass emissions. EPA has in fact 

corrected previous rule language similar to this proposed change (refer to Federal Register / Vol. 

76, No. 247 / Friday, December 23, 2011: Mandatory Reporting of Greenhouse Gases: Technical 

Revisions to the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting 

Rule – Final Rule, page 80559, modifications to Equation W-1). The proposed text revisions to 

this paragraph are not necessary and should not be included in the final rule.

Response: The EPA agrees with the commenter that the reference to standard conditions is not 

relevant for mass emissions. We have revised §98.233(d)(10) to read as follows in the final rule: 

“Calculate annual mass CO2 emissions using calculations in paragraph (v) of this section.”

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 94

Comment: Proposed Citation Reference: Acid Gas Removal §98.236(d)(1)(vi), Proposed Rule 

Text: Sub-basin ID (for the onshore petroleum and natural gas production industry segment 

only).

It is not clear if this requirement refers to the AGR unit itself or the wells that supply gas to the 

unit. “Sub-basin” is the designated Basin, county and formation combination. Reporting the 

formation type is not relevant for surface equipment, particularly since very few AGR units are 

not treating co-mingled gas streams. API requests that EPA drop this as a reporting element. If 

EPA insists on keeping this reporting requirement, the reporter should be able to select a single 

sub-basin ID that best represents the wells that supply gas to the unit.

Response: It was the EPA’s intent to gather the sub-basin ID for wells that supply gas to the 

AGR unit to improve verification of reported emissions. The EPA agrees with the commenter 

that it may be unclear how the requirement would apply to AGR units that treat co-mingled gas 

streams. Therefore, we have revised §98.236(d)(1)(vi) to clarify that the reporter may select the 

sub-basin ID that best represents the wells that supply gas to the unit.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

11
Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 19

Comment: Acid gas removal vent transferred offsite: EPA revised the reporting requirement 

98.236(d)(1)(iv) (citation in the proposed rule) such that if any emissions from the AGR unit 

were recovered and transferred outside of the facility, this quantity must be reported under 

Subpart W. We oppose this change as this quantity is already reported under Subpart PP, making 

this reporting requirement redundant, which wastes time and effort by reporters.

Response: The commenter is correct that subpart W required reporters to report the annual 

quantity of CO2 that was recovered from the AGR unit and transferred outside the facility under 

subpart PP. The EPA inadvertently omitted the clause “under subpart PP of this part” at the end 

of this paragraph in the proposed amendments. In the final rule, the EPA is clarifying in 

§98.236(d)(1)(iv) that the annual quantity of CO2 that was recovered from the AGR unit and 

transferred outside the facility must be reported under subpart PP. This is consistent with the 

historical reporting of recovered CO2 quantities from AGR units and prevents duplicative 

reporting of the recovered CO2 quantities under both subparts W and PP. 

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 5

Comment: Proposed EPA Amendment: For acid gas removal (AGR) vents, revise Equations 

W-4A and W-4B to clarify that the volumetric fractions of CO2 in natural gas flowing into / out 

of the AGR be annual averages.

Williams currently calculates the annual average for these variables and supports the proposed, 

clarifying amendment.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

5.0 Dehydrators

5.1 Minor Revisions to Calculation Methods (e.g., accounting for venting to 

vapor recovery or flare) 

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 5

12
Comment: EPA is proposing to revise estimation methodologies for dehydration units and 

blowdown vents. EPA is proposing to revise the dehydrator vent source estimations by adjusting 

the emissions calculation to account for venting to a vapor recovery system or a flare. This 

would result in a more accurate emissions determination for these sources. We support these 

changes which will result in a more accurate emissions determination for these sources.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 46

Comment: Dehydrator vents, Revisions to §98.233(e)(5): EPA proposes to include provisions 

to adjust emissions downward where dehydrator vents are routed to a vapor recovery system.

Comment: API supports this revision for dehydrators owned and operated by the reporter.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 47

Comment: Dehydrator vents, Revisions to §98.233(e): EPA proposes editorial revisions to 

clarify the calculation methods for desiccant dehydrators. This includes reordering paragraphs 

(3), (4), and (5) to make it more clear the emissions from desiccant dehydrators are also adjusted 

where emissions are routed to a VRU or flare.

API supports these revisions.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 16

13
Comment: Incorrect terminology for dehydrators: EPA proposes various changes to dehydrator 

terminology. For example, in the current rule, 98.233(e)(1) reads “Calculation Methodology 1. 

Calculate annual mass emissions from dehydrator vents with annual average daily throughput 

greater than or equal to 0.4 million standard cubic feet per day using a software program...” In 

the proposed rule, EPA proposes to change this to “Calculation Method 1. Calculate annual mass 

emissions from absorbent dehydrators that have an annual average of daily natural gas 

throughput that is greater than or equal to 0.4 million standard cubic feet per day by using a 

software program...” [emphasis added]. EPA does not explain why this change was made, and 

it’s unclear if EPA is trying to include equipment other than glycol dehydrators. With no 

supporting explanation, we assume that EPA is merely changing terminology and not changing 

the scope of equipment covered here. If this is indeed the case, EPA should not use the term 

“absorbent dehydrator”. This is not a term used by industry, it is not defined in the rule, and it 

may cause confusion with desiccant dehydrator requirements as they do use an absorbent. We 

propose the following language changes:

98.233(e)(1) Calculation Method 1. Calculate annual mass emissions from absorbent glycol

dehydrators that have an annual average of daily natural gas throughput that is greater than or 

equal to 0.4 million standard cubic feet per day by using a software program... 

98.233(e)(6)(i) Use the dehydrator vent volume and gas composition as determined in 

paragraphs (e)(1) or (e)(2) of this section for absorbent glycol dehydrators. Use the dehydrator 

vent volume and gas composition as determined in paragraphs (e)(3) and (e)(4) of this section 

for dehydrators that use desiccant. 

98.236(e) Dehydrators. You must indicate whether your facility contains any of the following 

equipment: absorbent glycol dehydrators with an annual average daily natural gas throughput 

greater than or equal to 0.4 million standard cubic feet per day, glycol dehydrators with an 

annual average daily natural gas throughput less than 0.4 million standard cubic feet per day, 

and dehydrators that use desiccant. If your facility contains any of the equipment listed in this 

paragraph (e), then you must report the applicable information in paragraphs (e)(1) through 

(e)(3). 

98.236(e)(1) For each absorbent glycol dehydrator that has an annual average daily natural gas 

throughput greater than or equal to 0.4 million standard cubic feet per day (as specified in § 

98.233(e)(1)), you must report the information specified in paragraphs (e)(1)(i) through 

(e)(1)(xviii) 

Response: We proposed these revisions primarily to clarify that the 0.4 million standard cubic 

feet (MMscf) per day throughput relates to the natural gas throughput of the dehydrator for 

determining the applicability of Calculation Method 1, not the throughput of the vent itself. The 

EPA agrees with the commenter that the terminology “absorbent dehydrators” may cause 

confusion since desiccant dehydrators use an absorbent. We have revised §98.233(e)(1) and 

§98.236(e) and (e)(1) to clarify that these provisions apply to “glycol dehydrators”. We have also 

revised §98.233(e)(6)(i) to read “Use the dehydrator vent volume and gas composition as 

determined in paragraphs (e)(1) through (e)(5) of this section, as applicable”, so this paragraph 

no longer uses the term “absorbent dehydrators”. See Section II.B.3 of the preamble to the final 

rule for additional discussion responding to this comment.

14
5.2 Comments on other minor revisions and restructuring of reporting 

requirements for dehydrators

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 96

Comment: Proposed Citation Reference for Dehydrators: §98.236(e)(1)(xviii), Proposed Rule 

Text: Sub-basin ID (for the onshore petroleum and natural gas production industry segment 

only).

It is not clear if this requirement refers to the dehydrator itself or the wells that supply gas to the 

unit. “Sub-basin” is the designated Basin, county and formation combination. Reporting the 

formation type is not relevant for surface equipment, particularly since very few dehydrators are 

not treating co-mingled gas streams. API requests that EPA drop this as a reporting element. If 

EPA insists on keeping this reporting requirement, the reporter should be able to select a single 

sub-basin ID that best represents the wells that supply gas to the dehydrator.

Response: It was the EPA's intent to gather the sub-basin ID for wells that supply gas to the 

dehydrator to improve verification of reported emissions. The EPA agrees with the commenter 

that it may be unclear how the requirement would apply to dehydrators that treat co-mingled gas 

streams. Therefore, we have revised §98.236(e)(1)(xviii) to clarify that the reporter may select 

the sub-basin ID that best represents the wells that supply gas to the unit.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 17

Comment: Dehydrator emissions reporting – control devices for large dehys. 98.236(e)(1)(xvii) 

does not seem to contemplate dehydrator emissions that are routed to vapor recovery. While 

98.236(e)(xv) includes the "yes-or-no" reporting element of "Whether any dehydrator emissions 

are vented to a vapor recovery device", there is no emissions reporting requirement that 

contemplates this scenario. The following changes are suggested:

98.236(e)(1)(xvii) Whether any dehydrator emissions are vented to the atmosphere without being 

routed to a flare or regenerator firebox/fire tubes or to a vapor recovery device. If any emissions 

are not routed to a flare or regenerator firebox/fire tubes or to a vapor recovery device, then you 

must report the information specified in paragraphs (e)(1)(xvii)(A) and (e)(1)(xvii)(B) of this 

section for those emissions from the dehydrator. 

15
98.236(e)(1)(xvii)(A) Annual CO2 emissions, in metric tons CO2, for the dehydrator when not 

venting to a flare or regenerator firebox/fire tubes or vapor recovery device, calculated 

according to § 98.233(e)(1), and (e)(5), and (e)(6) as applicable. 

98.236(e)(1)(xvii)(B) Annual CH4 emissions, in metric tons CH4, for the dehydrator when not 

venting to a flare or regenerator firebox/fire tubes or vapor recovery device, calculated 

according to § 98.233(e)(1), and (e)(5), and (e)(6) as applicable. 

Response: The commenter may have misinterpreted the reporting requirements in 

§98.236(e)(1)(xvii). The emissions required to be reported in §98.233(e)(1)(xvii)(A) and (B) are 

to be corrected to account for recovery as provided in §98.233(e)(5), so the reported emissions 

will not include emissions associated with vapors that are recovered. We intentionally require 

reporting under §98.233(e)(1)(xvii) for all emissions not routed to a flare or regenerator 

firebox/fire tubes to ensure all units report emissions. If a facility recovers all vapors not routed 

to a flare or regenerator firebox/fire tubes, then the facility would report “0” (zero) for their 

emissions in §98.233(e)(1)(xvii)(A) and (B). Reporting in this way helps in the verification 

process to distinguish between facilities that may have inadvertently not reported emissions and 

facilities that have no uncontrolled atmospheric emissions from their dehydrators.

We have not included the commenter's reference to §98.233(e)(6); §98.233(e)(6) refers to 

calculation of annual emissions from dehydrator vents routed to a flares or regenerator firebox/fire tubes. These emissions are reported under §98.236(e)(1)(xvi). We believe that the 

description of the emissions to be reported §98.233(e)(1)(xvii) clearly indicates the emissions to 

be reported in the §98.236(e)(1)(xvi) (A) and (B) are to exclude emissions that are routed to a 

flares or regenerator fire-box/fire tubes.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 32

Comment: Dehydrator emissions reporting – future e-GGRT issues: 98.236(e)(2)(iii) says, 

“...If any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a control 

device other than a vapor recovery device or a flare or regenerator firebox/fire tubes, then you 

must specify the type of control device and the number of dehydrators at the facility that were 

vented to each type of control device.” Note that EPA will need to program this into e-GGRT as 

a blank text field to be populated by the reporter; historically, these types of blank text fields 

have been avoided by EPA. In addition, the three types of control (vapor recovery, flare, 

regenerator) should cover the vast majority of vented emissions that are controlled.

Response: The EPA thanks the commenter for their input. The EPA will consider this comment 

in future implementations of e-GGRT.

16
Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 33

Comment: Dehydrator emissions reporting – failure to account for multiple emission points: 

For the reporting requirements for small dehydrators in 98.236(e)(2), EPA fails to account for the 

fact that sometimes a single dehydrator can have multiple emission points and that these 

emission points are often handled differently (e.g., one vent may be routed to vapor recovery 

while another vent may be routed to flare). The following changes are therefore needed, and they 

also conform with 98.236(e)(1). Because the same dehydrator can have different means 

of emissions routing, we encourage EPA to consider whether or not the reporting requirements 

for small glycol dehydrators need to be changed at all.

98.236(e)(2)(ii) Whether any dehydrators reported in paragraph (e)(2)(i) of this section

dehydrator emissions were vented to a vapor recovery device. If any dehydrators reported in 

paragraph (e)(2)(i) of this section dehydrator emissions were vented to a vapor recovery device, 

then you must report the total number of dehydrators at the facility that vented to a vapor 

recovery device. 

98.236(e)(2)(iii) Whether any dehydrators reported in paragraph (e)(2)(i) of this section

dehydrator emissions were vented to a control device other than a vapor recovery device or a 

flare or regenerator firebox/fire tubes. If any dehydrators reported in paragraph (e)(2)(i) of this 

section dehydrator emissions were vented to a control device other than a vapor recovery device 

or a flare or regenerator firebox/fire tubes, then you must specify the type of control device and 

the number of dehydrators at the facility that were vented to each type of control device. 

98.236(e)(2)(iv) Whether any dehydrators reported in paragraph (e)(2)(i) of this section

dehydrator emissions were vented to a flare or regenerator firebox/fire tubes. If any dehydrators 

reported in paragraph (e)(2)(i) of this section dehydrator emissions were vented to a flare or 

regenerator firebox/fire tubes, then you must report the information specified in paragraphs 

(e)(2)(iv)(A) through (e)(2)(iv)(D) of this section. 

98.236(e)(2)(v) For dehydrators reported in paragraph (e)(2)(i) of this section dehydrator 

emissions that were not vented to a flare or regenerator firebox/fire tubes, report the 

information specified in paragraphs (e)(2)(v)(A) and (e)(2)(v)(B) of this section. 

Additionally, the proposed language further confuses possible operating scenarios in 

98.236(e)(2)(v)(A) and (B), as well as in 98.236(e)(3)(ii) and (iii). These requirements reference 

calculations that only account for vapor recovery. However, the reporting requirement applies 

broadly to any dehydrator emissions that were not vented to a flare or regenerator firebox/fire 

tubes. In other words, if an alternative control device is used (as contemplated in 

98.236(e)(2)(iii)), there is no emissions reporting requirement that accounts for such a 

configuration. Again, we encourage EPA to consider whether or not the reporting requirements 

for small glycol dehydrators and desiccant dehydrators need to be changed at all.

17
Response: The EPA agrees with the commenter that the proposed reporting requirements did 

not account for small dehydrators routed to multiple emission points. We have revised 

§98.233(e)(2)(ii) through (v) as suggested by the commenter.

We are clarifying in this response that we intended for the emissions reported in 

§98.236(e)(1)(xvii)(A) and (B), (e)(2)(v)(A) and (B), and (e)(3)(ii) and (iii) would not include 

emissions that are routed to a flare or regenerator firebox/fire tubes. We consider the language in 

the introductory paragraphs in §98.236(e)(1)(xvii) and (e)(2)(v) as well and the language in 

(e)(3)(ii) and (iii) to clearly indicate that the emissions reported according to these requirements 

do not include emissions routed to a flare or regenerator firebox/fire tubes even though the 

emissions calculated according §98.233(e)(1) through (e)(5) do not directly adjust for the portion 

of the emissions that are routed to a flare or regenerator firebox/fire tubes.

We are not amending the reporting requirements to adjust the emissions for control systems other 

than vapor recovery systems, flares or regenerator firebox/fire because we have not provided a 

calculation methodology for these emissions under §98.233(e). If a significant number of “other 

control systems” are reported, the EPA may consider amendments in a future rulemaking to 

account for these alternate configurations.

6.0 Well Venting for Liquids Unloading

6.1 Revisions to Calculation Method 1 to allow for annualizing venting data 

(Equations W-7A and W-7B)

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 49

Comment: Well venting for liquids unloading: Revisions to §98.233(f)(1): EPA is proposing to 

modify the requirements for liquids unloading to accommodate the revisions requested by API to 

address situations where it is not possible to gather vent hours and the number of unloadings 

from January 1st to December 31st.

API supports these revisions.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 76

18
Comment: Monitoring and QA/QC requirements: Revisions to §98.234(h): EPA is proposing to 

add a new paragraph addressing the monitoring period for liquids unloading:

For well venting for liquids unloading, if a monitoring period other than the full calendar year is 

used to determine the cumulative amount of time in hours of venting for each well (the term 

“Tp” in Equation W-7A and W-7B of § 98.233) or the number of unloading events per well (the 

term “Vp” in Equations W-8 and W-9 of § 98.233), then the monitoring period must begin 

before February 1 of the reporting year and must not end before December 1 of the reporting 

year. The end of one monitoring period must immediately precede the start of the next 

monitoring period for the next reporting year. All production days must be monitored and all 

venting accounted for.

API supports this revision which relates to changes made in §98.233(f)(1).

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 3

Comment: Well Venting for Liquids Unloading: API supports EPA’s proposal to revise the 

calculation and reporting requirements for well venting from liquids unloading to allow for 

annualizing venting data for facilities that calculate emissions using a flow meter (Calculation 

Method 1).

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 50

Comment: Well venting for liquids unloading:

Revisions to §98.233(f)(1): EPA is proposing to revise Equation W-7 (Equation W-7A in the 

proposed rule) to pull the average flow rate term (FR) outside the summation.

This revision makes the equation consistent with the definition of FR, which is the average flow 

rate for all measured wells of the same tubing diameter and pressure group combination in a subbasin. Note, however, the flowrate for FR is defined as being in actual conditions. Industry 

19
practice is to measure gas flow rates in standard conditions. In addition, Equation W-7 is 

inconsistent with Equations W-8 and W-9 which both result in emissions at standard conditions. 

API requests that Equation W-7 be revised to reflect that the FR term and the resulting emissions 

are in standard conditions.

Response: The EPA is clarifying in the introductory text at §98.233 and §98.236 that the use of 

systems that automatically correct to standard conditions is allowed. This allows reporters that do 

measure actual volumes to use the equations as presented, but it allows reporters that determine 

flow volumes at standard conditions to use these measurements directly. See Section II.B.13 of 

the preamble to the final rule for additional discussion responding to this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 18

Comment: Gas Flow Rate Measurements. In discussions with EPA, API has emphasized the 

need to use industry standard conditions for gas flow and volume measurements. API urges EPA 

to revise the terms for Equations W-3, W-4A, W-4B, W-7, W-17A, W-17B, W-39A, and W-39B 

to reflect that measured or estimated gas volumes used in these equations and the resulting 

emissions are in standard conditions. This is particularly the case for Equation W-34 because it 

makes no sense to take a gas flow rate already determined in standard conditions to convert it to 

actual conditions just to apply a required estimation methodology which, in turn, will again 

convert it back to standard conditions per the rule requirements.

Response: The EPA is clarifying in the introductory text at §98.233 and §98.236 that the use of 

systems that automatically correct to standard conditions is allowed. This allows reporters that do 

measure actual volumes to use the equations as presented, but it allows reporters that determine 

flow volumes at standard conditions to use these measurements directly. See Section II.B.13 of 

the preamble to the final rule for additional discussion responding to this comment.

Commenter Name: Carrie B. Crumpton

Commenter Affiliation: CONSOL Energy, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0080-A1

Comment Excerpt Number: 7

Comment: Requiring the conversion of gas flow rates from "standard conditions" to "actual 

conditions" when applying required estimation methodology is burdensome and overly 

complicated. These estimations then have to be converted back into standard conditions for 

reporting under the regulatory requirements. Since instrumentation used in the industry typically 

measures gas flow rates in standard conditions, CONSOL request the EPA to revise Equations 

W-3, W-4A, W-4B, W-7, W-17A, W-17B, W-34, W-39A, and W-39B to reflect that the 

20
measured gas volumes and/or estimated gas volumes used in these equations, and the resulting 

emissions, are in standard conditions to better meet reporting requirements and consistency.

Response: The EPA is clarifying in the introductory text at §98.233 and §98.236 that the use of

systems that automatically correct to standard conditions is allowed. This allows reporters that do 

measure actual volumes to use the equations as presented, but it allows reporters that determine 

flow volumes at standard conditions to use these measurements directly. See Section II.B.13 of 

the preamble to the final rule for additional discussion responding to this comment.

6.2 Revisions to Calculation Method 1 and 2 to separate calculation of 

emissions from wells with plunger lifts and wells without plunger lifts

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 48

Comment: Well venting for liquids unloading: Revisions to §98.233(f)(1): EPA proposes to 

separate the calculation and reporting of emissions from wells that have plunger lifts and wells 

that do not. This applies to Calculation Method 1.

“...For any tubing diameter group and pressure group combination in a sub-basin where liquids 

unloading occurs both with and without plunger lifts, Equation W-7A will be used twice, once 

for wells with plunger lifts and once for wells without plunger lifts.”

API supports the added transparency provided by this revision.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Brian Korpics

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2011-0512-0087-A2

Comment Excerpt Number: 7

Comment: A variety of analyses have utilized Subpart W data to help deepen understanding of 

emissions from the oil and gas sector, including the Annual Inventory of U.S. Greenhouse Gas 

Emissions and Sinks and efforts by academics and other researchers to assess emissions, which 

have provided essential independent information about emissions from this sector. We 

specifically support many of the proposed revisions to Subpart W—listed below—that would 

enhance the ability of the public and policy makers to use the data in future contexts like these. 

We also respectfully suggest additional changes that would support these important goals.

21
• Well venting for liquids unloading. EPA has also proposed helpful changes regarding liquids 

unloading.22 In particular, the provisions will result in more disaggregated data and facilitate 

a better understanding of the factors affecting emissions from wells with and without plunger 

lifts. EPA’s revised description of the reporting requirements is also much clearer.

Footnotes:

22 Fed. Reg. at 13,398–99.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

6.3 Revisions to term "SPp"ed (well shut-in pressure or surface pressure) of 

Equation W-8

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 51

Comment: Well venting for liquids unloading, Revisions to §98.233(f)(2): EPA is proposing to 

modify the term SPp in Equation W-8 to provide an alternative method for determining the 

casing pressure: If casing pressure is not available for each well, you may determine the casing 

pressure by multiplying the tubing pressure of each well with a ratio of casing pressure to tubing 

pressure from a well in the same sub-basin for which the casing pressure is known. The tubing 

pressure must be measured during gas flow to a flow-line. The shut-in pressure, surface pressure, 

or casing pressure must be determined just prior to liquids unloading when the well production is 

impeded by liquids loading or closed to the flow-line by surface valves.

API supports the added flexibility provided by this revision.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

6.4 Comments on other minor revisions and restructuring of reporting 

requirements for well venting for liquids unloading 

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 97

Comment: Proposed Citation Reference for Liquids Unloading: §98.236(f)(1)(xi) and 

(f)(1)(xi)(A), Proposed Rule Text: (xi) For each well tubing diameter group and pressure group 

combination, you must report the information specified in paragraphs (f)(1)(xi)(A) through 

22
(f)(1)(xi)(E) of this section for each individual well not using a plunger lift that was tested during 

the year. (A) API number of tested well.

API opposes reporting the API well number for tested wells as this is not directly relevant to 

quantifying emissions.

Response: The EPA is requiring the reporting of API Well Numbers for tested wells to improve 

data quality by enabling identification of these wells. The API number of the tested well provides 

state, county, and location information that informs the verification and characterization of 

reported data. Collection of this data will allow the EPA to link the GHGRP data to other 

databases to more easily match the data reported under the GHGRP with other data sources. This 

data element is similar to the data collected under other subparts of Part 98 which is useful for 

verification and characterization of reported data. For these reasons, EPA is retaining the 

requirement to report API Well Numbers for tested wells in the final rule.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 98

Comment: Proposed Citation Reference: §98.236(f)(1)(xii) and (f)(1)(xii)(A), Proposed Rule 

Text: (xii) For each well tubing diameter group and pressure group combination, you must report 

the information specified in paragraphs (f)(1)(xii)(A) through (f)(1)(xii)(E) of this section for 

each individual well using a plunger lift that was tested during the year. (A) The API well 

number.

API opposes reporting the API well number for tested wells as this is not directly relevant to 

quantifying emissions

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 97.

Commenter Name: Brian Korpics

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2011-0512-0087-A2

Comment Excerpt Number: 8

Comment: We respectfully urge the Agency to make liquids unloading data more usable by 

requiring reporting of the total number of unloading events in methods 2 and 3.23 Currently, 

these two methods only report the number of venting wells in each sub-basin category, and this 

data cannot be used to estimate average emissions per unloading event or average venting 

frequency per well.

23 40 C.F.R. § 98.236.

23
Response: The EPA thanks the commenter for their suggestion. Previously, the reporting of the 

cumulative number of unloadings vented to the atmosphere was deferred. In the 2014 proposed 

amendments at §98.236(f)(2)(v), we proposed to require the reporting of the cumulative number 

of unloading events vented to the atmosphere for each well, aggregated across all wells for each 

sub-basin for which Calculation Method 2 or 3 was used. According to the proposed requirement 

at §98.236(f)(2), reporters are required to report this aggregate number of unloading events 

separately for each calculation method. Therefore, the proposed rule already addresses the 

commenter’s issue; we are finalizing these revisions are proposed.

7.0 Gas Well Completions and Workovers with Hydraulic Fracturing

7.1 Comments on proposed definitions for "reduced emissions completion," 

"reduced emissions workover," and "well completions"

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 1

Comment: Definitions of Well Completions and Workovers: API generally supports EPA’s 

proposal with respect to gas well completions and workovers. Specifically, API supports the 

proposal to amend the definition of “well completions” to delete the term “re-fracture” where 

this term applies to an already producing well and is considered a well workover, not a well 

completion for the purposes of part 98. This revision will avoid confusion regarding whether a 

re-fracture is a completion or a workover in the context of Subpart W.

Response: The EPA thanks the commenter for their support. The EPA is finalizing the 

definition of “well completions” in §98.6 to delete the term "re-fracture" as proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 35

Comment: (§98.6) EPA is proposing to revise the definition of well completions. Well 

completions means the process that allows for the flow of petroleum or natural gas from newly 

drilled wells to expel drilling and reservoir fluids and test the reservoir flow characteristics, steps 

which may vent produced gas to the atmosphere via an open pit or tank. Well completion also 

involves connecting the well bore to the reservoir, which may include treating the formation or 

installing tubing, packer(s), or lifting equipment, steps that do not significantly vent natural gas 

to the atmosphere. This process may also include high rate flowback of injected gas, water, oil, 

and proppant used to fracture or re-fracture and prop open new fractures in existing lower 

24
permeability gas reservoirs, steps that may vent large quantities of produced gas to the 

atmosphere.

In addition to activities that are either part of a well “completion” or “workover”, there are many 

activities that are merely “routine operations / surveillance / maintenance” that are conducted on 

a well with the production tree installed after the initial completion or workover event. For many 

activities, the timing of the action is what causes an activity to be classified as either a 

“completion” or a “workover.” If the operation is done during the original drilling, it is a 

“completion.” If it is done at some point later on a well that is already producing12, it is a 

“workover.” In order to improve the clarity of the classifications of well-site activities, API 

requests the following amendments to the definitions of “completions” and “workover” in 40 

CFR §98.6 to improve clarity and ensure consistency with definitions the industry is using under 

other regulatory programs:

Well completions mean the process of making a new oil or natural gas well ready for 

production. It that allows for the flow of petroleum or natural gas from newly drilled wells to 

expel drilling and reservoir fluids and test the reservoir flow characteristics steps which may vent 

produced gas to the atmosphere via an open pit or tank. Well completion and also involves 

connecting the well bore to the reservoir, which may include treating the formation or installing 

tubing, packer(s), or lifting equipment. steps that do not significantly vent natural gas to the 

atmosphere. This process may also include high-rate flowback of injected gas, water, oil,

fracture fluids and some proppant along with formation fluids such as oil, gas and produced 

water. used to fracture or re-fracture and prop open new fractures in existing lower permeability 

gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere. Venting 

or flaring of gas may also occur during this process.

Well workover means the work conducted on already producing wells with a rig or coiled tubing 

unit after the initial completion is over. Such process(es) of may include performing one or more 

of a variety of remedial operations on producing petroleum and natural gas wells to try to 

increase production or return the well to its normal production rate. This process also includes 

high-rate flowback of injected fracture fluids and some proppant along with formation fluids 

such as oil, gas, and produced water gas, water, oil, and proppant used to re-fracture and propopen new fractures in existing low permeability gas reservoirs or recomplete and existing well to 

a new production zone/horizon. Venting or flaring of gas may also occur during this process.

A well workover does not include routine maintenance activities that are performed on the well 

with the tree installed (See 30 CFR Part 250.601 Definitions for further details). Such routine 

activities may include maintenance, repair, or replacement of equipment such as rods, pumps, 

tubing, packers, or other mechanical devices.

Footnotes:

12 Refer to EPA’s response to V. Bruce Thompson of the American Exploration & Production 

Council in the Subpart W Response to Comments Part 2, dated November 2010 (page 1698), 

Comment Number: EPA-HQ-OAR- 2009-0923-1040-17.

25
Response: The EPA is finalizing the definition of “well completions” in §98.6 to delete the term 

"re-fracture" as proposed. As discussed in the preamble to the proposed rule at 70 FR 13399, the 

term “re-fracture” only applies to well workovers, so we only intended to remove this improper 

reference to “re-fracture” in the proposed revision. The commenter’s suggested revisions for 

“well completion” appear to be a complete re-write of the definition and, as such, goes beyond 

the scope of the proposed revisions. This significant re-write of the definition would need to go 

through full public review and comment. Therefore, we are not making any additional revisions 

to the definition of “well completions” based on these comments. The EPA did not propose to 

revise the definition of “well workovers”. As such, the suggested revisions to the definition of 

“well workovers” comment is beyond the scope of this rulemaking. We are not amending the 

definition of “well workovers” in this final rule. 

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 40

Comment: (§98.238) New definition for Reduced Emissions Completion (REC). Reduced 

emissions completion means a well completion following hydraulic fracturing where gas 

flowback that is otherwise vented is captured, cleaned, and routed to the flow line or collection 

system, re-injected into the well or another well, used as an on-site fuel source, or used for other 

useful purpose that a purchased fuel or raw material would serve, with no direct release to the 

atmosphere.

EPA is proposing to use the same regulatory definition for well completions as currently used for 

40 CFR Part 60 Subpart OOOO (Quad O). However, Quad O contains additional provisions that 

expand the definition and EPA has issued guidance (See attached letter to Matt Todd from Peter 

Tsirigotis dated September 28, 2012)13 clarifying this definition for Quad O to include brief 

periods of venting and to include flaring of flowback gas, but has not yet codified those changes. 

API’s understanding is that the pending revisions to Quad O will address this issue in a manner 

similar to what is proposed below.

As proposed, the Subpart W definition would result in no RECs reported due to the phrase “no 

direct release to the atmosphere”. API has explained to EPA on numerous occasions that there is 

a small amount of gas released during the initial flowback before sufficient gas to operate a 

separator is available. In addition, the Subpart W definition does not provide for flaring to occur 

on wells with REC. EPA has modified the calculation approach for completions and workovers 

with hydraulic fracturing in this proposed rule to address the small amount of venting during 

initial flowback and provides provisions for flaring associated with gas well completions and 

workovers. Therefore, EPA must also modify the definition for reduced emission completions.

API urges EPA to adopt these revisions for Subpart W.

“Reduced emissions completion (REC) means a well completion following hydraulic fracturing 

where gas flowback emissions from the gas outlet of the separator that is are otherwise 

vented is are captured, cleaned, and routed to the flow line or collection system, re-injected into 

26
the well or another well, used as an on-site fuel source, or used for other useful purpose that a 

purchased fuel or raw material would serve, with minimal no direct venting release to the 

atmosphere. Short periods of flaring during a REC may occur.”

Footnotes:

13 API references the additional guidance contained in the letter to Matt Todd (API) from Peter 

Tsirigotis (EPA), dated September 28, 2012.

Response: The EPA revising the definitions of “reduced emissions completion” and “reduced 

emissions workover” to clarify the venting and flaring activities that may occur as suggested by 

the commenter. See Section II.B.5 of the preamble to the final rule for additional discussion 

responding to this comment.

7.2 Revisions to Equations W-10A and W-10B

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 52

Comment: Well venting during completions and workovers with hydraulic fracturing:

Revisions to §98.233(g): EPA is proposing to modify Equation W-10A as requested by API to 

remove the sales gas term and to include an estimate for the initial cleanup stage of the flowback 

where there is insufficient gas. EPA is also proposing to modify the terms for FRMs to be based 

on the average flowback and PRs,p to be based on the average production flow. Equation W-10B 

is modified to include the estimated emissions for the initial cleanup stage of the flowback.

The proposed revisions accommodate the primary issues raised by API and API strongly 

supports these revisions. However, other issues remain with the equations for Calculation 

Method 2. API looks forward to continuing discussions with EPA on these issues.

Response: The EPA thanks the commenter for their support. The revisions to Equations W-10A 

and W-10B are being finalized as proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 101

Comment: Proposed Citation Reference for Completions and Workovers with Hydraulic 

Fracturing: §98.236(g)(5) and §98.236(g)(5)(i), Proposed Rule Text: (5) If you used Equation 

W-10A to calculate annual volumetric total gas emissions, then you must report the information 

specified in paragraphs (g)(5)(i)and (g)(5)(ii) of this section.

27
(i) Cumulative backflow time, in hours, for each sub basin (“Tp” in Equation W-10A).

Comment: In the proposed rule, Equation W-10A under 98.233(g) uses the terms Tp,s and Tp,i 

to refer to the cumulative times for the two stages of flowback represented in the equation. The 

reporting requirements here do not use the same terminology.

Response: The EPA agrees with the commenter that the terminology should be consistent 

between §98.233 and §98.236(g)(5)(i). We have revised §98.236(g)(5)(i) to clarify that facilities 

must report the flowback time after sufficient quantities of gas are present to enable separation. 

The first sentence in §98.236(g)(5)(i) reads as follows: “Cumulative flowback time, in hours, for 

each sub-basin, from when gas is first detected until sufficient quantities are present to enable 

separation, and the cumulative flowback time, in hours, for each sub-basin, after sufficient 

quantities of gas are present to enable separation (“Tp,i” and “Tp,s” in Equation W-10A).” 

Commenter Name: V. Bruce Thompson

Commenter Affiliation: American Exploration & Production Council (AXPC)

Document Control Number: EPA-HQ-OAR-2011-0512-0085-A2

Comment Excerpt Number: 6

Comment: AXPC and the Alliance appreciate EPA’s recognition that there are two distinct 

periods of flowback as defined by the rule. However, we do not support the addition of an 

emissions term in the equation for the period of flowback prior to separation. We strongly 

believe that emissions from this period are de minimus, as stated by EPA itself in their 

September 28, 2012 letter to API, stating that “Initially, the flowback consists of water, sand and 

fracturing fluids”. While there may be small amounts of entrained gas in the fluids that are 

returned to the surface prior to separation, the quantity is very small and not detectable. In 

practice, as soon as gas is detected it is routed to the separator for flaring or recovery, reducing 

the term Tp,i to zero and making that portion of the equation irrelevant and unnecessary. 

Additionally, if fluids are not able to be routed to the separator as soon as gas is detected then the 

volume of gas during that period will be far less than half of the post‐separation flow rate as the 

volume of gas will continue to increase during the initial stages of flowback. We urge EPA to 

remove these pre‐separation emission terms from equations W‐10A and W‐10B.

Response: The EPA has decided to retain the proposed calculation and reporting of preseparation emissions in Equations W-10A and W-10B. For cases where fluids are routed to the 

separator immediately upon first detection of gas, the equation correctly applies zero emissions 

to the initial flowback period. However, for cases where fluids are not immediately routed to the 

separator upon first gas detection, there are emissions associated with the initial flowback period 

that would not be accounted for without the initial flowback term. The commenter asserts that 

the volume of gas during the initial flowback period will be “...far less than half of the post‐

separation flow rate as the volume of gas will continue to increase during the initial stages of 

flowback”; however, the factor of one-half was added specifically to address this increase. The 

factor of one-half assumes this increase is linear over the period of initial gas detection to the 

time flowback is diverted to the separator. The commenter offered no data or alternative 

assumption that would provide a better estimate of the emissions during the initial flowback 

28
period. Consequently, the revisions to Equations W-10A and W-10B are being finalized as 

proposed. 

7.3 Clarifications to §98.233(g)(1) and (g)(2)

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 55

Comment: Well venting during completions and workovers with hydraulic fracturing, 

Revisions to §98.233(g)(2): EPA is proposing to expand the definition of well type combination.

A well type combination is a unique combination of the parameters listed in paragraphs (g)(2)(i) 

through (g)(2)(iii) of this section.

(i) Vertical or horizontal (directional drilling).

(ii) With flaring or without flaring.

(iii) Reduced emission completion/workover or not reduced emission completion/workover.

For reporters using Equation 10-A, the existing rule specifies the number of measurements 

required for each sub-basin and well type (vertical or horizontal) combination with a maximum 

number of combinations that need to be measured in each county of 10 (5 formation types and 

two well types). The proposed changes increase this theoretical number of combinations to 40 in 

each county (5 formation types X 8 possible combinations of well types). Coupled with the new 

requirement to measure or calculate completions and workovers separately in each subbasin/well-type combination the theoretical number of measurements or calculation

combinations is raised to 80 in each county. This effectively quadruples the number of potential

measurement or calculation requirements for completions or workovers, separately, in each

county. Additionally, whether a well will clean-up quickly with no need to flare or vent is not

able to be determined prior to beginning the actual flowback and cannot be a criteria for planning

which wells to measure or collect information to enable calculating the flowback volume.

Although full implementation of NSPS Quad O will sharply reduce the number of flowbacks

where gas is not flared and/or REC’s are not preformed (in January 2015), the exclusions

provided still render these options possible. Besides the obvious cost and burden implications of

quadrupling the number of possible combinations requiring measurement or calculation in each

county, this will be a scheduling nightmare for operators – particularly since prior determination

of whether a well will require flaring is not possible.

Recommendation 1: EPA should modify the proposed language as follows:

(2) The volume of CO2 or N2 injected into the well reservoir during energized hydraulic 

fractures will be measured using an appropriate meter as described in 98.234(b) or using receipts 

of gas purchases that are used for the energized fracture job. For paragraphs (g) introductory text 

and (g)(1) of this section, measurements and calculations are completed separately for workovers 

and completions per sub-basin and well type combination. A well type combination is a unique 

combination of the parameters listed in paragraphs (g)(2)(i) through (g)(2)(iii) of this section.

(i) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section.

29
(i) Vertical or horizontal (directional drilling).

(ii) [Reserved]With flaring or without flaring.

(iii) Reduced emission completion/workover or not reduced emission completion/workover.

Recommendation 2: To achieve transparency regarding the number of completions and

workovers that flare or not and that employ REC’s or don’t employ REC’s, EPA should expand

the reporting requirements in 98.236(g)(3) as follows:

• (3) Number of completions or workovers in the category.

• (i) Number of completions or workovers that employed a reduced emission completion 

(REC)

• (A) Number of completions or workovers that flared gas with no venting (excluding the

initial flowback period)

• (B) Number of completions or workovers that both flared gas and vented gas (excluding the 

initial flowback period)

• (C) Number of completions or workovers that vented gas with no flaring (excluding the

initial flowback period)

• (D) Number of completions or workovers that did not flare or vent gas (excluding the initial 

flowback period)

• (ii) Number of completions or workovers that did not employ a reduced emission completion

(REC)

• (A) Number of completions or workovers that flared gas with no venting (excluding the

initial flowback period)

• (B) Number of completions or workovers that both flared gas and vented gas (excluding the 

initial flowback period)

• (C) Number of completions or workovers that vented gas with no flaring (excluding the

initial flowback period) (D) Number of completions or workovers that did not flare or vent 

gas (excluding the initial flowback period)

Response: In the final rule, the EPA is maintaining the requirement to measure emissions by 

different combinations of activities (horizontal or vertical, with or without flaring, and with or 

without reduced emission completion/workovers) as proposed. See Section II.B.5 of the 

preamble to the final rule for additional discussion responding to this comment.

Commenter Name: V. Bruce Thompson

Commenter Affiliation: American Exploration & Production Council (AXPC)

Document Control Number: EPA-HQ-OAR-2011-0512-0085-A2

Comment Excerpt Number: 12

30
Comment: AXPC and the Alliance request that EPA reconsider the splitting up of reporting and 

measurement categories for the liquids unloading, well completions and workovers, associated 

gas venting and flaring, flare stacks, and desiccant dehydrator source categories. Reporters have 

established data collection and management systems based on the existing well type and other 

categories established by the existing rule and the proposed revisions would either double or 

quadruple the number of required measurements or calculations, input data management, and 

reporting requirements. AXPC does not object to reporting the number of sources that have the 

given characteristics for the existing categories, but objects to the creation of additional 

categories for data collection and reporting.

Response: In the final rule, the EPA is retaining the requirements as proposed to report the 

emissions based on the applicable groupings for the different sources listed by the commenter. 

The disaggregation of the data by these groupings will inform verification and analysis of the 

data and the EPA does not expect that the new requirements will impose a significant additional 

burden on reporters. See Section II.B.5 of the preamble to the final rule for additional discussion 

responding to this comment.

Commenter Name: Brian Korpics

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2011-0512-0087-A2

Comment Excerpt Number: 4

Comment: A variety of analyses have utilized Subpart W data to help deepen understanding of 

emissions from the oil and gas sector, including the Annual Inventory of U.S. Greenhouse Gas 

Emissions and Sinks and efforts by academics and other researchers to assess emissions, which 

have provided essential independent information about emissions from this sector.17 We 

specifically support many of the proposed revisions to Subpart W—listed below—that would 

enhance the ability of the public and policy makers to use the data in future contexts like these.

• Gas well completions and workovers. EPA has proposed to revise the requirements for 

completions and workovers with hydraulic fracturing to mandate the use of separate counts 

and separate emissions reporting for different well-type combinations.18 The separate welltype combinations are vertical or horizontal, with flaring or without, and utilizing a reduced 

emission completion/workover or not. These changes will result in more disaggregated data 

that will help distinguish emissions by well type and control technology. In addition to 

facilitating a better understanding of the factors affecting emissions, the proposed reporting 

requirements will increase the value of the data for use in the Annual Inventory of U.S. 

Greenhouse Gas Emissions and Sinks.

Footnotes:

17 See, e.g., David Allen et al., Measurements of methane emissions at natural gas production 

sites in the United States, 110 PNAS 17,768 (2013); A. R. Brandt et al., Methane Leaks from 

North American Natural Gas Systems, 343 SCI. 733 (2014).

31
18 79 Fed. Reg. at 13,399–40.

Response: The EPA thanks the commenter for their support. In the final rule, EPA is 

maintaining the requirement to measure emissions by different combinations of activities 

(horizontal or vertical, with or without flaring, and with or without reduced emission completion 

(or workovers)) as proposed. See Section II.B.5 of the preamble to the final rule for additional 

discussion responding to this comment.

7.4 Comments on other minor revisions and restructuring of reporting 

requirements for gas well completions and workovers with hydraulic 

fracturing

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 56

Comment: Well venting during completions and workovers with hydraulic fracturing:

Revisions to §98.233(g): EPA has replaced “backflow” with “flowback”.

API supports these changes.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 85

Comment: 98.236 (aa): Each facility must report the information specified in paragraphs (aa)(1) 

through (aa)(9) of this section, for each applicable industry segment, by using best available data. 

If a quantity required to be reported is zero, you must report zero as the value.

(1) For onshore petroleum and natural gas production, report the data specified in paragraphs 

(aa)(1)(i) and (aa)(1)(ii) of this section.

(i) Report the information specified in paragraphs (aa)(1)(i)(A) through (aa)(1)(i)(D) of this 

section for the basin as a whole.

(A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic 

feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. 

This does not include gas injected back into reservoirs or shrinkage resulting from lease 

condensate production.

32
The terms “vented” and “used in field operations” lack clarity and have not been described in 

any GHGRP or Subpart W documentation that API is aware of related to this requirement. API 

presumes that “used in field operations” means gas used on the well pad for fuel or pneumatic 

supply gas. The term “used in field operations” needs to be explicitly defined in the rule. API 

presumes that “vented” means gas vented by the source types requiring quantification and 

reporting under Subpart W.

Where produced gas volume is currently quantified and reported, it is an estimated volume. 

Quantification of gas produced is not currently required in all jurisdictions and where it is 

required the State oil and gas regulatory authority often defines the specific scope of what is 

included and in some instances the methodologies for estimation. For purposes of Subpart W, the 

requirement to report the produced gas volume should be removed. Should EPA want to estimate 

this volume, EPA can add the volume of gas associated with emissions reported into the GHGRP 

to the sales gas volume at the facility (basin) level.

Any expansion of the scope of items that need to be added to sales gas volumes to estimate 

produced gas volumes would require quantification of gas uses explicitly excluded from Subpart 

W quantification and reporting and would impose enormous burdens. Several examples that 

illustrate this problem follow:

• Venting during oil well flowbacks

• Volume of gas vented from equipment blowdowns

• Volume of gas combusted for process heaters <5mmBtu/hour

For each of these a reporter would be required to put the systems and processes in place to gather 

data and information on which to base an estimate of gas use, calculate an estimate of the volume 

of gas use, and then add this volume to the sales gas volume and the volume of gas used that is 

estimated elsewhere in Subpart W. This significantly expands the scope of the rule to include

sources explicitly excluded from the GHGRP or that are handled with counts of equipment such 

as externally fired heaters <5mmBtu/hr. API urges EPA to remove the requirement to report the 

volume of produced gas from the final rule.

Response: The EPA considers “vented” and “used in field operations” to be common terms that 

do not need to be further defined. The proposed rule language clearly requests a cumulative of all 

gas produced from the wells in a given basin and does not limit this value to vents or other 

releases that are specifically accounted for under subpart W. Reporting requirements by 

themselves do not obligate measurement systems to be installed. Through this response, EPA 

reinforces that position and confirms that using the best estimates to determine the quantity of 

gas produced from wells is adequate and allowed for this reporting requirement. The reporting 

requirements in §98.236(aa)(1)(i)(A) are being finalized as proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

33
Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 86

Comment: (B) The quantity of gas produced in the calendar year for sales, in thousand standard 

cubic feet. This requirement is fine as written.

Response: The EPA thanks the commenter for their support. This revision is finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 87

Comment: (C) The quantity of crude oil ratio, and best available estimate of produced in the 

calendar year for sales, not including lease condensates, in barrels.

(D) The quantity of lease condensate produced in the calendar year for sales, in barrels.

For sub-paragraphs (C) and (D), the term “lease condensate” has not been defined by the EPA 

under the GHGRP. There is a “condensate” definition in 98.238 but it is not specific enough to 

be applied to this reporting requirement and not consistent with what operators commonly term 

“condensate”. In addition, operators typically track and account hydrocarbon liquids produced on 

a well/lease as one category “crude and condensate”. Operators would have significant difficulty 

separating liquids production into crude oil and lease condensate. API recommends that 

§98.236(aa)(1)(i)(C) and (D) be collapsed into one reporting requirement as follows:

(C) The quantity of crude oil and condensate produced in the calendar year for sales, in barrels. 

With the revision suggested above, §98.236(aa)(1)(i)(D) should be eliminated.

Response: These proposed reporting requirements were intended to support verification and 

analysis of the reported data. The EPA has determined that an aggregate total will serve this 

purpose. Therefore, we are finalizing a reporting requirement for the quantity of crude oil and 

condensate in §98.236(aa)(1)(i)(C) and deleting the proposed paragraph §98.236(aa)(1)(i)(D) as 

suggested by the commenter. 

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 88

Comment: (ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through 

(aa)(1)(ii)(M) of this section for each unique sub-basin category.

(A) State.

34
(B) County.

(C) Formation type.

(D) The number of producing wells at the end of the calendar year.

(E) The number of producing wells acquired during the calendar year.

(F) The number of producing wells divested during the calendar year.

(G) The number of wells completed during the calendar year.

(H) The number of wells taken out of production during the calendar year.

It is not clear to API what the information required in items (ii) (A) thru (H) has to do with 

reporting of GHG emissions. It appears to API that EPA is attempting to construct a 

comprehensive count of wells in the U.S. with a great deal of specificity along with a 

comprehensive understanding of changes in the number of wells. API does not believe the 

GHGRP is the appropriate vehicle to gather this type of data. API also holds that the required 

information is not related to emissions reporting, and that requiring reporting of this information 

is an overreach of EPA’s authority. API urges EPA to remove these reporting requirements from 

the final rule.

Additionally, a well inventory parsed in the manner EPA is requiring is not information that an 

operator already tracks or has prepared. Requiring reporting of the information in items (ii) (A) 

thru (H) will impose a significant burden on reporters with no improvement or change in the 

quality of emissions data reported. API also notes that EPA has other avenues at its disposal to 

acquire the information - such as the commercial data systems such as DI-Desktop or the EIA’s 

information.

From a practical standpoint, a number of the requested items need to be clarified:

• (D) A count of wells that are actively producing at the end of the year may not be 

representative of the number of wells which contributed emissions to the annual estimate. For 

example, does this count exclude wells temporarily shut-in or experiencing downtime? Does 

this only exclude wells that were plugged and abandoned?

• (E) Does this refer to wells that were acquired and are now under operational control of the 

reporter as of 12/31 of the reporting year?

• (F) Does this refer to wells that were divested and are no longer under operational control of 

the reporter as of 12/31 of the reporting year?

• (G) The number of wells completed during the calendar year is reported elsewhere in the rule 

and redundant reporting here is not necessary.

• (H) Does this refer only to wells that were plugged and abandoned? What if they have been 

temporarily shut-in or temporarily abandoned?

35
Response: The EPA maintains the information listed by the commenters is needed to 

characterize and inform the EPA’s verification of the data. We disagree with the commenters 

that the information would be overly burdensome to collect. The EPA considers the reporting 

requirements to be fairly self-evident. We are clarifying in this response the answers to specific 

questions provided by the commenter. Well counts in (D) would include wells that are 

temporarily shut-in or experiencing downtime, but should exclude wells that are plugged or 

abandoned. Wells acquired during the calendar year in (E) would include all wells acquired 

during the calendar year, regardless of whether the reporter maintains operational control of the 

well as of 12/31 of the reporting year. Wells divested during the calendar year in (F) would 

include all wells that were in operational control of the reporter at some point during the calendar 

year but that are no longer under operational control of the reporter as of 12/31 of the reporting 

year. The number of wells taken out of production in (H) would include all wells permanently 

taken out of service (i.e., wells that are plugged and abandoned), but would not include wells that 

are temporarily shut-in or experiencing downtime. Regarding the commenter’s issue on (G), the 

EPA notes that the other reporting requirements concerning the number of well completions are 

disaggregated by well type combination. Reporting the total number of completions here 

provides a verification check on the disaggregated reporting elements and provides useful 

information by which to characterize the sub-basin activities together with other sub-basin 

summary data. We made minor clarifications to paragraphs (D) and (H) commensurate with the 

above guidance; otherwise, we are finalizing these reporting requirements as proposed.

8.0 Gas Well Completions and Workovers Without Hydraulic Fracturing

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 106

Comment: Proposed Citation Reference: §98.236(h)(1)(iii), Proposed Rule Text: Total number 

of hours that gas vented directly to the atmosphere during backflow for all completions in the 

sub-basin category (the sum of all “Tp” for completions that vented to the atmosphere as used in 

Equation W-13B).

Comment: This reporting element refers to “backflow”, but gas wells without hydraulic 

fracturing do not have “backflow”.

Response: The EPA agrees with the commenter. We have revised §98.236(h)(1)(iii) to clarify 

that the reporters must supply the total number of hours that gas vented directly to the 

atmosphere during venting for all completions in the sub-basin category. This change 

harmonizes with the calculation requirements in §98.233(h).

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

36
Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 109

Comment: Proposed Citation Reference for Completions and Workovers without Hydraulic 

Fracturing:§98.236(h)(2)(iii), Proposed Rule Text: Total number of hours that gas vented to a 

flare during backflow for all completions in the sub-basin category (the sum of all “Tp” for 

completions that vented to a flare from Equation W-13B).

Comment: This reporting element refers to “backflow”, but gas wells without hydraulic 

fracturing do not have backflow.

Response: The EPA agrees with the commenter. We have revised §98.236(h)(2)(iii) to clarify 

that the reporters must supply the total number of hours that gas vented directly to the 

atmosphere during venting for all completions in the sub-basin category. This change 

harmonizes with the calculation requirements in §98.233(h).

9.0 Blowdown Vents

9.1 Revisions to Equations W-14A and W-14B to add a compressibility term 

(includes harmonizing changes to Equations W-33 and W-34)

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 6

Comment: A revised calculation methodology for emissions from blowdown vents is proposed 

which will allow the use of a compressibility factor. Currently, emissions from blowdown vents 

are assumed to have a compressibility factor of one (1) which is not accurate at high pressures 

and low temperatures. The use of a blowdown specific compressibility factor will increase the 

accuracy of this estimate. We support these changes which will result in a more accurate 

emissions determination for these sources.

Response: The EPA thanks the commenter for their support. The EPA has revised the proposed 

requirements in this final rule to allow reporters to use a site-specific compressibility factor or 

use a default compressibility factor of 1. See Section II.B.6 of the preamble to the final rule 

regarding changes to the calculation methodology for emissions from blowdown vents to allow 

the optional use of a compressibility factor.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 10

37
Comment: The Use of Compressibility Factor Should Be Optional, Not Mandatory, in 

Blowdown Vent Emission Calculations.

For blowdown vent stacks, Subpart W currently contains emission calculations that do not use a 

compressibility factor.14 In the Proposed Rule, EPA proposes to mandate the use of a 

compressibility factor (denoted Za) in such calculations.15 EPA asserts that the change is not 

likely to increase reporting burdens, because EPA further proposes to include a default 

compressibility value of "1" for use in a set of circumstances that the Agency believes covers the 

most common measurements taken by pipeline operators.16

Kinder Morgan strongly opposes the mandatory use of the compressibility factor for blowdown 

vent calculations because EPA’s proposed default compressibility factor of "1" would not be 

available for the most common measurements made by pipeline operators. As proposed, EPA’s 

requirement to use a compressibility factor would impose a significant burden on industry 

without creating substantive benefits in terms of increased data and emissions accuracy. While 

some companies already use a compressibility term in their blowdown emission calculations, 

many do not. For companies not using compressibility factors in longstanding company 

processes, the addition of a compressibility term across hundreds of facilities encompassing 

thousands of blowdown events would result in unnecessary costs and duplicative calculations 

within company records. In addition, the inclusion of a mandatory compressibility factor in 

blowdown emission calculations will result in inconsistencies with prior year reports that do not 

include a compressibility factor in the blowdown emission calculations.

Despite the large burden this change would impose on operators, requiring use of a 

compressibility factor leads to no appreciable benefit in terms of improved data accuracy. As 

INGAA’s comments note, the potential bias introduced by failure to use a compressibility factor 

is on the order of 10% – small relative to other sources of uncertainty within required Subpart W 

estimation methods. Given the significant costs that the mandatory use of a compressibility 

factor would place on the industry for only small improvements in data accuracy, the EPA’s 

compressibility factor proposal is not justified.

For these reasons, Kinder Morgan strongly opposes the Agency’s proposal to require the use of a 

compressibility factor for calculation of emissions from pipeline and storage facilities.

However, Kinder Morgan strongly supports allowing the optional use of a compressibility factor 

in blowdown vent emission calculations. For operators easily able to accommodate the use of a 

compressibility factor, this change would not impose new burdens, and would provide greater 

flexibility. Accordingly, Kinder Morgan requests that EPA modify its proposed Equations W14A and W-14B, found in 98.233(i), as follows in Figure 5:

Figure 5: Proposed Modifications to 40 C.F.R. § 98.233(i).

Proposed 40 C.F.R. § 98.233(i). Blowdown vent stacks.

. . .

(i) Calculate the total annual natural gas emissions from each unique physical volume that is 

blown down using either Equation W-14A or W-14B of this section.

38
(Eq. W-14A)

Where:

. . .

Za= Compressibility factor at actual conditions for natural gas. You may use either a default 

value of 1, or calculate the compressibility factor based on actual temperature and pressure 

conditions. 1 if the temperature is above −10 degrees Fahrenheit and pressure is below 5 

atmospheres, or if the compressibility factor at the actual temperature and pressure is 0.98 or 

greater.

(Eq. W-14B)

Za= Compressibility factor at actual conditions for natural gas. You may use either a default 

value of 1, or calculate the compressibility factor based on actual temperature and pressure 

conditions. 1 if the temperature is above −10 degrees Fahrenheit and pressure is below 5 

atmospheres, or if the compressibility factor at the actual temperature and pressure is 0.98 or 

greater.

Kinder Morgan also requests harmonizing revisions to Equations W-33 and W-34 in § 98.233(t).

Finally, if EPA retains the proposed mandatory use of a compressibility factor or allows optional 

use of a compressibility factor, EPA should revise the compressibility factor calculations to 

reflect the temperatures and pressures at which natural gas pipelines and gas plants operate, as 

indicated in INGAA’s comments.

Footnotes:

14 See 40 C.F.R. § 98.233(i) (Eq. W-14A).

15 Proposed Rule at 13400.

16 Id.

Response: The EPA evaluated the commenter’s concerns and has subsequently revised the rule 

to allow reporters the option to use a default compressibility factor of 1 or a site-specific factor 

instead of being required to use a site-specific factor for specific temperature and pressure 

ranges. See Section II.B.6 of the preamble to the final rule for additional discussion responding 

to this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 32

39
Comment: Compressibility factor: INGAA supports the optional use of a compressibility factor 

for blowdown vent calculations. EPA proposed revisions mandate its use at typical system 

pressures and this decision is not supported or justified; mandatory use is not necessary.

Current Subpart W equations W-14A and W-14B estimate natural gas emissions from equipment 

blowdowns using the ideal gas law: n = PV/RT, where "n" is the molar amount of the gas and is 

proportional to volume. As gas pressure increases from atmospheric, gas behavior deviates from 

ideal due to intermolecular forces. A compressibility factor, "Z", is added to the ideal gas law 

equation to account for the intermolecular forces. Adding the compressibility factor to the ideal 

gas law changes the equation to n = PV/ZRT. The inverse compressibility factor, "1/Z", is the 

difference between the moles (i.e., "n") or mass (i.e., n * molecular weight) of the gas (for a 

specific temperature, pressure and volume) calculated using the ideal gas law and the moles or 

mass of gas calculated (for the specific temperature, pressure and volume) using the ideal gas 

law including compressibility.

The transmission segment is required to report blowdown emissions; underground storage does 

not have a requirement to report this source. INGAA requested including compressibility for 

transmission blowdown calculations as an option. This request was made to accommodate 

current practices where many operators already conduct blowdown calculations and use a 

compressibility term. These equations and calculations are embedded within longstanding 

company processes, and not using the compressibility term would result in unnecessary costs and 

two separate calculations (and values) within company records. However, others have 

implemented Subpart W reporting without the compressibility factor and have developed 

associated systems for data gathering and reporting. In some cases, these companies changed 

their existing practice to accommodate Subpart W requirements. As discussed in Comment 11, 

EPA has not defined or consistently applied data quality objectives. However, based on biases 

and uncertainties evident in Subpart W and for other GHGRP subparts, differences introduced 

through optional use of compressibility is relatively immaterial in comparison to other 

uncertainties. In addition, reporting could indicate whether compressibility was used so that EPA 

could understand the reporting basis. Because EPA defines operating bounds for application of 

Z, the Proposed Rule mandates its use for typical transmission operations.

A. The Proposed Rule mandates the use of Z at typical pressures for pipeline applications.

Rather than adding compressibility as an option as requested by INGAA, compressibility will be 

required for nearly all equipment blowdown calculations at T&S facilities. Proposed revisions to 

Subpart W would add Z to equations W-14A and W-14B and mandate that Z be determined for 

equipment blowdown emission calculations with pressures greater than or equal to 5 

atmospheres (73.5 psia). This same mandate is included in equations W-33 and W-34 for 

converting volume from actual to standard conditions. For pressures less than 5 atmospheres 

(and temperatures greater than -10°F) or Z values greater than or equal to 0.98, a default Z value 

of 1 can be used. As acknowledged by EPA in its technical support memo, transmission 

pipelines typically operate in the range of about 500 to about 1,000 psig14 15; thus, Z would likely 

be required for most, if not all, transmission segment blowdown emission calculations. It appears 

that EPA does not understand this outcome.

40
B. Preamble and technical support memo discussion indicate confusion and a fundamental lack 

of understanding of natural gas systems.

INGAA is concerned that EPA does not understand and appreciate the implications of the 

Proposed Rule changes. Discussions in the preamble and technical support memo indicate 

confusion and a fundamental lack of understanding of natural gas systems. In the preamble EPA 

states:

"Because it is likely that most facilities handle gas within the proposed compressibility factor 

default ranges, it is unlikely that adding this compressibility factor term into the blowdown vent 

stack calculations will significantly increase the reporting burden." [79 FR 13400]

This statement is not correct for most blowdown events at transmission facilities and is 

contradicted by information in the Proposed Rule TSD where EPA cites an API reference:

"Natural gas transmission compressor station components and main line pressures are in the 

range of 500 to 1000 psi (34 to 68 atmospheres). See page 6-32, American Petroleum Institute 

(August 2009), Compendium of Greenhouse Gas Emission Methodologies for the Oil and 

Natural Gas Industry."

Additional text from the TSD, which presents natural gas compressibility for a range of 

temperatures and pressures, indicates confusion or a lack of understanding of natural gas system 

operations:

"The compressibility of methane at standard conditions is close to 1. However, the 

compressibility of methane at low temperatures and high pressures is significantly different, as 

illustrated in Table 3.1. The natural gas processing and transmission compression segments 

covered by subpart W can operate systems at pressures higher than 25 atmospheres.16

[See Docket Id. No EPA-HQ-OAR-2011-0512-0081-A1 for Table 3.1. Compressibility of 

Natural Gas at Sample Temperatures and Pressures.]

Although the EPA had previously considered including the compressibility term (76 FR 56010, 

September 9, 2011), the EPA ultimately did not propose including the factor. The EPA 

concluded at that time that including a compressibility adjustment could create a degree of 

uncertainty among reporters when trying to compare their reported blowdown values on a 

volume basis. The EPA noted at that time that although the compressibility of pure light 

hydrocarbon substances is well known, the compressibility of hydrocarbon mixtures is less well 

known and the composition of natural gas throughout the segments covered by subpart W can be 

variable. At that time, we determined that ideal gas law calculations were adequate for reporting 

purposes under Part 98.

The EPA notes that the circumstances surrounding this issue are now different, because the EPA 

is proposing the option [Emphasis added] of using site-specific data for gas compositions, if 

available. Therefore, the original concern regarding the variation in the composition of natural 

gas at subpart W facilities and its effect on compressibility would be addressed through data 

collection on actual gas composition. The EPA has determined that at high pressures and low 

41
temperatures, the accuracy of the emission estimate would be improved if a compressibility 

factor were included in the calculation."

There are a number of areas of misunderstanding or confusion in the above support text, 

including:

• T&S and processing are the primary segments that report blowdown emissions. EPA’s Table 

3.1 lists compressibility factors for natural gas systems for temperatures well below typical 

blow down releases – e.g., -190oF and -100oF. Curiously, the table increases temperature in 

increments of 50 K (or 90 oF), but skips a temperature range more representative of the 

vented gas (e.g., 40 to 120F) associated with transmission operations – i.e., the table jumps 

by 100 K from -10 o

F to 170 oF and does not present information at typical temperatures. 

This oversight appears to indicate that EPA does not understand typical operations for the 

emission sources that would use these equations. Further, only one of the four pressures 

listed (40 atm / 588 psi) is indicative of the typical range representative of transmission 

operations.

• As noted in the cited text, EPA’s explanation includes reference to gas composition, "EPA is 

proposing the option of using site-specific data for gas compositions." INGAA does not 

understand the explanation that follows, because default natural gas composition is still 

allowed for compressor station emission calculations. See Comment 26 for additional 

discussion on gas composition – and INGAA’s support of revisions that clarify that T&S 

sources can use default natural gas composition or site data at the operator’s discretion. 

INGAA hopes that EPA does not intend to somehow intertwine Proposed Rule revisions that 

allow optional use of gas composition based on site data with blowdown calculations.

INGAA supports the optional choices for gas composition and, correspondingly, supports the 

option of using gas compressibility (Z) in equations W-14A and W-14B, and equations W-33 

and W-34.

C. INGAA has advocated for the optional use of Z in blowdown emission calculations since the 

onset of the Subpart W rulemaking.

In comments on the 2010 proposed rule [75 FR 18608], INGAA requested the optional use of 

existing company algorithms and programs, which may include the compressibility factor, to 

calculate and document blowdown emissions. This option was requested by INGAA so that 

longstanding facility blowdown emission systems and calculations did not have to be changed. 

The exclusion of Z required changes to some of these systems and calculations. Additional detail 

is available in previous INGAA comments, which are referenced in Comment 1.

Footnotes:

14 "Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Proposed Rule," EPA-HQ-OAR-2011-

0512-0065, Page 5 (February 20, 2014).

15 "Compendium of Greenhouse Gas Emission Methodologies for the Oil and Natural Gas 

Industry," Page 6-32. American Petroleum Institute (August 2009)

42
16 "Compendium of Greenhouse Gas Emission Methodologies for the Oil and Natural Gas 

Industry," Natural gas transmission compressor station components and main line pressures are 

in the range of 500 to 1000 psi (34 to 68 atmospheres). See page 6-32, American Petroleum 

Institute (August 2009).

17 Compressibility factors calculated using the California Natural Gas Association (CNGA) 

method. "Gas Pipeline Hydraulics" by Shashi Menon and Pramila Menon.

Response: The EPA evaluated the commenter’s concerns and has subsequently revised the rule 

to allow reporters the option to use a default compressibility factor or 1 or a site-specific factor 

instead of being required to use a site-specific factor for specific temperature and pressure 

ranges. See Section II.B.6 of the preamble to the final rule for additional discussion responding 

to this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 45

Comment: INGAA supports revisions to blowdown calculation equations that allow the 

optional use of a compressibility factor. 

Previous INGAA comments requested the optional use of a gas compressibility factor for 

blowdown vent stack calculations in §98.233(i). EPA proposes adding the compressibility factor, 

"Z", to blowdown emissions calculations in Equations W-14A and W-14B. However, to provide 

flexibility and accommodate existing systems used for blowdown tracking, use of the 

compressibility factor should be optional to accommodate existing practices for some operators. 

Revisions should not prescribe new requirements for operators that employ the current Subpart 

W calculation method. The Proposed Rule mandates use of the compressibility factor for typical 

T&S operating pressures, and it appears that EPA does not understand this implication. INGAA 

does not support mandatory use of a gas compressibility factor. See Comment 15 for additional 

details and discussion.

Response: The EPA evaluated the commenter’s concerns and has subsequently revised the rule 

to allow reporters the option to use a default compressibility factor of 1 or a site-specific factor 

instead of being required to use a site-specific factor for specific temperature and pressure 

ranges. See Section II.B.6 of the preamble to the final rule for additional discussion responding 

to this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 54

43
Comment: Compressibility does not introduce significant bias at typical T&S facility operating 

conditions.

Transmission pipelines typically operate in the range of about 500 to 1000 psi. Table 2 lists 

estimated compressibility factors for natural gas at temperature and pressure ranges more typical 

for transmission operations. The gas temperature exiting a compressor is typically higher than

ambient due to the energy added to the gas during compression. Thus, the table considers "1/Z" 

factors for gas temperatures ranging up to 130°F. At these temperatures and the highest pressures 

(i.e., 900 – 1, 000 psig), 1/Z values are estimated to be about 1.1; at lower temperature and 

moderate pressures (i.e., prior to compression), 1/Z is also on the order of 1.1. Thus, for typical 

operations, the bias from using the ideal gas law would be about 10%. Higher bias (e.g., about 

20%) could occur in some cases but is not typical for most events.

[See Docket Id. No EPA-HQ-OAR-2011-0512-0081-A1 for Table 2. Estimated Natural Gas 

Compressibility Factors (Z) for Range of Operating Pressures and Temperatures.]17 

To summarize, the operating temperatures and pressures for natural gas transmission compressor 

station blowdowns, including compressibility in blowdown calculations will typically change 

calculated emissions 10% or less relative to the ideal gas law; EPA has not explained what 

accuracy improvement is anticipated or how any reduced bias relates to data quality objectives.

In the TSD, EPA states:

"The EPA has determined that at high pressures and low temperatures, the accuracy of the 

emission estimate would be improved if a compressibility factor were included in the 

calculation."

EPA has not explained how the "improved emission factor accuracy" associated with including Z 

relates to GHGRP data quality objectives or compares with other uncertainties or biases in the 

GHGRP. INGAA believes that potential bias or uncertainty of about 10% or less for a single 

source type is small relative to other Subpart W and GHGRP emission estimation methods (e.g., 

emission factors for many estimates). Further, it is not evident that EPA has considered how this 

uncertainty impacts the overall blowdown vents emission estimate uncertainty and then justifies 

the incremental costs based on the perceived benefit. In addition to compressibility factor 

inclusion / exclusion, the blowdown vent emission estimate uncertainty includes contributions 

from uncertainties in:

• Physical volume estimate ("determined by engineering estimates based on best available 

data" [§98.233(i)(1)]);

• Actual temperature and pressure estimates ("For actual conditions, reporters must use 

average atmospheric conditions or typical operating conditions" [§98.233]); and

• Inherent assumption in equations W-14A and W-14B that the gas temperature in the unique 

volume is the same at the beginning and end of each blowdown.

It is anticipated that compressibility factor inclusion / exclusion would have negligible impact on 

the overall emission estimate uncertainty for blowdown vent stacks.

44
Response: The EPA evaluated the commenter’s concerns and has subsequently revised the rule 

to allow reporters the option to use a default compressibility factor of 1 or a site-specific factor 

instead of being required to use a site-specific factor for specific temperature and pressure 

ranges. See Section II.B.6 of the preamble to the final rule for additional discussion responding 

to this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 55

Comment: If the compressibility factor is mandatory rather than optional, then missing data 

provisions must apply.

The proposed missing data provisions do not specifically include compressibility factor as a 

calculation input that may not be available if process data is not collected at the time of a 

blowdown event or cannot be estimated. If the compressibility factor is not optional, the 

Proposed Rule must be revised to ensure that missing data provisions apply. This could be 

accomplished by adding the compressibility factor to one of the currently proposed missing data 

provisions or by clarifying that the compressibility factor is considered activity data that would 

be covered under broadly applicable provisions in §98.235(g).

Response: The EPA has revised the final rule to allow reporters the option to use a default 

compressibility factor of 1 or a site-specific factor instead of being required to use a site specific 

factor for specific temperature and pressure ranges. Consequently, there is no need for missing 

data procedures for this data element. See Section II.B.6 of the preamble to the final rule for 

additional discussion regarding the optional use of site-specific compressibility factors.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 56

Comment: Mandating the compressibility factor in blowdown vent calculations will add 

implementation costs that have not been considered by EPA.

Some companies have revised their blowdown vent tracking and calculations systems to comply 

with current Subpart W requirements and would incur costs to undo those system-wide changes. 

Optional use of Z would allow operators to use existing calculations and systems that are 

otherwise consistent with Subpart W and minimize Proposed Rule implementation costs. In the 

Proposed Rule Assessment of Impacts memo, EPA incorrectly concludes that the proposed rule 

change would have no impact on implementation costs:

45
"The EPA is proposing to add a compressibility term to the blowdown vent stack calculations. It 

is anticipated that reporters handle gas within the proposed compressibility factor default ranges; 

therefore, it is unlikely that adding this compressibility factor term into the blowdown vent stack 

calculations would increase burden to reporters. Therefore, the EPA did not estimate the 

potential burden impact to reporters for this change."

As demonstrated above, reporters typically handle gas over a broader pressure range than the 

proposed compressibility factor default pressure range, and mandating the use of the 

compressibility factor in blowdown vent calculations would require changes to existing systems 

and increase implementation costs. EPA has not considered or justified these costs, nor 

demonstrated that compressibility factor inclusion will significantly and cost-effectively reduce 

the overall perceived uncertainty of the blowdown vent emission estimates, especially when 

these uncertainties are considered within the context of other GHGRP sources. Many operators 

have developed and implemented blowdown tracking systems and calculation methods 

consistent with the Subpart W final rule (i.e., using the ideal gas law). Revising Subpart W to 

allow the optional use of the compressibility factors would allow operators to continue to use 

existing calculations and systems and would not significantly impact the reported emissions.

Response: The EPA evaluated the commenter’s concerns and has subsequently revised the rule 

to allow reporters the option to use a default compressibility factor of 1 or a site-specific factor 

instead of being required to use a site-specific factor for specific temperature and pressure 

ranges. See Section II.B.6 of the preamble to the final rule for additional discussion responding 

to this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 73

Comment: GHG volumetric emissions using actual conditions, Revisions to §98.233(t): EPA is 

proposing to add a compressibility factors to the equations converting volumetric emissions in 

actual conditions to standard conditions. For Equation W-33, which converts natural gas 

emissions, reporters may use 1 if the temperature is above -10 degrees Fahrenheit and pressure is 

below 5 atmospheres, or if the compressibility factor at the actual temperature and pressure is 

0.98 or greater. For Equation W-34, which converts GHG emissions, reporters may use 1 if the 

compressibility factor at the actual temperature and pressure is 0.98 or greater.

Comment: These revisions emphasizes the need for EPA to correct the emission equations for 

other source categories that are erroneously reported in “actual” gas conditions when the industry 

standard is to measure or estimate the gas volumes in standard conditions. The following 

equations are indicated in Subpart W to result in gas volumes in actual conditions:

• Volumetric CO2 emissions for acid gas removal units using calculation method 2 (Equation 

W-3). Here, the total annual volume of vent gas flowing out of the AGR unit in cubic feet per 

year is determined by flow meter. Flow meters used in industry automatically compensate for 

46
compressibility based on pressure in correcting the gas volumes for the actual conditions and 

report the measured volumes in standard conditions.

• The volume of natural gas flowing into or out of an AGR unit for calculation method 3 

(Equations W-4A and W-4B). Engineering calculation or a continuous flow meter is allowed 

for determining these volumes, where standard industry practice for either calculating or 

measuring these flows would be in standard conditions.

• The average flow rate in cubic feet per hour for all measured wells of the same tubing 

diameter group and pressure group combination in a sub-basin, over the duration of the 

liquids unloading for calculation method 1 (Equation W-7A). Flow meters used by industry 

correct the gas volumes for the actual conditions and report the measured volumes in 

standard conditions.

• Estimated venting emissions using Equation W-17A (for oil wells) or Equation W-17B for 

gas wells) for well testing venting and flaring. For oil wells, the GOR term used to estimate 

the gas volume is in units of standard cubic feet per barrel. For gas wells, the average annual 

production rate is determined for standard conditions.

• Estimated emissions from combustion units for onshore natural gas and petroleum 

production facilities (Equations W-39A and W-39B). The volume of gas to the combustion 

units used in these equations is determined or measured in standard

conditions.

For each of these equations, industry standard practice is to quantify the gas volumes at standard 

conditions. It makes no sense for a reporter to convert a gas volume from standard conditions to 

actual to comply with the designated outputs from these equations, and then reconvert to 

standard conditions to comply with the references to 98.233(t) Equations W-33 and W-34.

It appears EPA has added the compressibility term to Equations W-33 and W-34 to account for 

high gas pressure operations in the transmission sector. The compressibility for natural gas in 

transmission service (high pressure gas composed primarily of CH4) will be very different than 

natural gas in production operations (lower pressure gas of variable composition). Even the 

technical support document posted to the docket for this proposed rule (Greenhouse Gas 

Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems; Proposed Rule, February 20, 2014) confuses the

compressibility of natural gas and methane (Table 3.1 is labeled as providing compressibility 

factors for natural gas while text introducing the table describes the compressibility of methane). 

For oil and gas production operations, the only emission source where computing gas volumes at 

actual conditions is legitimate is the choke flow calculation used in equation W-11A and W-11B.

These are the only equations with application to the upstream oil and gas operations that should 

reference the conversion from actual to standard conditions in 98.233(t) and evaluate the need to 

correct for compressibility.

API urges EPA to correct the emissions or gas volumes noted above to reference standard 

conditions. API intends to provide additional information demonstrating the minimal impact of 

compressibility based on typical pressures and temperatures in oil and natural gas production 

operations.

47
Response: The EPA has revised the rule to allow reporters the option to use a default 

compressibility factor of 1 or a site-specific factor instead of being required to use a site-specific 

factor for specific temperature and pressure ranges. See Section II.B.6 of the preamble to the 

final rule for additional discussion regarding the optional use of site-specific compressibility 

factors. Regarding revising Equations W-3. W-4A, W-4B, W-7A, W-17A, W-17B to reflect 

standard conditions, we have made revisions to the introductory text in §98.233 and §98.236 to 

clarify that measurement systems that correct flows or volumes to standard conditions may be 

used directly in the above equations. See Section II.B.13 of the preamble to the final rule for 

additional discussion regarding the use of flow or volume measurement systems that correct to 

standard conditions.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 11

Comment: SoCal Gas supports optional use of a compressibility factor. Requiring that 

compressibility be applied in the calculations will require a re-working of existing systems which 

will increase our burden and cost which was not accounted for in the impact assessment 

performed.

Differences in calculated blowdown volumes introduced through optional use of compressibility 

are relatively immaterial in comparison to uncertainties in other calculation parameters. In 

addition, reporting could indicate whether compressibility was used so that EPA could 

understand the reporting basis.

It is a longstanding practice for SoCal Gas to use a compressibility term in blowdown 

calculations for higher pressure events (>100 psig). However, separate data gathering and 

reporting systems have been developed to implement Subpart W reporting without the 

compressibility factor to meet the existing requirements.

Response: The EPA evaluated the commenter’s concerns and has subsequently revised the rule 

to allow reporters the option to use a default compressibility factor of 1 or a site-specific factor 

instead of being required to use a site-specific factor for specific temperature and pressure 

ranges. See Section II.B.6 of the preamble to the final rule for additional discussion responding 

to this comment.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 26

48
Comment: Redundant recordkeeping requirement in Eq. W-14A and Eq. W-14B: EPA is 

proposing to modify these two equations by changing the description of “N” to “Number of 

occurrences of blowdowns for each unique physical volume in the calendar year. You must 

retain logs documenting the number of occurrences of blowdowns for each unique physical 

volume in the calendar year.” This change should not be made for two reasons. First, including a 

recordkeeping requirement in an equation parameter description does not conform to typical rule 

writing practices. Additionally, 98.237(b) already requires, “Results of all emissions detected 

and measurements.” 98.3(g)(2)(iv) already requires, “Any facility operating data or process 

information used for the GHG emission calculations.” Thus, this change is non-conforming and 

redundant and should not be made.

Response: The EPA agrees with the commenter that the recordkeeping requirements do not 

need to be specified in the equation variable description. EPA has removed the recordkeeping 

requirement from the description of the variable “N”. As the commenter noted, the 

recordkeeping requirements in §98.3(g)(2)(iv) already require records to be kept for this 

parameter.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 11

Comment: Williams believes the use of a compressibility factor other than 1 in Equations W14A and W-14B should be optional. This would allow current systems that utilize 

compressibility in their calculations to continue that practice. The proposed amendment places 

significant burden on the many reporters because compressibility factors would have to be 

determined for the vast majority of blowdowns, which involve starting pressures greater than 5 

atm and temperatures greater than -10 degrees F.

A compressibility factor equal to 1 provides a reasonably accurate, or sometimes slightly 

conservative, estimate of GHG blowdown emissions; it is protective. Given the option, reporters 

will naturally be inclined to employ a compressibility factor less than 1 for cases where reported 

GHG emissions will be reduced most significantly. In summary, Williams believes mandatory 

use of a compressibility factor results in added complexity with limited benefit.

Response: The EPA evaluated the commenter’s concerns and has subsequently revised the rule 

to allow reporters the option to use a default compressibility factor of 1 or a site-specific factor 

instead of being required to use a site-specific factor for specific temperature and pressure 

ranges. See Section II.B.6 of the preamble to the final rule for additional discussion responding 

to this comment.

49
9.2 Revisions to require reporting of aggregated blowdown emissions (in lieu 

of by "unique physical volume")

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 12

Comment: Kinder Morgan Supports the Proposed Rule’s New Approach to Report Blowdown 

Emissions Reporting by "Equipment Type."

Subpart W currently requires blowdown emissions to be reported by "unique physical volume" 

to EPA. Under § 98.236(c)(7), for each unique physical volume between isolation valves in a 

pipeline system greater than 50 cubic feet that is blown down more than once during the calendar 

year, the total number of blowdowns, annual emissions, and a unique identifier for the unique 

physical volume must be reported to EPA. For unique physical volumes blown down only once a 

year, less information must be reported: the total number of blowdowns, and an aggregate 

emissions figure for all such blowdowns.

Under the Proposed Rule, EPA has proposed a different simplified approach: to require reporting 

of emissions from physical volumes greater than 50 cubic feet only on an aggregate basis 

according to "equipment type," with every physical volume falling into one of the following 

seven "equipment type" categories: station piping, pipeline venting, compressors, 

scrubbers/strainers, pig launchers and receivers, emergency shutdowns, and all other blowdowns 

greater than or equal to 50 cubic feet.20

Kinder Morgan strongly supports this new approach to blowdown emissions reporting, which 

provides more useful data to EPA and is less burdensome for reporting entities.

To avoid confusion and any misinterpretation of the type of blowdowns, Kinder Morgan also 

recommends that the seven categories be called "equipment/event types" and be defined or 

explained in Subpart W or the preamble to the Final Rule. This label "equipment/event type" 

more accurately describes the "emergency shutdown" category. Additionally, EPA should clarify 

that emergency shutdown blowdown emissions should be categorized under the "emergency 

shutdown" category, regardless of the type of equipment that is blown down, and should further 

clarify the distinction between "station piping" (i.e., within the compressor station boundary) and 

"pipeline venting" (i.e., pipe external to the compressor station that is vented within the station 

boundary). Last, Kinder Morgan recommends that the category "all other blowdowns greater 

than or equal to 50 cubic feet" should be "all other equipment with a physical volume greater 

than or equal to 50 cubic feet."

Footnotes:

20 Proposed Rule at 13431 (proposing new § 98.236(i)).

Response: The EPA thanks the commenter for their support. The EPA agrees with the 

commenter that further clarification was needed on reporting blowdown emissions. In the final 

50
rule, we have incorporated the term “equipment or event type” to be consistent with emergency 

shutdown activities, revised the emergency shutdown category to include emergency shutdown 

blowdown emissions regardless of equipment type, and clarified the distinction between facility 

piping (the term used in place of the proposed station piping) and pipeline venting. We have also

revised the category proposed as “all the other blowdowns greater than or equal to 50 cubic feet” 

category to "all other equipment with a physical volume greater than or equal to 50 cubic feet" in 

order to clarify it is the physical volume of the equipment, not the blowdown volume (converted 

to standard conditions), to which the 50 cubic feet threshold applies. 

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 33

Comment: Tracking blowdowns by equipment type: INGAA supports categorizing and 

reporting blowdowns by equipment / event type rather than by unique volume. However, some 

of the proposed revisions are unclear and revisions are needed. 

Proposed Rule revisions require categorizing and reporting blowdown emissions by equipment 

type according to the following seven categories: station piping, pipeline venting, compressors, 

scrubbers/strainers, pig launchers and receivers, emergency shutdowns, and all other blowdowns 

greater than or equal to 50 cubic feet. INGAA recommended reporting by equipment type rather 

than "unique volume" because this provides more pertinent data and is also more consistent with 

existing approaches for tracking blowdowns. However, rule revisions and clarifications are 

recommended:

• Six of the categories are equipment types; however, "emergency shutdowns" would be more 

accurately described as an event type or a reason for a blowdown, but the blowdown could 

also be associated with a listed equipment type. The rule should clearly indicate that 

emergency shutdowns would be categorized under the "emergency shutdown" event category 

and not a related equipment category. This could be accomplished within the rule text or 

explanation in the preamble.

• Other than compressors, the categories of equipment types are not defined in the rule or 

discussed in the preamble. Definition and/or discussion of these equipment types are 

recommended to clarify data collection and reporting requirements, and to promote 

consistency among reporters. For example, the difference between "station piping" (i.e., 

within the compressor station boundary) and "pipeline venting" (i.e., pipe external to the 

compressor station that is vented within the station boundary) should be explained. 

Additional discussion and description is recommended to differentiate these two categories. 

Alternatively, these two types of blowdowns could be combined into one category called, 

"Piping – Blowdowns and Purges".

• Similarly, the reporting obligation for compressors could be clarified by re-labeling the 

"compressors" category as "Compressors – Blowdowns and Purges."

51
• The category "all other blowdowns greater than or equal to 50 cubic feet" should be "all other 

equipment with a physical volume greater than or equal to 50 cubic feet."

Response: See the response to comment EPA-HQ-OAR-2011-0512-0077-A1, Excerpt 12 in this 

section for the response to this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 57

Comment: Operators are given the option of calculating emissions for each unique volume and 

tracking / reporting by equipment type per §98.233(i)(2) or by directly measuring blowdown 

vent emissions using a flow meter per §98.233(i)(3). For section (i)(2) and related reporting, 

suggested revisions follow (added text in bold, deleted text in strike-through) for rule text related 

to data collection and reporting:

In §98.233(i)(2):

"(2) Method for determining emissions from blowdown vent stacks according to equipment type. 

If you elect to determine emissions according to each equipment type, using unique physical 

volumes as calculated in paragraph (i)(1) of this section, you must calculate emissions as 

specified in paragraphs (i)(2)(i) through (i)(2)(iii) of this section for each equipment type. 

Equipment or event (i.e., emergency shutdown) types must be grouped into the following seven 

categories: station piping, pipeline venting, compressors, scrubbers/strainers, pig launchers and 

receivers, emergency shutdowns, and all other blowdowns equipment with a physical volume 

greater than or equal to 50 cubic feet. If a blowdown event resulted in emissions from 

multiple equipment types and the emissions cannot be apportioned to the different 

equipment types, then categorize the blowdown event as the equipment type that 

represented the largest portion of the emissions for the blowdown event."

And, related reporting in §98.236(i)(1):

"Report by equipment type. If you calculated emissions from blowdown vent stacks by 

equipment types the seven categories listed in 98.233(i)(2), then you must report the equipment 

types and the information specified in paragraphs (i)(1)(i) through (i)(1)(iii) of this section for 

each equipment type. If a blowdown event resulted in emissions from multiple equipment types 

and the emissions cannot be apportioned to the different equipment types, then you must 

report the information in paragraphs (i)(1)(i) through (i)(1)(iii) of this section for the equipment 

type that represented the largest portion of the emissions for the blowdown event."

Response: The EPA has evaluated the commenter’s suggestion and agrees that it would clarify 

those situations where emissions cannot be apportioned to a specific equipment or event type. In 

the final rule, we have revised §98.233(i)(2) to add: “If a blowdown event resulted in emissions 

from multiple equipment types and the emissions cannot be apportioned to the different 

52
equipment types, then categorize the blowdown event as the equipment type that represented the 

largest portion of the emissions for the blowdown event.”

Commenter Name: Brian Korpics

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2011-0512-0087-A2

Comment Excerpt Number: 5

Comment: A variety of analyses have utilized Subpart W data to help deepen understanding of 

emissions from the oil and gas sector, including the Annual Inventory of U.S. Greenhouse Gas 

Emissions and Sinks and efforts by academics and other researchers to assess emissions, which 

have provided essential independent information about emissions from this sector.17 We 

specifically support many of the proposed revisions to Subpart W—listed below—that would 

enhance the ability of the public and policy makers to use the data in future contexts like these.

• Blowdown vents. Similarly, the Agency has proposed to require reporting of blowdown 

emissions aggregated into seven categories: station piping, pipeline venting, compressors, 

scrubbers/strainers, pig launchers and receivers, emergency shutdowns, and all other 

blowdowns greater than or equal to 50 cubic feet.19

17 See, e.g., David Allen et al., Measurements of methane emissions at natural gas production 

sites in the United States, 110 PNAS 17,768 (2013); A. R. Brandt et al., Methane Leaks from 

North American Natural Gas Systems, 343 SCI. 733 (2014).

19 Fed. Reg. at 13,401.

Response: The EPA thanks the commenter for their support. See Section II.B.6 of the preamble 

to the final rule for additional discussion regarding revisions made to the requirements for 

blowdown vent stacks.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number:

Comment: Order of blowdown calculations is incorrect: EPA proposes that all unique 

blowdown volumes be summed into equipment types before applying gas compositions to 

determine CH4 and CO2 volumetric and mass emissions. This will lead to gross misapplication of 

gas composition to blowdown volumes in the gas processing sector. For example, most gas 

plants have compressors that compress inlet "wet gas" and they have compressors that compress 

outlet "residue gas". These two gases have very different compositions. Yet, under the proposed 

methodology, all compressor blowdown volumes would be summed and then the reporter would 

somehow choose whether to apply the inlet gas composition or the outlet gas composition to this 

53
volume. In either case, the result will not represent actual emissions. This sort of gross and 

inaccurate presumption is highly illogical because elsewhere in this section, EPA is introducing 

extremely complex calculations to determine compressibility factors to presumably achieve a 

slightly higher degree of accuracy. Reporters are already determining the appropriate gas 

composition to use for each unique blowdown volume. We suggest that this should remain the 

practice, and summation into equipment types should occur last (after application of 98.233(u) 

and (v)).

Response: The EPA agrees with the commenter and has revised the final rule to incorporate the 

commenter’s suggestion for certain industry segments. See Section II.B.6 of the preamble to the 

final rule for additional discussion responding to this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 59

Comment: For the transmission segment, INGAA recommends that all unique blowdown 

volumes be summed into equipment types before applying gas compositions to determine CH4 

and CO2 volumetric and mass emissions. As discussed in Comment 23, INGAA recognizes that 

this approach may not be preferred for other segments where gas quality varies within the 

facility.

Response: The EPA has retained the option to allow reporters in the onshore natural gas 

transmission compression and LNG import and export equipment industry segments to sum the 

blowdown volumes first, prior to applying gas compositions. We find that, for these industry 

segments, the blowdown gas composition will be similar across different events so there is no 

loss in accuracy if the volumes are summed first. See Section II.B.6 of the preamble to the final 

rule for EPA’s response to this comment.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 3

Comment: Proposed EPA Amendment: Revise the current reporting requirements in 40 CFR 

98.236(c)(7) to simplify the reporting structure to report blowdown emissions aggregated by 

seven categories: station piping, pipeline venting, compressors, scrubbers / strainers, pig 

launchers and receivers, emergency shutdowns, and all other blowdowns greater than or equal to 

50 cubic feet.

Williams supports the optional use of EPA’s seven proposed blowdown categories to help 

reporters identify and report types of blowdowns. We do not, however, support the mandatory 

54
use of the proposed categories, as this would force many reporters like Williams to redesign and 

modify electronic data acquisition and reporting systems for facilities that are not staffed fulltime. At Williams, many of these systems were designed and installed to comply with the 

unique-volume reporting requirement of the current Greenhouse Gas Reporting Rule.

Response: The EPA disagrees with the commenter’s suggestion to make the blowdown 

categories optional. The EPA, as well as other commenters, have agreed that the requirement 

reduces burden and simplifies the rule. We also contend that providing the option to reporters 

would result in inconsistencies in the reported data such that the EPA would not be able to 

compare and review information between reporters. There are no changes to the final rule as a 

result of this comment. See Section II.B.6 of the preamble to the final rule for further discussion 

regarding the blowdown categories.

9.3 Optional calculation method where a flow meter is in use on a blow down 

vent - proposed §98.233(i)(3)

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 43

Comment: INGAA supports the addition of the method for determining blowdown vent 

emissions using a flowmeter. Minor revisions are needed to clarify method applicability and

adjustments to measured emissions.

Section 98.233(i)(3) is added to allow the installation of flowmeters on blowdown vent stacks to 

measure gas emissions rather than tracking individual blowdown events. This has the potential to 

reduce reporter burden in some cases. However, minor clarifications and adjustments are needed 

that include:

• The rule should clearly indicate that both the method for determining emissions from 

blowdown vent stacks using a flowmeter [§98.233(i)(3)] and the method for determining 

emissions from blowdown vent stacks according to equipment type [§98.233(i)(2)] can be 

used at facility for different blowdown emission sources. For example, if a facility vent 

includes a flowmeter, some but not all equipment vents may be routed to that vent stack.

• When a flowmeter is used to report blowdowns, the reporting section implies that emissions 

are not tracked by equipment or event type and an annual total is reported. However, 

§98.233(i) does not clearly indicate this, and §98.233(i)(3) and/or (4) should be clarified to 

indicate that if the flowmeter option is used the emissions are not categorized and an annual 

total is reported.

• INGAA supports §98.233(i)(2)(iii) provisions, where the calculation to address gas 

composition uses the annual volume. However, INGAA recognizes that this approach may 

not be appropriate for upstream operations where gas quality may vary within the facility and 

separate calculations may be warranted. Thus, §98.233(i) revisions may be necessary to add 

flexibility and accommodate various scenarios.

55
Response: The EPA has evaluated the commenter’s suggestions and agrees that the changes 

would clarify the rule. In the final rule, the EPA is clarifying in §98.233(i) that the facility may 

use the equipment/event type method for some blowdown vent stacks and use the flow meter for 

other blowdown vent stacks. If a reporter chooses to use a flow meter, they must measure the 

natural gas emissions from the blowdown(s) at the facility using a flow meter according to 

methods in §98.234(b), and calculate annual CH4 and CO2 volumetric and mass emissions 

measured by the meters according to §98.233(i)(4). If the reporter chooses to use this method, 

they must also calculate an annual emissions total, and do not need to calculate emissions by the 

seven categories listed in §98.233(i)(2). In the final rule, the EPA is clarifying in §98.236(i) that 

if both calculation methods are used, then the reporter must report by equipment/event type for 

the blowdown stack vents that use that method and report the total emissions for all blowdown 

vent stacks that use flow meters to determine blowdown emissions.

9.4 Comments on other minor revisions and restructuring of reporting 

requirements for blowdown vents

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 4

Comment: Assigning blowdown volumes to equipment: It is unclear what EPA’s intent is with 

the language in 98.236(i)(1) (shown below), but the following change must be made so that if 

reporters are able to delineate blowdown emissions within a "single event" to individual 

equipment types, they are allowed to do so. In many cases, equipment blowdowns are tracked by 

individual equipment and it may be more burdensome to lump blowdown emissions from one 

piece of equipment with another piece of equipment.

98.236(i)(1)...If a blowdown event resulted in emissions from multiple equipment types, then you 

must may report the information in paragraphs (i)(1)(i) through (i)(1)(iii) of this section for the 

equipment type that represented the largest portion of the emissions for the blowdown event. 

Response: The EPA agrees with the commenter that it is preferable to have the emissions 

apportioned by equipment type when possible. We have revised the last sentence in 

§98.236(i)(1) to state “If a blowdown event resulted in emissions from multiple equipment and 

the emissions cannot be apportioned to the different equipment, then you may report the 

information in paragraphs (i)(1)(i) through (i)(1)(iii) of this section for the equipment that 

represented the largest portion of the emissions for the blowdown event.” Similar language was 

added to §98.233(i)(2) to clarify this intent in the calculation methodology section also.

10.0 Onshore Production Storage Tanks

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

56
Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 5

Comment: Onshore Production Storage Tanks: API supports EPA’s proposal to modify the 

requirements for onshore production storage tanks to eliminate the need for spatial data.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 6

Comment: API also generally supports revisions that provide an exception based approach for 

stuck dump valves.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 57

Comment: Onshore production storage tanks, Revisions to §98.233(j): EPA is proposing to 

modify the requirements for onshore production storage tanks to eliminate the need for spatial 

data collection. This revises the numbering of the calculation methods.

Comment: API supports the revisions to remove the reference to the location of the well head 

and separator or well head and tank.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 7

57
Comment: API, however, disagrees with the revisions to Section 98.233(j)(6) which expands 

the universe of storage tanks subject to the rule. Specifically, the revised Section (j)(6) now 

includes storage tanks with throughput of less than 10 barrels per day which significantly 

expands the rule. While API appreciates that EPA adopted the provision regarding exception 

reporting, as discussed infra, API objects to the expansion of reporting emissions from stuck 

dump valves to encompass all tanks.

Response: The EPA thanks the commenter for alerting us to this issue. This was an inadvertent 

error. We are clarifying in the final rule, both in §98.233(j) and §98.233(j)(6), that you must 

calculate emissions from dump valve leakage only if you use Calculation Method 1 or 

Calculation Method 2. We are also revising the parameter “En” in Equation W-16 from the

proposed rule to remove the reference to Calculation Method 3, which was erroneously included 

in the proposed rule. Additionally, we are revising the definition of the parameter “En” to include 

a reference to §98.233(j)(4); this revision clarifies that the value of “En” used in Equation W-16 

should exclude any recovered emissions. See Section II.B.7 of the preamble to the final rule for

further discussion related to this comment.

11.0 Transmission Storage Tanks

11.1 Revisions to methods for quantifying emissions from the tank vapor vent 

stack

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 28

Comment: Transmission storage tank calculation requirements order: The order of 

requirements in 98.233(k) is confusing and should be changed to match the actual calculation 

progression.

98.233(k)(2)(iii) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section. 

98.233(k)(2)(iv) Calculate CH4 and CO2 volumetric and mass emissions at standard 

conditions using calculations in paragraphs (t), (u), and (v) of this section, as applicable to the 

monitoring equipment used. 

98.233(k)(3) If a leaking dump valve is... 

98.233(k)(4) Calculate CH4 and CO2 volumetric and mass emissions at standard conditions 

using calculations in paragraphs (t), (u)(2)(iii), and (v) of this section, as applicable to the 

monitoring equipment used. 

98.233(k)(5) 98.233(k)(4) Calculate the annual emission from storage tanks to flares... 

98.236(k)(2)(iv) Annual... calculated according to § 98.233(k)(1) through (k)(4) (k)(3). 

58
98.236(k)(2)(v) Annual... calculated according to § 98.233(k)(1) through (k)(4) (k)(3). 

98.236(k)(3)(iv) Annual... calculated according to § 98.233(k)(5) (k)(4). 

98.236(k)(3)(v) Annual... calculated according to § 98.233(k)(5) (k)(4). 

98.236(k)(3)(vi) Annual... calculated according to § 98.233(k)(5) (k)(4). 

Response: The EPA agrees with the commenter that the calculations should be reordered to 

match the calculation progression. The EPA has revised these requirements as suggested by the 

commenter. These revisions separate out the measurement methods in §98.233(k)(2)(i) and (ii) 

separately from the calculation requirements in proposed §98.233(k)(2)(iii) and (iv) and remove 

any confusion regarding the order of calculations.

11.2 Comments on other minor revisions and restructuring of reporting 

requirements for onshore transmission condensate storage tanks

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 27

Comment: 29. Transmission storage tanks reporting: Several changes should be made for these 

reporting requirements:

98.236(k)(1)(ii), (k)(2)(i), and (k)(3)(i) all contain language like "Method used to determine if 

dump valve leakage occurred." These requirements should be modified to include a specific list 

of options that EPA intends to program into e-GGRT. Including this in the actual rule will avoid 

the confusion and changes that have occurred in the past when e-GGRT programming added or 

"refined" reporting requirements.

98.236(k)(1)(iii) "Indicator Indicate whether scrubber dump valve leakage occurred for the 

transmission storage tank vent according to 98.233(k)(2)." [Note: This clarification and 

reference needs to be made since the calculation section of the rule prescribes when "leakage 

occurred".]

98.236(k)(1)(iv) "Indicator Indicate if there is a flare attached to the transmission storage tank 

vent stack." 

Response: The EPA thanks the commenter for their suggestion. Given the number of methods 

available to reporters, it would be unwieldy to list each method in the reporting requirements in 

the final rule. The EPA will further consider these comments in the programming of future 

versions of e-GGRT. The EPA has corrected the typographical errors in §98.236(k)(1)(iii) and 

(iv) as suggested by the commenter.

59
Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 35

Comment: §98.236 reporting requirements are substantially revised to better comport with 

analogous §98.233 emission estimation requirements. In reviewing these revisions, some minor 

technical issues were identified:

• For each transmission storage tank vent, §98.236(k)(1)(iii) requires, "Indicator whether 

scrubber dump valve leakage occurred for the transmission storage tank vent." It is not clear 

what specifically is being requested by this item, and clarified text is required.

Response: The first word should have been “indicate”. The EPA has corrected this 

typographical error in §98.236(k)(1)(iii) and also in §98.236(k)(1)(iv).

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 35

Comment: Leaking and venting time – reporting requirements: Reporting element 

98.236(q)(2)(iii) should be reworded to more accurately reflect reality. The component leaking 

time that is used in Equation W-30 is based on broad assumptions; the time is not based on actual 

field observations. For example, many operators will fix leaks that are detected during the 

survey, but they may not choose to perform an additional survey to "get credit" for those fixes. It 

would be inaccurate to characterize this time as "found leaking and operational". Transmission 

storage tanks have a similar issue. The following changes are suggested:

98.236(k)(2)(iii) Duration of time that venting is assumed to have occurred according to 

98.233(k)(3), in hours (may use best available data if a continuous flow measurement device was 

used). [see previous comment regarding rearranging and renumbering certain of the 98.233(k) 

requirements]

Response: The EPA agrees that the provisions of §98.236(k)(2)(iii) may be reworded to clarify 

that the time venting is an assumed leak time. We have revised §98.233(k)(2)(iii) as follows: 

"(iii) Duration of time that the leak is counted as having occurred, in hours, as determined in 

§98.233(k)(3) (may use best available data if a continuous flow measurement device was used)." 

These revisions are consistent with the calculation requirements in §98.233.

12.0 Well Testing Venting and Flaring

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

60
Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 58

Comment: Well testing venting and flaring: Revisions to §98.233(l): EPA is proposing 

clarifying revisions to the text in this section. This includes modifying the definition of the term 

FR for equation W-17A from: “FR = Flow rate in barrels of oil per day for the oil well(s) being 

tested.” to “Average annual flow rate in barrels of oil per day for the oil well(s) being tested.”

Comment: API is OK with these changes. However, the estimated venting emissions using 

Equation W-17A (for oil wells) or Equation W-17B (for gas wells) for well testing venting and 

flaring are indicated to result in gas volumes at actual conditions. For oil wells, the GOR term 

used to estimate the gas volume is in units of standard cubic feet per barrel. For gas wells, the 

average annual production rate is determined for standard conditions. API requests that these 

equations be revised to utilize gas flow rates in standard conditions.

Response: The EPA thanks the commenter for their support regarding the proposed changes to 

§98.233(1). Regarding revising Equations 17-A and 17-B to standard conditions, we are 

finalizing revisions to the introductory text at §98.233 and §98.236 to clarify that use of systems 

that correct to standard conditions is allowed for these equations. See Section II.B.13 of the 

preamble to the final rule for additional discussion responding to this comment.

13.0 Associated Gas Venting and Flaring

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 8

Comment: Associated Gas Venting and Flaring: API supports EPA’s proposal to add a term 

to Equation W-18 to account for when part of the associated gas from a gas well goes to a sales 

line while another part of the gas is flared or vented because these amendments will eliminate 

erroneous over-reporting.

Response: The EPA thanks the commenter for their support. The term "SGp,q”, which accounts 

for situations where part of the associated gas from a well goes to a sales line, has been retained 

in the final rule. For additional edits to Equation W-18, see Section II.B.8 of the preamble to the 

final rule.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 59

61
Comment: Associated gas venting and flaring. Revisions to §98.233(m): EPA is proposing to 

modify Equation W-18 to adjust the emissions downward based on the volume of associated gas 

sent to sales or emissions reported elsewhere (such as when associated gas is flared or for gas 

emitted from tank flashing). EPA is defining a new term, EREp,q as:

Emissions reported elsewhere, volume of associated gas for well p in sub-basin q, in standard 

cubic feet, during time periods in which associated gas was vented or flared and for which 

emission source types of this section calculate and report emissions from the associated gas 

stream prior to venting or flaring of the associated gas (i.e., § 98.233(j) for onshore production 

storage tanks).

API supports the addition of the SGp,q term to subtract gas sent to sales from the emission 

estimate. However, API does not support the addition of the EREp,q term. We believe this will 

significantly increase the burden of tracking these “emissions reported elsewhere” with very little 

increase in accuracy. The equation terms are estimated by different methods (the volume of 

associated gas based on GOR, the volume of sales gas from a sales meters, and the volume of 

ERE by other estimation methods), so it is possible that the equation will result in negative 

volumes.

API recommends removing the EREp,q term from Equation W-18 and revising the definition of 

the summation term for the equation to indicate that it applies to associated gas not reported 

elsewhere. This is consistent with the new definition for associated gas venting and flaring which 

states “This does not include venting or flaring resulting from activities that are reported 

elsewhere, including tank venting, well completions, and well workovers.” These changes should 

minimize the potential for double counting emissions from associated gas reported elsewhere.

Response: After considering the public comments, the EPA agrees that the potential for doublecounting emissions using Equation W-18 with emissions reported elsewhere is minimal, 

particularly given the proposed definition of “associated gas venting or flaring.” Therefore, we 

are finalizing Equation W-18 without an ERE term and we are finalizing the definition of 

“associated gas venting or flaring” as proposed. See Section II.B.8 of the preamble to the final 

rule for further discussion regarding this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 121

Comment: Proposed Citation Reference for Associated Natural Gas Venting and Flaring:

§98.236(m)(7), Proposed Rule Text: Total volume of emissions reported elsewhere, in standard 

cubic feet, during time periods in which associated gas was vented or flared and which are 

calculated and reported under other paragraphs of this section, in standard cubic feet (the sum of 

“EREp,q” values used in Equation W-18 of this subpart).

As indicated earlier, API recommends removing the EREp,q term from Equation W-18.

62
Response: As noted in our response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 

59 in this section, we are finalizing Equation W-18 without an ERE term. See Section II.B.8 of 

the preamble to the final rule for further discussion regarding this comment.

14.0 Flare Stack Emissions

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 61

Comment: Flare stack emissions:

Revisions to §98.233(n): EPA is proposing to change mole percent to mole fraction where the 

gas composition is applied to estimate emissions from flares. EPA is also proposing to change 

the volumetric emissions from actual to standard conditions.

API supports these revisions, especially changing the volumetric emissions from actual 

conditions to standard conditions.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 16

Comment: Flare Stacks: To allow for the possibility of missing data in calculating flare stack 

emissions, Kinder Morgan requests that EPA make the following modifications to § 98.233(n) 

indicated in Figure 3:

Figure 3: Proposed Modifications to 40 C.F.R. § 98.233(n).

Proposed 40 C.F.R. § 98.233. Calculating GHG emissions.

(n) Flare stack emissions. Calculate CO2, CH4, and N2O emissions from a flare stack as 

specified in paragraphs (n)(1) through (n)(9) of this section.

. . .

(2) If you have a continuous gas composition analyzer on gas to the flare, you must use these 

compositions in calculating emissions. If you do not have a continuous gas composition analyzer 

on gas to the flare, you must use the appropriate gas compositions for each stream of 

hydrocarbons going to the flare as specified in paragraphs (n)(2)(i) through (n)(2)(iii) of this 

63
section.

. . .

(ii) For onshore natural gas processing, when the stream going to flare is natural gas, use the 

GHG mole fraction in feed natural gas for all streams upstream of the de-methanizer or dew 

point control, and GHG mole fraction in facility specific residue gas to transmission pipeline 

systems for all emissions sources downstream of the de-methanizer overhead or dew point 

control for onshore natural gas processing facilities. For onshore natural gas processing plants 

that solely fractionate a liquid stream, use the GHG mole fraction in feed natural gas liquid for 

all streams. If a measured gas composition is not available for the flare stack, use a 

representative composition for the stream as determined by engineering estimates, process 

knowledge, or best available data.

(iii) For any applicable industry segment required to report flare stack emissions under 

§98.232, when the stream going to the flare is a hydrocarbon product stream, such as methane, 

ethane, propane, butane, pentane-plus and mixed light hydrocarbons, then you may use a 

representative composition from the source for the stream determined by engineering calculation 

based on process knowledge and best available data.

. . .

(5) Calculate GHG volumetric emissions from flaring at standard conditions using Equations W19 and W-20 of this section.

Where:

. . .

ZL= Fraction of the feed gas sent to a burning flare (equal to 1- ZU). This fraction may be

determined by engineering estimates, process knowledge, or best available data.

Response: The missing data procedures are included in §98.235 in the final rule. For gas 

processing plants that do not have gas composition monitors, the reporters must determine the 

GHG mole fraction of the gas stream going to the flare based on whether the stream is from 

upstream or downstream of the de-methanizer or dew point control. Given the amount of time 

available to take the measurement and the routine nature of the measurement, EPA does not 

agree that missing data provisions are necessary to add to paragraph (n)(2)(ii). There are missing 

data procedures retained in §98.235 in the final rule for annual measurement data that allow

reporters to repeat the estimation or measurement activity as soon as possible, including in the 

subsequent calendar year if missing data are not discovered until after December 31, until valid 

data for reporting are obtained.

The EPA agrees with the commenter that the commenter’s suggested revisions to paragraph 

(n)(2)(iii) provide clarity and we have incorporated this change in the final rule. Regarding the 

additional language the commenter suggests for the definition of ZL, we note that this revision is 

unnecessary because ZL is defined as one minus ZU and the definition of ZU includes a provision 

allowing “engineering estimate and process knowledge based on best available data and 

operating records.”

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15.0 Centrifugal and Reciprocating Compressors 

15.1 Comments on proposed requirements for conducting volumetric emissions 

measurements for centrifugal or reciprocating compressors vented to 

common manifold or flare

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 18

Comment: Proposed Rule revisions for measuring manifolded compressor sources are not 

adequately supported, and implementation will not be safe or practical in some cases.

It appears that EPA proposed rule revisions for measuring centrifugal and reciprocating 

compressor source emissions routed to a common vent manifold without review and analysis of 

available information. EPA has not defined the prevalence of manifolded systems that preclude 

individual compressor source measurement, and has not included justification for these proposed 

revisions. EPA is in possession of e-GGRT data and BAMM requests that could assist in 

defining the population of affected units. EPA has not adequately supported the need to 

independently categorize this subset of compressor source measurements or to require more 

frequent (i.e., three times per year) measurements. EPA should justify why emissions estimated 

from reporter emission factors obtained from other existing measurements do not provide a 

suitable and viable emissions estimate from compressors with manifolded vent lines.

The Proposed Rule and EPA technical support document (TSD)9 fail to address the following 

fundamental practical issues that may preclude measurement from many manifolded compressor 

sources: unsafe to access and technically infeasible measurement locations; and vent gas from 

manifolded compressor sources that is comingled with gas from other emission sources. Previous 

industry comments and discussions, as well as numerous BAMM requests, have addressed the 

safety and technical feasibility issues with accessing and measuring certain vent lines. The 

discussion below explains how the Proposed Rule requirement to measure manifolded 

compressor source emissions at a single point in the manifold downstream of all compressor 

inputs and where emissions cannot be comingled with other non-compressor emission sources 

retains the fundamental issue precluding measurement of individual compressor sources that are 

manifolded. All the manifolded compressors and other comingled sources would need to be 

shutdown, blown down, and purged, thus resulting in unnecessary GHG emissions, in order to 

safely install sample ports and re-pipe vent lines (as needed to avoid comingling) to isolate 

emissions from the manifolded compressor sources.

The Proposed Rule requires three measurements per year for manifolded compressor sources, 

taken before emissions are comingled with other non-compressor emission sources. This 

requirement appears to be arbitrary and is not supported by data or conclusions drawn from 2011 

or 2012 reported data or by defined data quality objectives. EPA has randomly concluded that 

three measurements per year are necessary to address "annual process variability" representative 

of an entire year. However, EPA has failed to demonstrate what additional insight may be 

65
obtained from three dissimilar measurements (e.g., compressor modes may or may not be the 

same from one test to the next) that could not be ascertained from a single measurement.

The following two paragraphs from the TSD illustrate EPA opinions that are unsupported by 

credible data or basis for belief. These opinions have been used to establish a test frequency 

based on a perception that accuracy will be improved. Data quality and accuracy estimates are 

precluded by the inability to drawn meaningful conclusions from manifolded compressor source 

emissions measurements discussed further below). For example, EPA has failed to explain or 

expound on how manifolded source-mode emissions data are expected to be different from other 

compressor source emissions data and why three measurements are expected to reduce 

measurement uncertainty associated with dissimilar measurements. In addition, three 

measurements per year are not supported by a cost-effectiveness determination as discussed 

below. Example text from the TSD or preamble follows.

"The EPA considered requiring only one or two measurements per year for these manifolded 

sources (as opposed to the EPA proposal above for the average of three measurements). The 

EPA concluded that the annual process variability for these sources was high enough to 

warrant more than one or two measurements per year." [79 FR 13402] [emphasis added]

"However, the process variation in a manifold fed by several sources over the year could be 

high enough that overall data quality could be reduced if one or two measurements are not 

representative of the entire year’s operations. The option to require three annual 

measurements from a single point in a manifold would likely reduce overall burden on reporters, 

while ensuring a more representative data set and better data quality than collecting one or 

two data points. Any of these options to require annual measurements would resolve the 

reporter’s concerns about the technical and safety issues with installing and utilizing 

sampling ports in manifolded lines. The accuracy of these options would vary with the 

number of annual measurements that would be required." [emphasis added]

Following this logic, one would conclude that using an emission factor developed from tens, 

hundreds, or thousands of measured data points would be more accurate, provide even greater 

data accuracy, be more representative, and reduce uncertainty and improve data quality. An 

emission factor approach (e.g., reporter emission factor) for manifolded sources reduces 

uncertainty and provides a viable emission estimation method that could be based on thousands 

of data measurements if developed from the entire data set of measurements completed to date. 

Adding 2013 and 2014 data, the uncertainty would be further reduced and the emissions estimate 

would be improved. So EPA is essentially requiring that the reporter develop an "emission 

factor" based on three measurements of a conglomerated set of units operating in various modes 

accounting for various emission sources; yet, as discussed in comments on emission estimation 

alternatives, EPA ignores an approach that uses a source-mode specific emission factor based on 

potentially hundreds of measurements. The lack of consistent logic relates to EPA’s failure to 

consistently apply reasonable data quality objectives, as discussed in Comment 11.

Footnotes:

66
9 "Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Proposed Rule," EPA-HQ-OAR-2011-

0512-0065 (February 20, 2014)

Response: See Section II.B.11 of the preamble to the final rule for EPA’s response to this 

comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 19

Comment: Proposed Rule revisions would substantially increase industry burden and EPA has 

inaccurately estimated costs.

EPA has misrepresented the rule revision as a positive change beneficial to industry and a 

reduction in burden:

"Reporters would no longer be required to annually measure compressor sources that are 

manifolded individually. Instead, reporters would measure the manifolded group of compressor 

sources three times per year. Therefore, this proposed change is a burden reduction for reporters 

that have more than three compressor sources manifolded together."10

"For example, if a reporter operates seven compressors that have their blowdown vent stacks 

manifolded, the reporter would no longer have to conduct seven measurements every year (one 

for each blowdown vent stack) as required by the current rule. Instead, for this example, the 

reporter would be required to only conduct a measurement three times per year on the common 

vent stack that is associated with the manifolded group of seven compressor sources, which 

would decrease burden for the reporter compared to the seven measurements currently required." 

[79 FR 13402]

In concluding that the burden is lessened, EPA has failed to address the cost and potential 

logistical problems associated with mobilization of a test team two additional times per year (i.e., 

total of three times a year) to conduct measurements on manifolded compressor sources. 

Comment 9 provides additional discussion of actual costs associated with three separate annual 

measurements, and discusses logistical and scheduling issues associated with third party crews 

that are often committed to other surveys (as opposed to mobilizing for a single measurement). 

In addition, there are logistical costs to mobilize operations personnel and coordinate with Gas 

Control to complete these additional measurements. Alternatively, costs would be incurred to 

acquire equipment and train staff at each site to conduct the two additional measurements.

Further, EPA has not addressed the burden (possibly exorbitant if it is necessary to repipe 

existing systems to avoid co-mingling) associated with installing sample ports on manifolded 

configurations. All compressors that are connected to the common manifold would be required to 

be shutdown, blown down (increasing GHGs), and purged in order to safely install sample ports 

67
and enable manifolded measurements unless the measurements could be safely conducted at the 

vent line exhaust. Further, the Proposed Rule requires that manifolded compressor source 

emissions must be measured "at a single point in the manifold downstream of all compressor 

inputs and where emissions cannot be comingled with other non-compressor emission sources." 

[§98.233(p)(4)(i)] Thus, for compressor sources with emissions comingled with other sources, a 

sample port would need to be installed prior to the comingling of gases from the compressor 

sources and the non-compressor sources, and the manifolded compressors and other sources 

would need to be shutdown, blown down (increasing GHGs), and purged in order to safely 

install sample ports and re-plumb vent lines (as needed to avoid comingling) and enable 

manifolded measurements. Operational costs include manpower across multiple disciplines (e.g., 

operations coordination, selection of test port location, welders with hot work permits, etc.) and 

equipment to coordinate and execute port installation.

Feasibility issues concerning both the technical issues and costs for re-plumbing are not 

considered and could be significant problems. Adding the option to conduct measurements of 

manifolded compressor sources was intended to reduce burden by not requiring all compressors 

to be simultaneously shutdown to safely install sample ports on individual units. However, the 

requirement to conduct a measurement at a location where compressor source emissions cannot 

be comingled with other non-compressor emission sources would in many cases require the 

shutdown of all associated equipment.

Footnotes:

10 "Assessment of Impacts of the 2014 Proposed Revisions to Subpart W," EPA-HQ-OAR-2011-

0512-0063 (February 20, 2014).

Response: The EPA appreciates the suggestions provided by the commenter and we have made 

revisions to the manifolded compressor measurement requirements as a result of comments 

received. We are allowing a single annual measurement similar to other compressor sources. In 

addition, we are revising the sampling requirement from the proposed rule so that the final rule 

reads as follows “Measure at a single point in the manifold downstream of all compressor inputs 

and, if practical, prior to comingling with other non-compressor emission sources”. See Section 

II.B.11 of the preamble to the final rule for further discussion regarding the final requirements 

for manifolded compressors.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 20

Comment: The manifolded compressor source measurement data will have limited utility (i.e., 

data that are not comparable to non-manifolded compressor source data).

Treatment of other industries in the GHGRP is clear – the objective is not to require 

measurement of every emission source and alternatives to measurement (e.g., emission factors, 

68
engineering estimates) are common for developing the facility inventory. Similar treatment 

should be afforded for T&S sources. For manifolded lines, other options, such as use of emission 

factors specific to the emission source and operating mode of interest, are available (i.e., reporter 

emission factors). It is unclear what EPA expects to learn from measurements that will likely 

include different operating modes (i.e., different emission sources), because information on the 

individual compressor sources cannot be discerned. Numerous compressor mode-source 

combinations are possible for each manifolded measurement, and measured emissions cannot be 

associated with an individual compressor source. That is, measurements from a common vent 

outlet cannot be used to characterize or understand annual emissions from individual 

compressors where multiple dissimilar vents (compressor source and mode) have been routed 

together.

EPA has not provided data or analysis to compare or contrast manifolded compressor sources 

with non-manifolded compressor sources. Further, EPA has not explained how manifolded 

compressor source emissions data will be integrated in the inventory – or will be used to address 

the GHGRP objective to inform future policy. Simplifying assumptions that apportion the 

emissions by unique compressor mode-source combinations are likely to result in larger 

emissions uncertainties and fail to provide better data quality than emission factor approaches.

The proposed rule requirements for manifolded measurements will provide dissimilar data that 

cannot be merged with existing 2011 – 2013 data and cannot be used to inform a heretofore 

undefined issue or concern that EPA has identified. Similarly, EPA has not supported its position 

for requiring measurements from all sources (refer to Comments 11 and 13). These 

measurements will not provide meaningful information regarding compressor source emissions.

Response: The EPA appreciates the concerns expressed by the commenter. The manifolded 

measurement alternatives were provided, in part, to address the technical and safety concerns for 

these sources that were raised during implementation of the rule. In this case, measurements are 

needed to characterize the emissions from the compressors. While credible and accurate 

emissions factors can provide a cost-effective means of calculating GHG emissions for purposes 

of reporting under Part 98, at this time, the deferral of key data, such as reporter emission factors 

for the various compressor sources, limits our ability to develop representative emission factors. 

See Section II.B.11 of the preamble to the final rule for further discussion regarding the final 

requirements for manifolded compressors.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 21

Comment: Emissions from manifolded compressor sources that are comingled with other 

sources, unsafe to access, or technically infeasible to measure should be estimated using 

emission factors. Emission measurement requirements for measureable-manifolded compressor 

sources should be limited to a single annual measurement.

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Manifolded compressor sources that are comingled with other sources, unsafe to access, or 

technically infeasible to measure should be exempt from emissions measurements, and their 

emissions can be estimated using emission factors. As discussed above, extraordinary effort to 

measure emissions from these sources is not warranted because the measurement data would 

have limited utility.

Annual emissions measurements from measureable manifolded groups of compressor sources 

should be treated the same as non-manifolded vent sources, and required to conduct a single 

annual emissions measurement. The same feasibility issues (safety, other access issues) that 

apply to single compressor vents also may apply to manifolded lines. EPA has not supported the 

need to differentiate this subset of emission sources nor provided a viable alternative to improve 

the emissions estimates from manifolded sources. As proposed, this alternative will not provide a 

greater understanding or meaningful insight into GHG emissions from manifolded compressor 

sources, as the sources will likely be measured in different modes and then averaged together. 

The resulting reported emissions from this alternative will provide a value for that measurement, 

but will not provide useful data or information to enhance the understanding of compressor 

sources. The proposed requirement also does not address concerns regarding the burden and 

costs associated with three separate measurements, the installation of sample ports, or shutdown 

complications (i.e., shutting down all units at the same time) for port installation.

Should EPA disregard the above request to revise measurement requirements for manifolded 

compressor sources and retain tri-annual measurement requirements, EPA should:

• Demonstrate that manifolded compressor source emissions data are necessary (e.g., identify 

data gaps and information voids in the absence of direct source measurements) through 

thoughtful consideration of existing reported data for these sources;

• Establish data quality objectives and define the purpose and end use of these measurements

(i.e., explain how dissimilar data will be utilized and the expected outcome from these 

emission data);

• Support claims that three measurements will provide more insight on variability than one 

measurement per year and that three measurements support the associated data quality 

objective;

• Discuss representativeness of manifolded compressor source measurements in different 

modes;

• Justify the cost and burden necessary to meet data objective(s);

• Provide an alternative for sources that are physically unable to safely access a location in the 

manifold downstream of all compressor streams and where emissions are not comingled with 

other non-compressor emission sources.

Response: The EPA considers measurement of manifolded compressors to be important. The 

EPA has revised the monitoring frequency to once per year for manifolded systems. See Section 

II.B.11 of the preamble to the final rule for further discussion regarding the final requirements 

for manifolded compressors.

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Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 51

Comment: Manifolded Lines: EPA seeks comment on the Proposed Rule requirement to 

measure manifolded compressor sources emissions at least three times per year at a location 

where compressor source emissions cannot be comingled with other non-compressor emission 

sources. As discussed in Comment 8, for measurement of manifolded compressor sources, EPA 

has not provided adequate technical justification for the proposed requirement for three 

measurements each year, and has greatly underestimated the costs associated with three separate 

measurement team mobilizations. Emission measurement requirements for measureable 

manifolded compressor sources should be limited to a single annual measurement. Manifolded 

lines where compressors sources are comingled with other emission sources should rely on 

reporter emission factors developed for individual compressors. 

Response: The EPA has revised the monitoring frequency to once per year for manifolded 

systems. See Section II.B.11 of the preamble to the final rule for further discussion regarding the 

final requirements for manifolded compressors.

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 12

Comment: The issue of measuring manifolded compressor vent lines is addressed in the 

proposal by requiring at least three measurements of emissions from the common vent header 

over the year and reporting an average of these measurements. Since our company and many 

other companies conduct annual surveys using a contract service, this approach would be a 

logistical challenge to implement and likely more costly using contractors; the use of in-house 

resources versus contractors may need to be evaluated if this part of the proposal is finalized. 

EPA has specifically requested comment on options for measuring emissions from manifolded 

compressor vent lines. Rather than this proposal, we request that company average emission 

factors be used for sampling points affected by manifolded vent lines. Currently in the e-GGRT 

Subpart W data entry spreadsheet, the reporter indicates which compressor units have 

manifolded vent lines. We request that the Subpart W spreadsheet be further modified to prompt 

the reporter to enter a "Not measured" value for each affected sampling point. The rule currently 

requires that the reporter fill in company average emission factors for sampling points not 

measured during the reporting year in the "Not Measured" fields. Using company average 

emission factors for sampling points affected by manifolded vent lines would provide more 

accurate emission rate information than the current proposal of averaging three or more 

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combined measurements. Combined (manifolded vent) measurements will not provide useful 

sampling point information for specific operating modes.

Response: The EPA has revised the monitoring frequency to once per year for manifolded 

systems. See Section II.B.11 of the preamble to the final rule for further discussion regarding the 

final requirements for manifolded compressors.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 12

Comment: Williams does not support the requirement of three measurements per year for 

commonly manifolded vents to atmosphere. Like many companies, Williams uses a third-party 

contractor to conduct annual compressor monitoring as part of our greenhouse gas emissions 

inventory. The proposed amendment would create significant logistical complications in 

scheduling the third-party for return to facilities with manifolded compressor vents. The added 

margin of statistical accuracy and relevancy resulting from EPA’s proposed change would be 

very limited.

For these reasons, Williams believes annual as-found measurements are of sufficient frequency 

for purposes of the GHG inventory. Also, as discussed previously, Williams objects to the 

collection of flow rate measurements in a manifolded flare header system for safety reasons.

Response: The EPA has revised the monitoring frequency to once per year for manifolded 

systems. See Section II.B.11 of the preamble to the final rule for further discussion regarding the 

final requirements for manifolded compressors.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 62

Comment: API supports the revisions to the emission estimation methods for centrifugal 

compressors that allow measurements at the manifold for compressors routed to manifolds. This 

provides added flexibility and addresses safety concerns. However, EPA should recognize that 

there may still be some manifolded compressors that do not currently have measurement ports at 

a location where the compressor sources are not comingled with other sources, or where it is 

unsafe to access or technically infeasible to measure emissions. An emission factor approach is 

needed for these situations. In addition, annual emission measurements from measureable 

manifolded compressors should be treated the same as non-manifolded emission sources and 

required to conduct a single annual emission measurement.

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Response: The EPA thanks the commenter for their support. While credible and accurate 

emissions factors can provide a cost-effective means of calculating GHG emissions for purposes 

of reporting under Part 98, the deferral of key data, such as reporter emission factors for the 

various compressor sources, limits our ability to develop representative emission factors. In 

response to this and similar comments, the EPA has revised the monitoring frequency to once per 

year for manifolded systems. See Section II.B.11 of the preamble to the final rule for further 

discussion regarding the final requirements for manifolded compressors.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 68

Comment: API supports the revisions to the emission estimation methods for reciprocating 

compressors that allow measurements at the manifold for compressors routed to manifolds. This 

provides added flexibility and addresses safety concerns. However, EPA should recognize that 

there may still be some manifolded compressors that do not currently have measurement ports at 

a location where the compressor sources are not comingled with other sources, or where it is 

unsafe to access or technically infeasible to measure emissions. An emission factor approach is 

needed for these situations. In addition, annual emission measurements from measureable 

manifolded compressors should be treated the same as non-manifolded emission sources and 

required to conduct a single annual emission measurement.

Response: The EPA thanks the commenter for their support. While credible and accurate 

emissions factors can provide a cost-effective means of calculating GHG emissions for purposes 

of reporting under Part 98, the deferral of key data, such as reporter emission factors for the 

various compressor sources, limits our ability to develop representative emission factors. In 

response to this and similar comments, the EPA has revised the monitoring frequency to once per 

year for manifolded systems. See Section II.B.11 of the preamble to the final rule for further 

discussion regarding the final requirements for manifolded compressors.

Commenter Name: Brian Korpics

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2011-0512-0087-A2

Comment Excerpt Number: 6

Comment: A variety of analyses have utilized Subpart W data to help deepen understanding of 

emissions from the oil and gas sector, including the Annual Inventory of U.S. Greenhouse Gas 

Emissions and Sinks and efforts by academics and other researchers to assess emissions, which 

have provided essential independent information about emissions from this sector.17 We 

specifically support many of the proposed revisions to Subpart W—listed below—that would 

enhance the ability of the public and policy makers to use the data in future contexts like these.

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• Centrifugal and reciprocating compressors. EPA also proposed to modify reporting 

requirements for centrifugal and reciprocating compressors routed to a common vent 

manifold.20 Under the revisions, operators may take three aggregate measurements annually 

for all of the manifolded compressors. Direct measurements are important for this emissions 

source. At the same time, we respectfully urge the Agency to ensure that other key 

information from each of the compressors in a common manifold is also reported, including 

information on the operating mode of each manifolded compressor at the time the 

measurement is made.21

Footnotes:

17 See, e.g., David Allen et al., Measurements of methane emissions at natural gas production 

sites in the United States, 110 PNAS 17,768 (2013); A. R. Brandt et al., Methane Leaks from 

North American Natural Gas Systems, 343 SCI. 733 (2014).

20 Fed. Reg. at 13,402–03.

21 A simple aggregate of emissions from the manifolded compressors would provide potentially 

misleading information from these important emission sources, as all of the compressors might 

not be fully functioning at the time the measurement is made.

Response: The EPA thanks the commenter for their support. The EPA has taken steps to ensure 

that key information from each of the compressors in a common manifold will be reported. The 

final rule at §98.236(o)(1)(iv) and (v) and §98.236(p)(1)(v) through (vii) requires activity data, 

including mode information during the time of measurement, to be reported for each compressor 

whether the compressor is part of a manifolded group or not.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 14

Comment: 13. Manifolded vents with different compressor sources: GPA supports INGAA’s 

comments regarding the various issues associated with the proposed manifolded vent 

measurement requirements. Additionally, GPA notes that in many cases, different compressor 

sources may be manifolded together. For example, a rod packing vent can be piped to the 

blowdown vent. This situation does not appear to be fully contemplated in the proposed rule; 

rather, the proposed rule only appears to contemplate the same compressor sources (i.e., rod 

packing vents) being manifolded together. EPA should not consider this type of configuration to 

be "co-mingling."

14. Replace "8760" with "T" in Equations W-24B and W-29B: If the entire manifolded group of 

compressor sources is not operating, reporters should be allowed to account for downtime. For 

example, if the manifolded group of compressor sources consists of reciprocating compressor 

rod packing sources (or centrifugal compressor wet seal oil degassing vent sources), and all of 

74
the compressors are not operating (such as when a gas plant is down), then these emissions 

should not be calculated during this downtime.

Es,i,g = Tg * MTs,g,avg * GHGi,g 

Tg = Total time the manifolded group of compressor sources g had potential for emissions in 

the reporting year, in hours. Include all time during which at least one compressor source in 

the manifolded group of compressor sources g had potential for emissions. Default of 8760 

hours may be used. 

Response: The EPA disagrees with the commenter that the proposed rule does not allow 

different compressor sources to be manifolded together. The rule at §98.238 defines a 

manifolded group of compressor sources as “a collection of any combination of manifolded 

compressor sources (as defined in this section) that are manifolded to a common vent” [emphasis 

added]. However, the EPA agrees with the commenter that, if the entire manifolded group of 

compressor sources is not operating, reporters should be allowed to account for this downtime. 

Therefore, the EPA has replaced "8760" with "Tg" in Equations W-24B and W-29B. To provide 

greater clarity, the EPA has defined "Tg" as “the total time the manifolded group of compressor 

sources g had potential for emissions in the reporting year, in hours. Include all time during 

which at least one compressor source in the manifolded group of compressor sources g was in a 

mode-source combination specified in either paragraph (o)(1)(i)(A), (o)(1)(i)(B), (p)(1)(i)(A), 

(p)(1)(i)(B), or (p)(1)(i)(C) of this section. Default of 8760 hours may be used.”

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 31

Comment: Unclear requirements regarding manifolded groups of compressors that contain 

centrifugal and reciprocating compressors: 98.233(o)(9) and 98.233(p)(9) both contain the 

language (analogous language for reciprocating compressors), "If the centrifugal compressors 

included in the manifolded group of compressor sources share the manifold with reciprocating 

compressors, you must follow the procedures in either this paragraph (o)(9) or paragraph (p)(9) 

of this section to calculate emissions from the manifolded group of compressor sources." Why is 

this sentence included here (for continuous monitoring method) but not in 98.233(o)(8) and 

98.233(p)(8) (for as found measurements method)? It would appear that this sentence should be

included in all of these sections or in none of them.

Response: The EPA included this language to clarify that the calculation does not need to be 

repeated if centrifugal compressor sources are manifolded together with reciprocating 

compressor sources. We agree that this clarification is applicable and necessary in §98.233(o)(8) 

and (p)(8) and we are including this clarification in these paragraphs in the final rule.

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15.2 Proposed definitions for "compressor mode", compressor source", 

"manifolded compressor source", and "manifolded group of compressor 

sources"

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 4

Comment: Several definitions are proposed to be changed or added to provide needed clarity to 

the rule. The changes in definitions will clarify and provide consistency going forward in our 

understanding of these terms. . . Revised definitions of "compressor", "compressor mode", and 

"manifolded group of compressor sources" are proposed that clarify the meaning and provide 

further detail regarding the scope of these terms. We support these changes that provide needed 

clarity.

Response: The EPA thanks the commenter for their support. The EPA is clarifying the 

definition of “compressor source” in this final rule to specify the applicability of the rule to 

specific compressor emission sources. See Section II.B.11 of the preamble to the final rule for 

additional discussion responding to this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 40

Comment: The definition of "Compressor source" in §98.238 and referenced in §98.236(o) and 

(p) should be revised to improve clarity. Suggested revisions include:

"Compressor source, for the purposes of Subpart W, means a specific type of compressor 

seal or valve. These include (wet seals, blowdown valves, and isolation valves) on a centrifugal 

compressor and blowdown valves, isolation valves, and rod packing on a reciprocating 

compressor."

Response: The EPA is clarifying the definition of “compressor source” in this final rule to 

specify the applicability of the rule to specific compressor emission sources. See Section II.B.11

of the preamble to the final rule for additional discussion responding to this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 36

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Comment: (§98.238) New definition for compressor source Compressor source means any 

type of vent or valve (i.e., wet seal, blowdown valve, isolation valve, or rod packing) on a 

centrifugal or reciprocating compressor.

The broad language in this proposed definition is not acceptable. It is not sufficiently clear to 

manage compliance and could lead to broad interpretation to sources not specifically called out 

in the rule. API requests that the definition for compressor source be revised to specifically list 

the required sources rather than include them in a parenthetical.

"For the purposes of Subpart W, compressor source means blowdown valve leakage through the 

blowdown vent, wet seal oil degassing vents, and unit isolation valve leakage through an open 

blowdown vent without blind flanges for centrifugal compressors. For reciprocating 

compressors, compressor source means blowdown vent leakage through the blowdown vent 

stack, rod packing emissions, and unit isolation valve leakage through the blowdown vent 

without blind flanges."

Response: The EPA is clarifying the definition of “compressor source” in this final rule to 

specify the applicability of the rule to specific compressor emission sources similar to the 

clarification suggested by the commenter. See Section II.B.11 of the preamble to the final rule 

for additional discussion responding to this comment.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 15

Comment: New definition of "compressor source": EPA proposes a definition for the term 

"compressor source." GPA supports defining this term. However, as suggested by API, this 

definition must be changed to specifically indicate which compressor emission sources are 

covered by the rule. The proposed rule defines compressor sources as "any type of vent or valve 

(i.e., wet seal, blowdown valve, isolation valve, or rod packing) on a centrifugal or reciprocating 

compressor." The phrase "any type of vent or valve" is too vague. See API’s comments for 

suggested language changes.

Response: The EPA is clarifying the definition of “compressor source” in this final rule to 

specify the applicability of the rule to specific compressor emission sources. See Section II.B.11

of the preamble to the final rule for additional discussion responding to this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 37

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Comment: (§98.238) New definition for manifolded compressor source Manifolded 

compressor source means a compressor source (as defined in this section) that is manifolded to a 

common vent that routes gas from multiple compressors. Comment: API supports this new 

definition and the flexibility it provides in allowing safer measurements at the manifold.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 38

Comment: §98.238) New definition for manifolded group of compressors Manifolded group 

of compressor sources means a collection of any combination of manifolded compressor sources 

(as defined in this section) that are manifolded to a common vent.

API supports this new definition.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 44

Comment: Revisions to §98.232: EPA modified the source category for reciprocating engines 

in the list of sources to be reported for onshore petroleum and natural gas production facilities. 

98.232(c)(11) Reciprocating compressor rod packing venting.

It appears EPA is making these revisions for consistency with the definition of compressor 

source under §98.238 and requirements for reciprocating compressors under §98.233(p), which 

apply to blowdown valve leakage, isolation valve leakage, and rod packing leakage. API 

supports the removal of “rod packing” from the source category name for reciprocating 

compressor venting contingent upon EPA adopting the proposed definition of compressor source 

under §98.238. The proposed definition of compressor source is needed with this revision to 

prevent an expanded interpretation of emissions reporting for reciprocating compressors.

Response: The commenter is correct that the proposed revisions are intended to harmonize with 

revisions to the definition of “compressor source”. The EPA is adopting revisions to the 

definition of “compressor source” in this final rule. See Section II.B.11 of the preamble to the 

final rule for additional information.

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15.3 Revisions to calculation and reporting of emissions for compressors routed 

to a flare

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 24

Comment: Misleading statement regarding compressors routed to flare. 98.233(o)(12)(i) is 

circular in that is contains calculation requirements, but it also says that the calculation 

requirements of 98.233(o) do not apply. Additionally, it would be clearer to replace "emission 

calculations" with "requirements" since many of the paragraphs in (o) include emission 

calculations and measurement requirements. Analogous changes are suggested for section 

98.233(p) as well. The following revision is suggested:

98.233(o)(12)(i) Emissions calculations under this paragraph (o) Paragraphs (o)(1) through 

(o)(11) of this section are not required for compressor sources that are routed to a flare. 

98.233(p)(12)(i) Emissions calculations under this paragraph (p) Paragraphs (p)(1) through 

(p)(11) of this section are not required for compressor sources that are routed to a flare. 

Response: The EPA agrees with the commenter’s suggested edits and has incorporated these 

revisions into the final rule.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 10

Comment: While Williams agrees that compressor emissions routed to an operation flare 

should be reported under the flare source category, we object to the requirement that flow rates 

(part of the specified activity data) be collected for compressors routed to flare.

Collecting discrete flowrate measurements in a closed piping system routed to a flare is 

potentially dangerous. A leak monitoring contractor for Williams reported instances at nonWilliams facilities where they observed air entering the closed flare header system during 

compressor monitoring events. This could create an explosive environment within the flare 

header system. A second concern is potentially exposing workers to hydrogen sulfide.

Installing continuous flow meters on a closed piping system routed to flare for the purposes of 

compressor GHG monitoring would be very burdensome and disruptive to plant operations. 

Williams proposes the following alternative, consistent with calculation methods employed for 

other emission sources routed to flare. Allow reporters to use best engineering estimates and 

process knowledge when calculating and reporting compressor emissions routed to flare. The 

79
company-wide emission factors developed for the various compressor mode – source 

combinations, along with compressor run times, could be effectively used to develop these 

engineering estimates.

Response: The EPA has evaluated the commenter’s concerns and has determined the final rule 

does not need to be revised. The final rule at §98.233(o)(12)(ii) and (p)(12)(ii) specifies that “if 

any compressor sources are routed to a flare, calculate the emissions for the flare stack according 

to paragraph (n) of this section and report emissions from the flare according to §98.236(n), 

without subtracting emissions attributable to compressor sources from the flare.” The flare 

provisions at §98.233(n)(1) allow a reporter to use engineering calculations based on best 

available data or company records to estimate the flow to the flare that is not continuously 

measured. No change has been made to the final rule as a result of this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 69

Comment: API supports the revisions that permit calculating and reporting compressor flare 

emissions with other flared sources, and that provide the flexibility to continuously measure 

emissions. API supports the proposed change to calculate and reporting emissions from 

compressors routed to flares to be reported with other flare emissions. API request that EPA 

consider including the same provision for other emissions sources that are routed to a flare, such 

as dehydrator vents. Because the language included at §98.233(p)(12)(ii) was not included for 

these sources, emissions attributed to vent streams from these sources that are routed to a flare 

are still required to be subtracted from the flare emissions and reported under the specific source 

of the vent stream per §98.233(n)(9).

Response: The EPA thanks the commenter for their support. We did not propose to change the 

calculation procedures for these other sources to consider only cumulative emissions from flare 

stacks; therefore, we conclude that the additional revisions suggested by the commenter are 

beyond the scope of this rulemaking. However, the EPA may consider the commenter’s 

suggestions in a future rulemaking.

15.4 Revisions to 3-year cycle requirement, schedule to measure compressors in 

the not-operating-depressurized mode, & schedule to measure 

compressors in the operating mode

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 5

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Comment: Compressor testing is inordinately expensive: For example, one GPA member 

company operates 28 compressors at four natural gas processing plants subject to reporting under 

subpart W of the Mandatory Greenhouse Gas Reporting Rule (GHG MRR, 40 CFR part 98). 

Since they have only a few facilities subject to subpart W, they have opted to outsource their 

GHG compressor monitoring to a third party contractor who specializes in this type of work. 

Their decision to outsource monitoring was based on cost, data quality, and consistency of 

approach. After two years of monitoring, they have robust data on the actual cost of compressor 

monitoring

In their experience, minimizing the number of mobilizations is key to minimizing third party 

monitoring costs. There are a couple of ways the contractor can minimize mobilizations. First, 

the contractor can multitask by conducting infrared camera leak monitoring and compressor 

monitoring during the same site visit. Second, the contractor can arrange to visit several facilities 

in the same geographic area during a single trip. With these cost saving measures implemented, 

their actual 2013 compressor monitoring costs came to $4,176 per facility or $597 per 

compressor.

The downside to this approach is that compressor monitoring cannot be scheduled around facility 

or compressor shutdowns. Instead, compressors are monitored "as found", and they are usually 

found to be operating. After two years of monitoring they have only managed to collect "not 

operating depressurized" (NOD) mode date for 12 of 28 compressors [43 percent (%)]. Since this 

is their third year of monitoring, the remaining 16 compressors are required to be monitored in 

the NOD mode in 2014. These 16 compressors seldom operate in the NOD mode (21% of the 

time on average in 2013). Some are in the NOD mode for only 3 or 4 days all year. Further, they 

rarely have multiple compressors at a single facility operating in the NOD mode simultaneously. 

To monitor these 16 compressors in the NOD mode in 2014 will require multiple mobilizations 

to each facility, and these monitoring events will need to be tightly scheduled around planned 

maintenance shutdowns. The cost and logistics of scheduling will be formidable challenges. 

2014 NOD monitoring requirements will add $4,544 per facility ($1,136 per compressor) to their 

2014 compressor monitoring cost.

Based on monitoring data collected to date, they know that NOD mode compressor emissions are 

minimal. The total methane (CH4) emissions from all 28 compressors in the NOD mode in 2013 

was 0.8 metric tonnes (mt) (20.2 mt carbon dioxide equivalent [CO2e]), as reported in their 

calendar year 2013 GHG emission inventories in EPA's electronic Greenhouse Gas Reporting 

Tool (e-GGRT). (The CO2 emissions are less than 0.5% of the CH4 emissions on a CO2e basis so 

are not considered in this analysis).

This company’s experience shows that the rule’s strict requirement to conduct NOD mode 

monitoring is leading to absurd results, where a contractor is having to drive hundreds of miles to 

mobilize to their facilities several times over the course of the year, burning fuel and producing 

CO2 in the process, in order to collect 16 NOD measurements.

Their experience also shows that the monitoring requirement is not cost effective. On a per ton 

basis, their costs to conduct 2014 NOD mode compressor monitoring will exceed the typical cost 

to control criteria pollutants using best available control technology (BACT). For example, the 

total additional cost to conduct NOD monitoring in 2014 is $18,174 (for four facilities) while the 

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total reported NOD emissions for all compressors in 2013 was 0.8 mt CH4. This translates to a 

monitoring cost of $22,492.57 per mt of CH4 emitted.

Monitoring compressors "as found": While GPA continues to assert that compressor testing 

should not be required, while testing is still required, GPA supports INGAA’s comments 

regarding compressor measurements and that they should be completed "as found" without 

mandating mode-specific measurements. As shown above, coordinating measurement efforts 

with compressor operations is extremely challenging. EPA has not provided evidence that data 

gaps exist to justify a mode-specific measurement requirement. Additionally, EPA has not 

provided an assessment of how this data element impacts the overall GHGRP inventory data 

accuracy, and whether mode-specific measurements result in data quality improvements that 

justify the additional burden.

Response: In an effort to reduce the burden associated with measuring compressors in the NOD 

mode, we are augmenting the three-year measurement requirement, as proposed with minor 

revisions, to specify that reporters must take a measurement in the NOD mode at least once in 

any three consecutive calendar years, provided the measurement can be taken during a scheduled 

shutdown. If three consecutive calendar years occur without measuring the compressor in NOD 

mode, you must measure the compressor at the next scheduled depressurized shutdown. With 

respect to the commenter’s assertion of the minimal nature of NOD mode emissions, the data 

available to us suggests that these emissions are not always as small as those indicated by the 

commenter and, for some industry segments, NOD mode emissions contribute significantly to 

the total annual emissions from compressors. As more data become available to estimate NOD 

mode emissions, including data that are inputs to emissions equations that have been deferred 

until 2015, the EPA may consider further revisions to the NOD mode measurement requirements 

in a future rulemaking. See Section II.B.11 of the preamble for additional discussion regarding 

the final requirements for compressor mode measurements.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 7

Comment: For Compressor Venting Measurements, Subpart W Should Rely Exclusively on the 

Annual "As-Found" Measurement, Rather than Mandating Mode-Specific Measurements at 

Specific Intervals.

Subpart W currently requires reporting entities to collect GHG emission data from each 

compressor vent on an annual basis "in the operating mode in which it is found" (referred to 

herein as "as-found" mode). This provision further requires the reporting entity to specify 

whether the as-found mode was: (i) operating; (ii) standby pressurized; or (iii) not-operating, 

depressurized.8 Subpart W also currently requires testing in the not operating, depressurized 

mode at least once every three consecutive calendar years.

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The Proposed Rule would retain both the annual as-found requirement and the three-year testing 

requirement for not-operating, depressurized compressors. Further, it would add another 

mandated, mode-specific testing requirement: a requirement to test the emissions of centrifugal 

compressors in the operating mode once in any three consecutive years; if the centrifugal 

compressor is not measured in the operating mode at least once in any three consecutive years, it 

must be measured in the operating mode in the next calendar year that the compressor operation 

exceeds 2,000 hours.9

Data already submitted to EPA demonstrate that the annual compressor testing requirement –

without consideration of data submitted only as a result of the three-year compressor notoperating, depressurized testing requirement – has yielded extensive data on compressor 

emissions, including in each of the three operating modes. As explained in the INGAA 

comments, the first two years of Subpart W reporting have generated more than a thousand 

reciprocating compressor measurements for each of the three operating modes, and hundreds of 

centrifugal compressor measurements for each of the operating modes. Because the annual asfound measurements already generate such extensive data on emissions in all three modes, 

further mode- and time-specific testing does not result in meaningful additional emissions data 

beyond what is already being collected in the as-found mode.

Not only does the Proposed Rule fail to justify the need for further mode- and time-specific 

testing requirements, it also fails sufficiently to justify the unreasonable added costs 

and complexity imposed by these requirements. In addition to the already substantial costs and 

complexity of the annual compressor measurements, the existing three-year requirement creates 

cumbersome scheduling and logistical issues for measurement personnel. Because of EPA’s 

three-year requirement, Subpart W measurement teams are required to schedule costly “out-ofsequence” tests that significantly raise the cost of annual measurements.10 The Proposed Rule is 

flawed because it fails to provide sufficient justification to continue to require not operating, 

depressurized mode measurements every three years. Elimination of this continued requirement 

would result in significant cost savings to pipeline operators.

Footnotes:

8 Section 98.233(o)(1) provides that centrifugal compressors have two modes: operating and not 

operating, depressurized, and § 98.233(p)(1) provides that reciprocating compressors 

additionally have a third mode: standby pressurized mode.

9 Proposed § 98.233(o)(1)(i)(D).

10 INGAA’s comments note that compressor measurement costs its members between $3,000 

and $6,000 per year per compressor, without consideration of scheduling, coordination, and other 

logistical and administrative costs, and without consideration of out-of-sequence costs.

Response: We are not finalizing the requirement to measure in each mode at least once every 

three years although we are retaining, with minor revisions, the requirement to test in NOD mode 

at least once in any three consecutive calendar years, provided the measurement can be taken 

during a scheduled shutdown. If three consecutive calendar years occur without measuring the 

compressor in NOD mode, you must measure the compressor at the next scheduled 

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depressurized shutdown. As more data become available to estimate NOD mode emissions, 

including data that are inputs to emissions equations that have been deferred until 2015, the EPA 

may consider further revisions to the NOD mode measurement requirements in a future 

rulemaking. See Section II.B.11 of the preamble for additional discussion regarding the final 

requirements for compressor mode measurements.

Commenter Name: Ritu Talwar

Commenter Affiliation: Spectra Energy Corp

Document Control Number: EPA-HQ-OAR-2011-0512-0079-A1

Comment Excerpt Number: 2

Comment: Compressor Test Should be Completed in "As-Found" Mode Without Condition: 

Without reasonable justification, EPA proposes to mandate compressor measurements be made 

in specific modes and at specified intervals without consideration for the increased costs and 

operational burdens this mandate imposes. Spectra Energy has collected compressor data in all 

three modes, operating, standby pressurized, and not-operating depressurized and is able to 

generate reporter emissions factors for all modes.

This proposed requirement presents operational scheduling challenges, increased cost burdens, 

both made unnecessary by the availability of data across all modes of operation. For these 

reasons, it is not necessary to mandate testing in any particular mode. Instead of adopting this 

prescriptive mandate, EPA should allow our industry to measure the equipment in the "AsFound" mode without condition.

Response: See response to comment EPA-HQ-OAR-2011-0512-0077-A1, Excerpt 7 and

Section II.B.11 of the preamble for additional discussion regarding the final requirements for 

compressor mode measurements.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 14

Comment: Proposed EPA Amendment: If there is no scheduled shutdown within three 

consecutive years, a measurement must be made at the next scheduled depressurized compressor 

shutdown.

With this amendment, it appears that EPA is attempting to alleviate the forced shutdown 

scenario. While at some facilities, like gas processing plants, it may achieve this purpose. At 

others locations where facility shutdowns are uncommon (e.g. compressor stations), operators 

would likely force unit shutdowns while the measurement contractor is on site. This would result 

in the unintended consequence of emitting additional greenhouse gases solely for the purpose of 

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obtaining a measurement. Ultimately, Williams believes annual as-found monitoring conducted 

company-wide generates sufficient data for the various compressor mode – source combinations.

Response: See response to comment EPA-HQ-OAR-2011-0512-0089-A3, Excerpt 5 and 

Section II.B.11 of the preamble for additional discussion regarding the final requirements for 

compressor mode measurements.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 8

Comment: Moreover, with respect to the Agency’s proposal to require additional testing in the 

operating mode every three years, EPA has not properly estimated the incremental time and cost 

that operators will incur to comply with the requirement. Contrary to EPA’s assumption that the 

incremental time and costs to collect additional measurements would be unchanged, the 

imposition of this additional three-year mode specific requirement will require additional 

expense to mobilize highly trained measurement teams for yet more out-of-sequence testing.11

The costs of the three-year requirement are not only economic, however; there are also 

environmental impacts. Even though "EPA did not intend for reporters to perform an 

unscheduled shutdown of a facility for the sole purpose of taking a measurement of the 

compressor in the not-operating-depressurized-mode,"12 the three-year requirement has already 

led to unnecessary vented emissions due to shutdown mode tests undertaken by operators solely 

to comply with Subpart W’s three-year measurement requirement.

For these reasons, Kinder Morgan urges EPA to eliminate all compressor testing requirements 

other than the annual, as-found requirement. Companies would still be required to report the 

specific operating mode during which measurements were conducted, and EPA would still 

receive substantially the same amount of data from Subpart W reporting entities.

Footnotes:

11 EPA’s cost analysis does not even assess the costs associated with EPA’s proposed three-year 

operating mode measurement requirement. See "Memorandum-Assessment of Impacts of the 

2014 Proposed Revisions to Subpart W," Alexis McKittrick and Mark Defigueiredo, EPA/CCD, 

Docket ID No. EPA-HQ-OAR-2011-0512-0063 (Feb. 20, 2014) at 3-5.

Response: See response to comment EPA-HQ-OAR-2011-0512-0077-A1, Excerpt 7 and 

Section II.B.11 of the preamble for additional discussion regarding the final requirements for 

compressor mode measurements.

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Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 14

Comment: Compressors 

Annual tests should be completed "as found" and Subpart W should not mandate a 

defined measurement frequency for any specific compressor operating mode. 

The Proposed Rule includes two new requirements that define the frequency for completing 

compressor vent measurements for a specific compressor operating mode. One requirement is a 

derivative of the current requirement to test reciprocating and centrifugal compressors in 

shutdown, de-pressurized mode (hereinafter referred to as "shutdown mode" in this comment). 

The other is a new requirement to test centrifugal compressors in operating mode once every 

three years, or the next calendar year that compressor operation exceeds 2,000 hours if operating 

mode is not measured in the previous three years. This is a new requirement, never before raised 

by EPA, and its addition has not been justified in the preamble or support documents. INGAA 

does not support these requirements and recommends testing compressors in the "as found" 

mode. Subpart W data collected to date indicates that collectively, measurements are being 

completed in all required compressor modes so industry data exists (and will continue to grow) 

to characterize emissions for each compressor mode – source combination in §98.233(o) and (p). 

In summary, compressor measurements should be completed in the "as found" mode and EPA 

should not prescribe test frequency for any particular mode.

The preamble discusses options related to mandatory testing in shutdown mode and requests 

comment. It is INGAA’s understanding that inclusion of a mandatory frequency for shutdown 

mode tests in the current rule dates back to EPA concerns circa 2009 – 2010 that there would be 

a lack of data collected in this mode. However, 2011 and 2012 data demonstrate that T&S 

sources completed hundreds of measurements in this mode and there is approximately the same 

number of "as found" tests completed in shutdown mode as other modes. Thus, it is not 

necessary to mandate testing in this or any mode. Mandating shutdown measurement frequency 

will result in unnecessary, additional emissions and costs, as well as logistical issues for 

scheduling out-of-sequence tests. For example, to accommodate logistical complications from 

mandatory shutdown tests, in some cases operating units will be shut down and blown down 

while test crews are completing their scheduled site visit. This results in unnecessary emissions 

and can have a cascade affect for other units and facilities where the mode may also be changed 

to address facility or system demands.

Response: See response to comment EPA-HQ-OAR-2011-0512-0077-A1, Excerpt 7 and

Section II.B.11 of the preamble for additional discussion regarding the final requirements for 

compressor mode measurements.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

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Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 17

Comment: The Proposed Rule adds a new requirement for centrifugal compressors to complete 

operating mode tests every three years or the next year that compressor operation exceeds 2,000 

hours if operating mode measurement is not completed in the previous three years. Thus, for 

centrifugal compressors, EPA has increased stringency without providing the regulatory basis, 

identifying the benefit, or justifying the data need. INGAA is strongly opposed to this revision 

since its need is unsubstantiated and Subpart W measurement data reported to date indicates 

hundreds of operating mode tests were completed in the first two years.

The new requirement mandates measurement in operating mode at least once every three years 

or in a subsequent year when unit operation next exceeds 2,000 annual hours. EPA does not 

provide explanation or justification for this new requirement in the preamble or within any of the 

supporting documents. The time interval has no basis, and it is premature to establish any 

mandatory interval without first reviewing the 2011 – 2013 measurement data that has already 

been provided. Without any record supporting this arbitrary and capricious change, INGAA 

recommends deleting the requirement proposed in §98.233(o)(1)(i)(D). Similar to the discussion 

above, this requirement will add logistical problems, incur costs far in excess of EPA’s presumed 

costs for completing measurements, and result in scenarios where scheduling a third party 

contractor is not feasible.

Based on experiences in 2011 and 2012, INGAA was surprised that the Proposed Rule retained –

and expanded – mandatory schedules for mode-specific tests. EPA should revise the proposed 

rule to eliminate mandatory mode-specific test schedules and require annual measurement in the 

"as found" mode. As demonstrated in data reported to date, there is an abundance of data to 

review and analyze across all mode-source combinations for both reciprocating and centrifugal 

compressors. Reported 2011 and 2012 data provide a reasonable number of measurements in 

each mode, and additional data will be available from recently submitted 2013 data and data 

collected in 2014. Retaining the proposed requirements is unnecessary and will further increase 

compliance costs, introduce significant logistical challenges, and require access to testing 

alternatives through missing data provisions.

Response: See response to comment EPA-HQ-OAR-2011-0512-0077-A1, Excerpt 7 and 

Section II.B.11 of the preamble for additional discussion regarding the final requirements for

compressor mode measurements.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 24

Comment: Section 98.233(o)(1)(i)(D) requires centrifugal compressors be measured in the 

operating mode:

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− "...at least once in any three consecutive calendar years, provided that the measurement can be 

taken when the compressor is in operating-mode. If three consecutive calendar years occur

without measuring the compressor in operating-mode, you must measure the compressor as 

specified in paragraph (o)(1)(i)(A) of this section in the next calendar year that the compressor is 

in operating-mode for more than 2,000 hours."

This new requirement in the Proposed Rule is not mentioned, discussed, or justified in the TSD. 

Further, the TSD fails to consider available data (i.e., reported emissions data by mode for 2011 

and 2012) when assessing mandatory test frequencies for centrifugal compressors in the 

operating mode, and reciprocating and centrifugal compressors in the not operating, depressurized mode. EPA has not demonstrated that data from thousands of tests show a shortage 

of measurements for any particular compressor mode-source combination, or the need for the 

rule to mandate testing in any particular mode.

Response: See response to comment EPA-HQ-OAR-2011-0512-0077-A1, Excerpt 7 and 

Section II.B.11 of the preamble for additional discussion regarding the final requirements for 

compressor mode measurements.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 6

Comment: The Proposed Rule includes two new requirements that define the frequency for 

completing compressor source emission measurements for a specific compressor mode. One 

requirement is a derivative of the current requirement to test reciprocating and centrifugal 

compressors in the not operating depressurized mode at least once every three years. The other 

requirement is new, and mandates that if a centrifugal compressor is not tested in the operating 

mode at least once in any three consecutive years, then the annual compressor measurement must 

be conducted in the operating mode the next year that operating hours exceed 2,000. 

Measurement data collected to date, however, do not support the need for these new test 

frequency requirements.

SoCal Gas has about 43 compressors subject to Subpart W and has been measuring compressor 

vent flows since 2011. Many measurements have been collected, which are more than adequate 

to characterize emissions for each compressor mode - source combination in §98.233(o) and (p). 

There is no evidence that these mandates for compressor vent measurement frequency will 

improve the measurement inventory. Furthermore, they will only introduce logistical 

complications for scheduling out-of-sequence tests and unnecessarily increase compliance costs.

In addition, EPA has not demonstrated the need for, defined the benefit of, or estimated 

associated costs for the prescribed measurement interval mandates. EPA has not provided any 

explanation or justification in the preamble or within any of the supporting documents for the 

new measurement frequency requirement for centrifugal compressors in operating mode. At a 

minimum, EPA should review and analyze 2011- 2013 measurement data to ascertain any need 

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prior to mandating any measurement frequencies. SoCal Gas operates compressors ranging from 

25 HP -15,200 HP. Currently, the requirements for testing are the same for all compressors 

regardless of size or operation (ex. Vapor recovery).

Based on an absence of support for these mandatory testing intervals, So Cal Gas recommends 

that all annual compressor source measurements be conducted in the as-found compressor mode 

and that the mandatory testing interval subsections and associated reported activity data in the 

Proposed Rule be deleted. In addition, small, very low pressure compressors should be excluded 

from the testing requirements, using a default population emission factor similar to LNG storage.

Response: See response to comment EPA-HQ-OAR-2011-0512-0077-A1, Excerpt 7 and 

Section II.B.11 of the preamble for additional discussion regarding the final requirements for 

compressor mode measurements.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 49

Comment: Frequency of Measurement in Shutdown, De-pressurized Mode: EPA discussed 

options related to mandatory testing in shutdown, de-pressurized mode and requested comment. 

It is INGAA’s understanding that mandatory frequency for shutdown mode tests is included in 

the current rule due to EPA concerns that there would be a lack of data in this mode. However, 

2011 and 2012 data show that T&S sources completed hundreds of measurements in this mode 

and there are about the same number of "as found" tests completed in shutdown mode as other 

modes. Thus, it is not necessary to mandate testing in this or any mode. Mandating shutdown 

measurement frequency will result in unnecessary emissions and costs as well as logistical issues 

for scheduling out-of-sequence tests.

Response: See response to comment EPA-HQ-OAR-2011-0512-0089-A3, Excerpt 5 and 

Section II.B.11 of the preamble for additional discussion regarding the final requirements for 

compressor mode measurements.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 21

Comment: EPA’s proposals to mitigate the burdens of the three-year, mode-specific testing 

requirements are also inadequate as proposed. Acknowledging that its three-year mode-specific 

requirement "could present a compliance challenge for some facilities, because not every facility 

schedules routine shutdowns for maintenance within 3 years," EPA proposes to provide an 

exception to the three-year requirement for compressors that do not undergo a "scheduled 

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shutdown" during a three-year consecutive period. For such compressors, emissions 

measurements in the not operating, depressurized mode can be made at the next "scheduled 

shutdown" (for reciprocating compressors, during the next “scheduled shutdown” when the 

compressor rod packing is replaced).13

EPA’s proposed "scheduled shutdown" exception to the three-year requirement will not avoid 

many of the costs associated with mandatory testing in not operating, depressurized mode, such 

as out-of-sequence scheduling costs or the obligation to maintain records on compressor 

shutdown testing status. However, the shutdown exception could provide relief to operators if it 

provides enough time for operators to coordinate the scheduling of third-party measurement 

service providers with the scheduled shutdown. These measurements are usually scheduled 

several months in advance.

If EPA does not eliminate the three-year, mode-specific requirements, as Kinder Morgan 

requests, it should clarify the term "scheduled shutdown" to make the exception useful to 

operators. It could do so by clarifying that "scheduled shutdown" refers to a major maintenance 

outage that is scheduled months in advance, as opposed to a shutdown scheduled in direct 

response to a particular event (e.g., in response to change in demand or operational disruption). 

Shutdowns are frequently scheduled to occur just days after a triggering event, and it would be 

logistically challenging and potentially impossible to schedule an internal Kinder Morgan or 

external contractor measurement team to perform an emission measurement in advance of these 

types of short-notice shutdowns. Kinder Morgan believes that EPA intends for this "scheduled 

shutdown" exception to refer only to major maintenance shutdowns with long lead times, and 

requests that EPA adopt a more specific definition.

Footnotes:

12 Proposed Rule at 13403.

13 Proposed §§ 98.233(o)(1)(i)(C) and (p)(1)(i)(D).

Response: We are retaining, with minor revisions, the requirement to test in NOD mode at least 

once in any three consecutive calendar years, provided the measurement can be taken during a 

scheduled shutdown. If three consecutive calendar years occur without measuring the 

compressor in NOD mode, you must measure the compressor at the next scheduled 

depressurized shutdown. We have clarified in the final rule that “...a scheduled shutdown means 

a shutdown that requires a compressor to be taken off-line for planned or scheduled maintenance. 

A scheduled shutdown does not include instances when a compressor is taken offline due to a 

decrease in demand but must remain available.” See Section II.B.11 of the preamble for 

additional discussion regarding this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 16

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Comment: For centrifugal and reciprocating compressors, the Proposed Rule specifies similar 

measurement requirements for not operating-depressurized-mode:

§98.233(o)(1)(i)(C):

"You must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section at least 

once in any three consecutive calendar years, provided the measurement can be taken during 

a scheduled shutdown. If three consecutive calendar years occur without measuring the 

compressor in not-operating-depressurized-mode, you must measure the compressor as specified 

in paragraph (o)(1)(i)(B) of this section at the next scheduled depressurized shutdown." 

[emphasis added]

§98.233(p)(1)(i)(D):

"You must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at least 

once in any three consecutive calendar years, provided the measurement can be taken during 

a scheduled shutdown. If there is no scheduled shutdown within three consecutive calendar 

years, you must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section 

either prior to or during the next compressor shutdown when the replacement of the 

compressor rod packing occurs." [emphasis added]

Although the rule text includes a necessary qualification "provided the measurement can be 

taken during a scheduled shutdown," ambiguity remains regarding what constitutes a shutdown. 

Although EPA attempts to address issues with mandatory shutdown mode testing that resulted in 

many BAMM requests in 2013 (and likely 2014), practical concerns remain. It is unclear how a 

requirement for a test at the next "shutdown" would be interpreted. A number of companies have 

a corporate safety policy prohibiting or limiting standby, pressurized mode of operation when 

compressor operation is not required. In these cases, when a compressor is taken offline, it is 

depressurized (i.e., de-energized) within a specified time frame for safety reasons. Transmission 

compressors often start up and operate to meet pipeline demand; these compressor are then taken 

offline (i.e., "shutdown") when demand decreases. It is not clear if this "shutdown" meets the 

intent of the revised rule text, and this interpretation would be a logistical impossibility to 

implement.

In most instances, a unit taken offline (i.e., operation not needed due to pipeline demand) should 

not be considered "scheduled shutdown." Planning and mobilization of a third party test group is 

not possible in this case and would be logistically difficult if not impossible. Third party 

mobilization would be extremely complicated even for planned shutdowns with a significant lead 

time. As noted above, INGAA members have tested nearly 1,000 total compressors, and tracking 

and scheduling systems will need to be developed and implemented to address this EPA 

requirement. It is not feasible or practical to mobilize a test crew to address a unit shut down on 

short notice. Most companies use third party contractors to complete annual measurements. 

Contractor crews are actively engaged in schedules where they proceed to affected facilities 

along a pipeline to complete annual measurements and then move on to the next pipeline. EPA 

has not considered the logistical issues for scheduling third party "out-of-sequence" tests or the 

additional costs and added burdens imposed by this requirement. As discussed in Comment 9, 

EPA cost estimates show a fundamental lack of understanding of measurement program 

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requirements. While some situations may be able to accommodate this schedule, other situations 

will not have such flexibility. As a result, mandating shutdown measurement frequency in any 

form will yield an outcome that EPA wants to avoid: unnecessary vented methane emissions will 

occur as operators accommodate a mandatory shutdown mode test within the required three year 

(or five year) period.

INGAA strongly believes that mandatory testing in shutdown mode is not warranted and has not 

been justified. Several items related to compressor "scheduled shutdown" and test scheduling 

must be considered:

• Some compressors start up and shut down frequently to meet pipeline demand, but may be 

operating or in standby mode when the "as found" test is conducted. EPA should 

acknowledge that Gas Control operations dispatches compressors as necessary to meet 

demand and that unit shutdowns may occur that preclude a measurement. The rule text 

includes a necessary caveat regarding a scheduled shutdown. It would appear to indicate that 

EPA intends for this requirement to apply to a shutdown of longer duration, such as those 

associated with major maintenance and a unit’s unavailability for dispatch. If EPA retains 

this approach, clarifying text should be provided (e.g., preamble discussion) as well as a rule 

definition for "scheduled shutdown." Due to logistics, including test crew commitments and 

availability, significant lead time (e.g., multiple months) may be required to accommodate 

testing during a "scheduled" shutdown, and these complications must be considered in rule 

definitions and requirements.

• Even if EPA intends for scheduled shutdown to mean extended compressor shutdown for 

major maintenance, scheduling and logistical issues remain – e.g., getting a test team to a site 

with relatively short notice; tracking shutdown test status and operations shutdown plans for 

each individual compressor. Most companies rely on third party service providers to conduct 

site surveys and measurements, which are often scheduled up to 6 months or more in 

advance, especially for the spring through fall (i.e., after early year cold weather and 1st 

quarter reporting is addressed and well in advance of the year-end deadline). Attempting to 

align station operations and maintenance with service providers increases the burden and 

costs, and may result in circumstances where a crew is not available, or would charge a 

significant additional fee. In addition, major maintenance activities may preclude safe 

measurement and source access due to the nature of the engine driver or compressor 

maintenance activities. In some cases, only essential staff members are allowed in proximity 

due to safety concerns.

• EPA has either not estimated or significantly under-estimated costs and has not defined the 

benefit (or even demonstrated the need for a prescribed measurement interval) for this 

mandate. The existing count of mode-specific Subpart W measurement data from 2011 and 

2012 contradicts EPA’s perception that this provision is necessary

• As discussed in Comments 3 through 6, access to alternatives is imperative to address 

measurement challenges. Missing data provisions should be relied on when needed.

Response: We are retaining, with minor revisions, the requirement to test in NOD mode at least 

once in any three consecutive calendar years, provided the measurement can be taken during a 

scheduled shutdown. If three consecutive calendar years occur without measuring the 

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compressor in NOD mode, you must measure the compressor at the next scheduled 

depressurized shutdown. In the final rule, we are using consistent language for both centrifugal 

and reciprocating compressors to require reports that have not tested in the NOD mode for three 

consecutive years to test “...at the next scheduled depressurized shutdown.” We have also 

clarified in the final rule that “...a scheduled shutdown means a shutdown that requires a 

compressor to be taken off-line for planned or scheduled maintenance. A scheduled shutdown 

does not include instances when a compressor is taken offline due to a decrease in demand but 

must remain available.” See Section II.B.11 of the preamble for additional discussion regarding 

this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 41

Comment: In §98.233(p)(1)(i)(D), it is not clear what is meant by "scheduled shutdown". 

Clarification is needed to provide operators a clearer understanding – and there must be a 

reasonable, and potentially significant, lead time available to schedule and mobilize a test team. 

A similar clarification should be made for §98.233(o)(1)(i)(C). In both cases, significant lead 

time may be needed to address logistics, including test crew schedule and availability. INGAA 

does not support mandatory testing in shutdown mode. If that issue is addressed, then guidance 

on "scheduled shutdown" would not be necessary.

Response: We have clarified in the final rule that “...a scheduled shutdown means a shutdown 

that requires a compressor to be taken off-line for planned or scheduled maintenance. A 

scheduled shutdown does not include instances when a compressor is taken offline due to a 

decrease in demand but must remain available.” See Section II.B.11 of the preamble for 

additional discussion regarding this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 64

Comment: In the preamble, EPA notes that they did not intend for reports to perform an 

unscheduled shutdown of a facility for the sole purpose of taking a measurement of the 

compressor in the not-operating- depressurized-mode. API supports the revision to allow this 

measurement to be taken during the next scheduled depressurized shutdown. However, there are 

instances when a scheduled compressor shut-down is only for a short duration, such that it is not 

possible to complete the measurement. In other situations, a “scheduled shutdown” may occur 

without sufficient lead time to arrange for or mobilize a measurement team. EPA has not 

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considered the logistical requirements to arrange for and conduct these measurements. API 

requests some additional wording to §98.233(o)(1)(i)(C) to address these issues:

"...you must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section

at the next scheduled depressurized shutdown of sufficient duration and lead time."

Response: The clarification requested by the commenter is open to significant interpretation and 

could be used by reporters as a means of not testing during any scheduled shutdown. We have 

clarified in the final rule that “...a scheduled shutdown means a shutdown that requires a 

compressor to be taken off-line for planned or scheduled maintenance. A scheduled shutdown 

does not include instances when a compressor is taken offline due to a decrease in demand but 

must remain available.” See Section II.B.11 of the preamble for additional discussion regarding 

the final requirements to measure compressors in the NOD mode.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 146

Comment: In the preamble, EPA notes that they did not intend for reporters to perform an 

unscheduled shutdown of a facility for the sole purpose of taking a measurement of the 

compressor in the not-operating-depressurized-mode. API supports the revision to allow this 

measurement to be taken during the next compressor shutdown when the replacement of the 

compressor rod packing occurs.

Response: The EPA thanks the commenter for their support. See Section II.B.11 of the 

preamble for additional discussion regarding the final the requirements to measure compressors 

in the NOD mode.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 7

Comment: If the Proposed Rule measurement frequency by mode mandates are retained, then 

requirements associated with next scheduled depressurized shutdown should consider the 

logistics of conducting measurements and obtaining activity data. For centrifugal and 

reciprocating compressors, the Proposed Rule specifies similar measurement requirements for 

the not operating depressurized-mode:

§98.2339o)(1)(i)(C):

"You must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section at least 

once in any three consecutive calendar years, provided the measurement can be taken during 

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a scheduled shutdown. If three consecutive calendar years occur without measuring the 

compressor in not-operating-depressurized-mode, you must measure the compressor as specified 

in paragraph (o)(1)(i)(B) of this section at the next scheduled depressurized shutdown." 

[Emphasis added]

§98.233(p)(1)(i)(D):

"You must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at least 

once in any three consecutive calendar years, provided the measurement can be taken during 

a scheduled shutdown. If there is no scheduled shutdown within three consecutive calendar 

years, you must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section 

either prior to or during the next compressor shutdown when the replacement of the 

compressor rod packing occurs." [Emphasis added]

§98.236

(o)(l)(xvi) "Date of last maintenance shutdown that compressor was depressurized"

(p)(l)(xvi) "Date of last maintenance shutdown for rod packing replacement"

Although the rule text provides a qualification "provided the measurement can be taken during a 

scheduled shutdown" regarding the mandated test schedule, there is ambiguity regarding what 

constitutes a scheduled shutdown, and practical considerations remain. Primary concerns 

include:

• When taken out of service or shut-down, a unit may not be depressurized (i.e., de-energized). 

Depressurization might only occur during major equipment overhaul depending upon the 

facility operating configuration.

• Planning and mobilization of a test team can be logistically difficult, even for planned 

shutdowns with a significant lead-time. It is not feasible or practical to mobilize a test crew 

to address a unit shut down on short notice because they are typically actively engaged in test 

schedules to complete annual measurements. EPA has not considered the logistical issues for 

scheduling "out-of-sequence" tests or the additional cost or added burden imposed by this 

requirement.

Because operators are obligated to dispatch compressors as necessary to meet demand, unit 

shutdowns may occur that preclude a measurement. The Proposed Rule needs a practical 

definition regarding a scheduled shutdown that includes a shutdown of longer duration and likely 

associated with major maintenance and unit unavailability for dispatch. SoCal Gas proposes the 

following:

• "for the purposes of this testing, "scheduled shutdown" is a shutdown that plans for the unit 

to be taken out of service, includes compressor depressurization, and that is scheduled at least 

three weeks in advance and has a duration no less than 96 hours."

Response: The clarification requested by the commenter has specificity. In response to public 

comments, we have clarified in the final rule that “...a scheduled shutdown means a shutdown 

that requires a compressor to be taken off-line for planned or scheduled maintenance. A 

scheduled shutdown does not include instances when a compressor is taken offline due to a 

decrease in demand but must remain available.” While we have not provided a minimum lead 

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time or duration for the scheduled shutdown, this revision clarifies our intent that the 

maintenance has to be planned or scheduled in advance and that the maintenance requires that 

the compressor be taken off-line (depressurized) to be considered a scheduled shutdown. See 

Section II.B.11 of the preamble for additional discussion regarding the final requirements to 

measure compressors in the NOD mode.

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 11

Comment: Although we have not used the BAMM provisions to date, BAMM has typically 

been used to estimate emissions from equipment that is not available in a specific operating 

mode at the time of the annual measurement survey; for example, compressor vents are required 

to be measured in a "depressurized, not operating" mode every three years. It may not be 

possible to conduct this measurement without interrupting natural gas service since units may be 

required to be operating at the time of the survey to provide natural gas to customers. The 

proposed rule seeks to address this situation by allowing operators to measure this mode during a 

scheduled shutdown. If there is no scheduled shutdown within three consecutive calendar years, 

then a measurement would have to be made during the next scheduled depressurized shutdown. 

EPA has specifically requested comment on the option of requiring measurement in this mode 

every five years rather than every three years to provide companies a larger window of 

opportunity to make the measurement. We request extension of the required monitoring 

frequency to once every five years to provide additional flexibility in monitoring, however, this 

change will not result in 100% certainty that a unit will be available at a specific time. This 

requirement should be viewed in conjunction with the "missing data" provisions and emission 

factors developed for this operating mode as soon as feasible, since this is one of the most 

problematic emissions measurements to obtain.

Response: See response to comment EPA-HQ-OAR-2011-0512-0089-A3, Excerpt 5 and

Section II.B.11 of the preamble additional discussion regarding the final requirements to measure 

compressors in the NOD mode.

15.5 Use of as found leak measurements to develop reporter emission factors in 

Equations W-23 and W-28.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 2

Comment: Proposed EPA Amendment: For reporters that elect to conduct as-found leak 

measurements for individual compressor sources, all measurements from a single owner or 

96
operator may be used when developing emission factors. These emissions factors must be 

applied to all reporting facilities for the owner or operator.

Williams is supportive of the amendment, as it allows more measurements to be used in 

calculating representative compressor emission factors for the various compressor mode – source 

combinations.

Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 70

Comment: API also supports the change and appreciates EPA revising the rule language to 

include a clear option to calculate the compressor emission factor using either measurements 

from a single facility, or using all measurements from a single owner or operator. However, the 

current and proposed rule language leave room for interpretation as to what is meant by 

“reporter” as no definition was included in the rule. A Frequently Asked Questions document 

published by EPA in July 2011 provided clarification to the entity EPA considered to be the 

“reporter” for purposes of calculating compressor emission factors to be applied to emissions not 

measured during the annual test (inserted below). If the proposed change is included in the final 

rule, API recommends that EPA include language in the rule that addresses the meaning of 

“reporter” as addressed in the FAQ included below.

Question: Need clarification on what entity the “reporter” is in terms of developing the 

compressor emission factors for measurements conducted in the “as found” mode and 

applied to other compressors. This applies to processing, storage, transmission, and LNG 

operations. Is the “reporter” the facility, or all facilities operated by the same company?

Response: For purposes of developing the compressor emission factors for measurements 

conducted in the “as found” mode, EPA intended the “reporter” to be all facilities 

operated by the same company. In other words, the company could develop an emission 

factor, and apply it to all facilities operated by the same company. EPA has reviewed 

your question and cannot provide further guidance at this time. Your question relates to 

an issue or issues currently the subject of ongoing litigation. Please monitor the website 

for any additional guidance that may be available in the future.

http://www.epa.gov/climatechange/emissions/subpart/w.html

Response: The EPA evaluated the commenter’s concerns and has determined the rule does not 

need to be revised. As allowed at §98.233(o)(6)(iv) and §98.233(p)(6)(iv) of the final rule, the 

reporter emission factor may be calculated by using all measurements from a single owner or 

operator instead of only using measurements from a single facility. If you elect to use this option, 

97
the reporter emission factor must be applied to all reporting facilities for the owner or operator. 

No change has been made to the final rule as a result of this comment.

Commenter Name: Ritu Talwar

Commenter Affiliation: Spectra Energy Corp

Document Control Number: EPA-HQ-OAR-2011-0512-0079-A1

Comment Excerpt Number: 5

Comment: As stated in the current rule, section 98.233(o)(6)(i) and 98.233(p)(7)(i)(B), the 3-

year average is developed by creating an annual emission factor and then averaging the 3 years. 

However, as newly written, the proposed Equations W-23 and W-28 have more specific 

language that requires taking all 3 years of data to develop the average, thereby, eliminating the 

annual average. Equation flexibility is needed to maintain the annual average to avoid 

unnecessary costs and reporting burden of modifying existing data systems.

Response: The EPA disagrees with the commenter’s interpretation of the existing requirements 

in the current rule at §98.233(o)(6)(i) and §98.233(p)(7)(i)(B). The current rule at 

§98.233(o)(6)(i) and §98.233(p)(7)(i)(B) requires reporters to use all measurements from the 

current calendar year and the preceding two calendar years (totaling three consecutive calendar 

years of measurements) to calculate the annual emission factor. The current rule does not allow 

the reporter to calculate an annual average emissions factor and then average three annual 

average emissions factors together. However, we note that, if one retains the so-called “annual 

average emissions factors” and the count of compressors measured during each year, one can 

easily calculate the correct average emissions factor (weighting each annual emission factor by 

the number of measurements made during each year of the three year period). No change has 

been made to the final rule as a result of this comment.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 11

Comment Excerpt: (g) 98.236(o)(2)(vii) "...For emission vents associated with individual 

compressor sources that use an as found leak measurement(s), calculate emissions by summing 

all emissions from all compressor mode-source combinations for the emission vent." If this 

requirement is kept in the final rule, this calculation requirement should be housed in 

98.233(o)(6) under a new requirement 98.233(o)(6)(v). Since it is a required calculation, it 

should not be described in the reporting section of the rule. This same comment and suggested 

correction also applies to the analogous requirements in 98.236(p) and 98.233(p).

Response: The provision noted by the commenter was inadvertently included in the proposed 

rule. Similar to the requirements in the current rule, the EPA intended to have the emissions 

reported separately for each compressor source at each compressor as specified in the proposed 

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rule at §98.236(o)(2) and (p)(2). In the final rule, the reporting requirements for compressors 

have been revised to more clearly indicate that the reporting requirements apply to each 

compressor source leak or vent. We recognize that manifolded compressors and compressors 

with continuous leak measurements may include emissions across different compressor sources, 

but for single compressors using at found measurements, emissions reporting will be the same as 

in previous years (by compressor source for each compressor).

15.6 Comments on other minor revisions and restructuring of reporting 

requirements for centrifugal and reciprocating compressors

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 29

Comment: The proposed revision that eliminates acoustic device measurement for blowdown 

valves is arbitrary and capricious.

The previous comment notes instances where acoustic instruments are allowed for leak 

detection, and Subpart W also includes the acoustic leak detection device for leak rate 

quantification in §98.234(a)(5).

However, the Proposed Rule introduces new limitations for using the acoustic device method for 

quantifying through-valve leakage. As discussed in Comment 13, EPA must re-visit its decisions 

in previous amendments to understand the significant problem this change causes, because EPA 

added the acoustic method for leak quantification in an attempt to remedy June 2010 comments 

on the re-proposed Subpart W rule.

The 2010 Subpart W Final Rule added the acoustic method for leak quantification for 

measurements where through-valve leakage is the emission source, including transmission 

condensate tank dump valves, compressor isolation valves, and compressor blowdown valves. 

The Proposed Rule eliminates use of the acoustic method for blowdown valve leakage 

measurements for reciprocating compressors in operating mode or standby pressurized mode, 

and centrifugal compressors in operating mode. This revision is not explained or justified. In 

addition, as discussed in the following comment, eliminating this method will introduce 

significant compliance challenges for operators. Since EPA added the method to Subpart W in an 

attempt to respond to comments regarding safety issues for some vent measurements, elimination 

of the acoustic method for vent measurements associated with blowdown valve leakage 

undermines EPA’s perceived solution to INGAA’s comments. Since addition of the acoustic 

method was EPA’s solution to measurement challenges, this proposed revision compromises the 

ability of operators to comply. During the 2010 rulemaking, other recommendations offered by 

INGAA were not implemented by EPA. Operators did not necessarily agree with EPA’s decision 

to add the acoustic method, as opposed to alternative approaches or other measurement methods, 

including the IR camera. However, the acoustic method is now integral to Subpart W 

compliance. Revisions to method applicability is unsupported in the preamble or background 

documents. Elimination of the acoustic method for blowdown valves is untenable unless the 

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original comments from INGAA and others are revisited. Comment 13 provides additional 

background and details regarding this issue.

Response: The EPA has retained the acoustic device measurement method in the final rule. See 

Section II.B.11 of the preamble to the final rule for additional discussion responding to this 

comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 30

Comment: EPA cannot eliminate use of acoustic device measurement unless significant other 

issues are addressed.

The Proposed Rule eliminates acoustic device measurement for compressor blowdown valve 

leakage. As discussed above, EPA has not explained this revision. During the 2010 Subpart W 

rulemaking, INGAA offered other recommendations to address vents that are unsafe to access or 

technically infeasible to measure through both its written comments and during industry 

meetings with EPA; INGAA would be open to revisiting this issue. However, based on EPA’s 

2010 decisions as reflected in the November 2010 Subpart W Final Rule and explained in EPA’s 

responses to comments, the acoustic method is integral to the ability of operators to meet Subpart 

W measurement obligations. Use of the acoustic device must be retained without revisions or 

significant other issues must be addressed.

Since 2009, there has been considerable discussion about the inability of operators to safely 

access or feasibly measure all vents. Through comments and meetings with EPA, INGAA 

explained scenarios of concern and offered several recommendations. EPA can reference 

INGAA comments from June 2010, as well as other timeframes for additional detail, but 

example issues and recommendations included:

• The primary consideration in the design and construction of compressor-related vents is to 

safely convey potential gas leakage outside of the compressor house. Measurement or access 

to these vents was not contemplated in station design. In some cases, vent lines are only 

"accessible" at or above the compressor house roofline because compressor house equipment 

and other lines preclude adding access ports at a lower elevation. In addition, in some cases it 

may not be safe to access lines at the roofline because ground-level piping and equipment in 

the vicinity preclude safe access. INGAA has explained this issue in detail and provided 

example pictures in previous comments and meetings.

• INGAA comments and discussions with EPA requested the ability to preclude measurement 

of vent lines that were inaccessible due to safety and other feasibility issues (e.g., line 

masked by other equipment). INGAA and its members were confident that the majority of 

lines could be accessed and measurements completed. However, since measurement had 

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never been required for these lines, the prevalence of lines infeasible to measure was 

uncertain.

• It was noted that rule implementation would document the prevalence of vents infeasible to 

measure, and INGAA members were confident that the vast majority would be measured. In 

addition, other measures, such as IR camera screening of elevated inaccessible vents, could 

be completed to document the prevalence of leakage and vent emissions from inaccessible 

lines.

• INGAA and its members were confident that measurement program implementation would 

document a very high percentage of vent line measurements representative of the population 

of T&S compressors, especially after measures were implemented to address challenging 

situations. INGAA recommended phasing in the measurements over the first few years (or 

access to BAMM) to provide time for operators to engineer solutions (e.g., add sample ports 

during maintenance shutdown) for vent lines with access complications.

• INGAA and its members were willing to work with EPA to identify a minimum threshold of 

measured lines (i.e., the vast majority) and requirements to document measurement issues 

and leak frequency (based on IR camera screening) for vents not measured. This approach 

could have been linked to an alternative data quality objective to replace EPA’s "100% 

measured" goal, as discussed in Comment 11.

This approach would provide ample data to develop reporter emission factors and support 

documentation for vents not measured. In addition, proven direct measurement methods would 

have been used for the very high percentage of vent lines measured. It would not have been 

necessary to add the indirect acoustic method to Subpart W.

However, EPA insisted on measurement of every vent. In response to comments from INGAA 

and others regarding vent lines that are not safe to access or infeasible to measure, EPA added 

the acoustic method for leak quantification to the Subpart W Final Rule in November 2010. Prior 

to its inclusion in the final rule, that method had not been discussed as an alternative. INGAA 

comments regarding flexibility for leak detection had requested the addition of acoustic 

instruments for detecting through valve leakage, and it was INGAA’s understanding that the 

instrument functions well for leak detection. However, acoustic device leak rate quantification 

was added to Subpart W as EPA’s solution to these concerns, as evident in the November 2010 

Response to Comments Document12 (as well as the 2010 Technical Support Document). For 

example, EPA responses to comments about safety and vent measurement feasibility repeatedly 

identify acoustic device measurement as the solution. Several example EPA responses are 

provided:

"EPA recognizes the importance of ensuring safety. Rather than provide exemptions, EPA has 

added alternative reporting methodologies to ensure safety in the collection of data from certain

sources. ... EPA has added in today’s final rule alternative emissions estimating methods which 

can be performed safely when direct, end of stack emissions measurement is deemed unsafe or 

less economical for the reporter. For gas processing, transmission, storage, LNG storage and 

LNG import/export terminals, today’s final rule provides options of installing ports in vent lines 

which are unsafe to access the end of the vent stack, or, ... the use of acoustic detectors which 

101
have algorithms for equating detector readings with through-valve leakage." [Response to 

Comments, Pages 2 – 3]

"Finally, EPA is very aware of safety issue, and today’s final rule adds several alternative 

emissions detection and quantification options to be more cost-effective as well as less 

hazardous... today’s final rule allows the alternative to use an acoustical detector calibrated for 

through-valve leak quantification as an alternative to condensate tank roof vent measurement. 

This same technique is included for through leaking compressor isolation valves." [Response to 

Comments, Page 267]

"In addition, EPA has added options for quantifying emissions as alternative to direct 

measurement of today’s final rule. For example:

• For condensate tank emissions at transmission compressor stations (i.e. leaking scrubber 

dump valves), these emissions can also be estimated by the alternative of testing the dump 

valve directly with an acoustic detector that has an algorithm to estimate through valve 

leakage flow.

• Reciprocating compressor packing vents and blowdown vents also allow use of an acoustic 

detector that quantifies flow. Measurement can also be done by simple piping reconfiguration 

to put a leg of the vent piping out where it can be easily accessible for insertion of a portable 

flow meter (e.g. hot wire anemometer)

• Centrifugal compressor wet seal oil degassing vent and blowdown vents can also use the 

acoustic detector for through leaking blowdown valves.

• All compressor isolation valves can be measured at the blowdown vent or, alternatively, with 

an acoustic detector at the valves themselves." [Response to Comments, Page 291]

"EPA disagrees with the use of an engineering analysis to quantify venting emissions from 

through-valve leakage. These methods will not accurately quantify venting emissions from a 

significant source of emissions to adequately inform future policy decisions. However, today’s 

final rule has been revised and EPA is allowing the use of an acoustic leak detection instrument 

to detect and measure venting emissions from through valve leakage from transmission tanks, 

and centrifugal and reciprocating compressor venting." [Response to Comments, Page 1297]

"EPA agrees that safety should be a primary concern of reporters when monitoring transmission 

storage tanks; please see the response to EPA-HQ-OAR-2009-0923-1024-11. Of particular note, 

EPA allows the installation of permanent flow meters and the use of acoustic instruments so 

reporters can monitor these sources remotely and therefore never compromise safety." [Response 

to Comments, Page 1456]

"In gas transmission compressor stations, EPA has included in today’s final rule the alternative 

of using an acoustic leak detection instrument that has algorithms for through-valve leak 

quantification to estimate compressor scrubber dump valve leakage as an alternative to 

measuring the emissions from the tank roof vent. This alternative acoustic through-valve leak 

measurement technique is also added in today’s final rule for compressor blowdown vent 

through-valve leakage." [Response to Comments, Page 1511]

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These are just some of the examples; there are additional examples in the Response to Comments 

Document. The responses are sometimes specific to one or two of the types of valves related to 

vented emission measurement, but it is clear that EPA adopted the acoustic method for leak rate 

measurement as the solution to safety and vent measurement feasibility issues wherever throughvalve leakage is the emission source that triggers a vent measurement requirement. This decision 

was intended to address EPA’s desire to ensure that 100% of vents are measured.

This EPA decision has resulted in important implementation outcomes, including:

• In some instances, the acoustic method has been used for vent measurements where the 

associated valve is accessible and direct vent measurement was not required because of 

acoustic method availability.

• In the first three reporting years, many reciprocating compressor and centrifugal compressor 

measurements of isolation valve and blowdown valve leakage, and condensate tank dump 

valve leakage, have used the acoustic method. Data reported to e-GGRT for these years 

cannot discern acoustic method data from data acquired using direct measurement methods 

(e.g., meter or anemometer in the line, bagging, high volume sampler).

• There are questions arising about whether measurement methods contribute to the difference 

in compressor methane emission estimates for Subpart W versus the U.S. GHG Inventory.

Note that despite the addition of the acoustic method, BAMM requests have still been necessary 

to address cases where neither the vent line nor valve is accessible. For example, valves are 

sometimes buried or insulated and thus inaccessible. If the vent line is also inaccessible or 

infeasible to measure, INGAA does not expect that EPA wants a valve exhumed for acoustic 

device measurement.

Since EPA’s solution to measurement challenges was addition of the acoustic method, the 

method has been used by operators to comply with Subpart W requirements. It is notable that an 

EPA GHG emission factor project being conducted in the same timeframe, managed by the same 

group that authored Subpart W, discussed acoustic method results in a 2011 report13.

EPA’s decision to rely on the acoustic method as the "silver bullet" for measurement concerns 

has resulted in a method that is now inextricably woven into the fabric of the rule – and must 

remain a measurement option unless the numerous issues raised since 2009 are revisited. In 

addition, any attempt to reconcile the issues will require time for operators to assess and 

implement any new "solution."

The history summarized above – and elaborated on in more detail in previous INGAA comments 

and EPA’s 2010 Response to Comments document – demonstrates that the use of the acoustic 

method cannot be altered without undermining previous decisions that affect the ability of 

operators to comply. The Proposed Rule revision to eliminate use of the acoustic method in some 

cases cannot stand. INGAA welcomes additional conversation on this topic, with the 

understanding that any attempt to alter the current rule must undertake a thorough and thoughtful 

process to define acceptable alternatives to the current measurement paradigm. It is imperative 

that revisions do

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Footnotes:

12 "Mandatory Greenhouse Gas Reporting Rule Subpart W – Petroleum and Natural Gas: EPA's 

Response to Public Comments," (November 2010).

13 Natural Gas Industry Methane Emission Factor Improvement Study. Final Report, 

Cooperative Agreement No. XA-83376101, prepared for U.S. EPA by URS Corporation and 

University of Texas – Austin (December 2011).

Response: The EPA has retained the acoustic device measurement method in the final rule. See 

Section II.B.11 of the preamble to the final rule for additional discussion responding to this 

comment.

Commenter Name: Ritu Talwar

Commenter Affiliation: Spectra Energy Corp

Document Control Number: EPA-HQ-OAR-2011-0512-0079-A1

Comment Excerpt Number: 4

Comment: Acoustic Measurement Device is an Acceptable Compliance Method for Subpart W 

and Proposed Limitations Reduce Measurement Flexibility: The Proposed Rule eliminates use of 

the acoustic method for blowdown valve leakage measurements for reciprocating compressors in 

operating mode or standby pressurized mode, and centrifugal compressors in operating mode. 

We question the rationale for this revision and the lack of meaningful explanation for the change. 

Eliminating this method will introduce significant compliance challenges for the transmission 

and storage sector. For example, Spectra Energy uses an acoustic device to measure potential 

leaks through blowdown valves as an alternative to measuring valve leaks at vent stacks, as 

prescribed in 40 CFR 98.233. Spectra Energy believes that, in these instances, measuring leaks 

using an acoustic detection device is a safer alternative for Spectra Energy’s employees and 

contractors. Because of these efforts to provide an efficient and safe method for leak detection in 

certain situations, Spectra Energy encourages EPA to continue to allow the use of acoustic 

measuring devices.

Response: The EPA has retained the acoustic device measurement method in the final rule. See 

Section II.B.11 of the preamble to the final rule for additional discussion responding to this 

comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 66

Comment: EPA is eliminating the use of acoustic device measurement for blowdown valve 

leakage for centrifugal compressors in operating mode. API objects to this revision as there may 

104
be situations where it is unsafe or infeasible to otherwise measure these emissions. EPA had 

added this provision to remedy issues raised in June 2010 comments on the re-proposed Subpart 

W rule. Removing this option is further complicated by EPA’s proposal to remove the option to

request BAMM, introducing compliance challenges for operators using acoustic device

measurements for blowdown valve leakage.

Response: The EPA has retained the acoustic device measurement method in the final rule. See 

Section II.B.11 of the preamble to the final rule for additional discussion responding to this 

comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 71

Comment: EPA is eliminating the use of acoustic device measurement for blowdown valve 

leakage for reciprocating compressors in operating mode or standby pressurized mode. API 

objects to this revision as there may be situations where it is unsafe or infeasible to otherwise 

measure these emissions. EPA had added this provision to remedy issues raised in June 2010 

comments on the re-proposed Subpart W rule. Removing this option is further complicated by 

EPA’s proposal to remove the option to request BAMM, introducing compliance challenges for 

operators using acoustic device measurements for blowdown valve leakage.

Response: The EPA has retained the acoustic device measurement method in the final rule. See 

Section II.B.11 of the preamble to the final rule for additional discussion responding to this 

comment.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 9

Comment: The Proposed Rule eliminates acoustic device measurement for compressor 

blowdown valve leakage, but still requires measuring 100% of vents. Currently, SoCal Gas relies 

on this measurement method to address blowdown vents where vents are not accessible due to 

safety considerations precluding direct measurement. Therefore, use of this device cannot be 

eliminated unless alternative rule requirements are provided such as the infrared camera for 

screening and eliminating the requirement to measure 100% of vents (I.e., inaccessible, unsafe, 

or technically infeasible to measure).

Response: The EPA has retained the acoustic device measurement method in the final rule. See 

Section II.B.11 of the preamble to the final rule for additional discussion responding to this 

comment.

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Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 13

Comment: In 40 CFR 298.233(o)(2)(i) and (p)(2)(i), EPA has eliminated the use of acoustic 

leak detection devices for measuring natural gas leakage through blowdown vent valves when 

the centrifugal or reciprocating compressor is pressurized. Previously, this was allowed.

Williams’ monitoring contractor often uses an acoustic leak detection device across blowdown 

vent valves in cases where other measurement methods are not safe or possible. Elimination of 

this measurement method for blowdown vents would reduce the number of actual vent 

measurements collected and would be detrimental to the GHG inventory program.

The acoustic leak detection device is a safe and simple method for measuring leaking blowdown 

valves. Eliminating this measurement method would create unintended safety hazards. One 

hazard is having to use a manlift in unsafe surroundings (overhead power lines, physical 

obstructions) to measure blowdown valve emissions from elevated blowdown stacks. A second 

hazard is subjecting individuals collecting the measurements to the possibility of collecting the 

measurement when a high-pressure blowdown occurs.

Response: The EPA has retained the acoustic device measurement method in the final rule. See 

Section II.B.11 of the preamble to the final rule for additional discussion responding to this 

comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 39

Comment: Several miscellaneous minor technical corrections and clarifications were 

identified. 

The Proposed Rule has not been scrutinized for minor corrections. The limited time for comment 

preparation, and schedule overlap with reporting obligations due March 31, prevented such 

scrutiny. However, several minor technical corrections and requests for clarification are included 

here. In some cases, comments above could result in revisions that would make these items 

irrelevant (i.e., the item in question would not be in the Final Rule).

• Since timing did not provide the opportunity to "test" the data flow and calculations in the 

compressor sections, INGAA recommends that the compressor sections be carefully 

reviewed to ensure the source(s), and associated compressor(s) operation and measurements 

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for all reported emissions are clear and concise, and are consistent with data collected and 

emissions calculated by the equations in §98.233(o) and (p).

• EPA should clarify the requirements for compressor sources routed to vapor recovery. The 

following recommendations to delete text clarify that no measurement or additional data are 

required if the compressor vent is routed to vapor recovery:

− §98.233(o): "...If emissions from a compressor source are routed to vapor recovery, 

paragraphs (o)(1) through (o)(12) of this section do not apply."

− §98.233(p): "...If emissions from a compressor source are routed to vapor recovery, 

paragraphs (p)(1) through (p)(12) of this section do not apply."

Response: The EPA agrees with the commenter’s suggested corrections and has revised the rule

accordingly.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 69

Comment: Section 98.233(p) states that when emissions from a compressor source are routed to 

vapor recovery, the calculations specified in paragraphs(p)(1) through (p)(12) do not apply. It 

appears that this is intended to eliminate all requirements in paragraphs (p)(1) – (12), but this is 

not clear because "calculations" is referred to in the regulatory text (i.e., it could be interpreted 

that requirements not related to calculations apply). Text should be revised so that it is clear that 

all of the requirements in paragraphs (p)(1) – (12) do not apply. A similar clarification should be 

made for §98.233(o).

"... If emissions from a compressor source are routed to vapor recovery, paragraphs (p)(1) 

through (p)(12) of this section do not apply. ..."

Response: The EPA agrees with the commenter’s suggested corrections and has revised the rule 

accordingly.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 70

Comment: To alleviate possible confusion and facilitate understanding of subsequent 

calculation and reporting requirements, it is recommended that the phrase "compressor mode –

source combination" be introduced in §98.233(p)(1)(i) and that the four specific compressor 

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mode – source combinations be listed. A similar revision should be made for §98.233(o)(1)(i) for 

the three centrifugal compressor mode-source combinations.

Response: The EPA has evaluated the commenter’s concerns and has determined the rule does 

not need to be revised. The requirements at §98.233(o)(1)(i)(A) and (B) and §98.233(p)(1)(i)(A) 

through (C) clearly identify the compressor mode-source combinations that require an emission 

factor. No change has been made to the final rule as a result of this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 61

Comment: Text that follows related to manifolded line measurements is confusing and appears 

to contain a typo. It appears that "two" should be "three". It is unclear whether each measurement 

must be 60 days apart or if there must be 60 days between the first and last (third) measurement.

• §98.233(o)(1)(iii)(C): "The three required leak measurements must be separated by a 

minimum of 60 days. If more than two three leak measurements are performed, the first and 

last measurements in a calendar year must be separated by a minimum of 120 days."

Response: The EPA is not requiring three annual measurements for manifolded vents in this 

final rule. See Section II.B.11 of the preamble to the final rule for additional discussion regarding 

the final requirements for manifolded compressors.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 60

Comment: Clarifying revisions are recommended to correct a grammatical inconsistency when 

referring to standard conditions. The following sections should be revised by replacing the word 

"Measure" with "Determine" for both reciprocating and centrifugal compressor sections. Neither 

should request "measurement" at standard conditions; rather, the measured values should be 

adjusted to standard conditions:

• §98.233(o)(2)(i)(A): "Measure Determine the volumetric flow at standard conditions from 

the blowdown vent using calibrated bagging or high volume sampler according to methods 

set forth in § 98.234(c) and § 98.234(d), respectively."

• §98.233(o)(2)(i) (B): "Measure Determine the volumetric flow at standard conditions from 

the blowdown vent using a temporary meter such as a vane anemometer according to 

methods set forth in § 98.234(b)."

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• §98.233(p)(2)(i)(A): "Measure Determine the volumetric flow at standard conditions from 

the blowdown vent using calibrated bagging or high volume sampler according to methods 

set forth in §98.234(c) and §98.234(d), respectively."

• §98.233(p)(2)(i) (B): "Measure Determine the volumetric flow at standard conditions from 

the blowdown vent using a temporary meter such as a vane anemometer, according to 

methods set forth in §98.234(b)."

Response: The EPA agrees with the commenter’s suggested edits and has subsequently revised 

the rule. In addition, the EPA has made analogous edits to §98.233(p)(2)(ii)(A) and (B) for 

consistency.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 42

Comment: Suggested clarifying text revisions for §98.233(p)(2)(iii)(A):

"You must use the methods described in § 98.234(a) to conduct annual leak detection of 

equipment leaks from the packing case into an open distance piece, or for compressors with a 

closed distance piece, conduct annual detection of gas emissions from the rod packing vent, 

distance piece vent, compressor crank case breather cap or other vent emitting gas from the 

rod packing."

Response: The EPA agrees with the commenter’s suggested edits and has revised the final rule

accordingly.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 72

Comment: §98.236(p)(2)(vii) requires:

"For emission vents associated with individual compressor sources that use an as found leak 

measurement(s), calculate emissions by summing all emissions from all compressor modesource combinations for the emission vent"

It is not clear why this would be required. Reporting the emissions for compressor mode-source 

combinations separately could provide additional insight into the emission source, and the values 

can be summed at any time. In addition, it is not clear if this requirement only applies when the 

emissions are all measured values, or if it applies when one or more of the emission rates are 

calculated from the reporter emission factor using equation W-27.

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Response: The provision noted by the commenter should not have been included in the 

proposed rule. Similar to the requirements in the current rule, the EPA intended to have the 

emissions reported separately for each compressor source at each compressor as specified in the 

proposed rule at §98.236(o)(2) and (p)(2). In the final rule, the reporting requirements for 

compressors have been revised to more clearly indicate that the reporting requirements apply to 

each compressor source leak or vent. We recognize that manifolded compressors and 

compressors with continuous leak measurements may include emissions across different 

compressor sources, but for single compressors using at found measurements, emissions 

reporting will be the same as in previous years (by compressor source for each compressor)

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 25

Comment: Incorrect equation reference: 98.236(o)(3) says "...If the measurement method 

specified in paragraph § 98.233(o)(2) is performed, report the information specified in paragraph 

(o)(3)(ii) of this section." This sentence does not make sense and must be in error. 98.233(o)(2) 

is solely for "as found" measurements from individual compressor sources. However, the 

requirements of 98.236(o)(3)(ii) related to instances where a reporter uses equation W-24, which 

is only used for continuous monitoring and measurements of manifolded groups of compressor 

sources. Although we are unclear what the intended requirement is, a possible suggested 

correction is as follows, but we encourage EPA to discuss this item with GPA.

98.236(o)(3)(ii) For each compressor mode-source combination where a reporter emission 

factor as calculated in equation W–24 W-23 was used to calculate emissions in Equation W–23 

W-22, report the information specified in paragraphs (o)(3)(ii)(A) through (o)(3)(ii)(D) of this 

section. 

(B) The compressor mode-source combination reporter emission factor, in standard cubic feet 

per hour (EFm,s in Equation W–24 W-23). 

(C) The total number of compressors measured in the compressor mode-source combination in 

the current reporting year and the preceding two reporting years (Countm in Equation W–24 W23). 

Response: The EPA agrees with the commenter’s suggested edits and has revised the final rule

accordingly.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 64

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Comment: • Suggested clarifying edits to §98.233(o)(6)(i) and §98.233(p)(6)(i)

"Tm = Total time the compressor is in the operating mode associated with the mode-source 

combination m, for which Es,i,m is being calculated, in the reporting year, in hours."

• Suggested clarifying edits to §98.233(o)(6)(ii) and §98.233(p)(6)(ii)

"Tm = Total time the compressor is in the operating mode associated with the unmeasured 

mode-source combination m, for which Es,i,m is being calculated, in the reporting year, in 

hours."

Response: The EPA disagrees with the commenter’s suggested clarifying edits because the term 

“operating mode” refers to only one of several different compressor modes. The requirements at 

§98.233(o)(6) and §98.233(p)(6) apply to all compressor mode-source combinations. The final 

rule defines “compressor mode” and “compressor source” at §98.238. No change has been made 

to the final rule as a result of this comment.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 22

Comment: Conflicting requirements for reciprocating compressor emission factors: 

98.233(p)(6)(iii)(A) and (B) are contradictory requirements. 98.233(p)(6)(iii)(A) requires that an 

emission factor "must be calculated annually for each compressor mode-source..." (emphasis 

added). However, 98.233(p)(6)(iii)(B) then says, "You must combine emissions for blowdown 

vents, measured in the operating and standby-pressurized modes." We suggest the following 

changes:

98.233(p)(6)(iii) Using Equation W–28 of this section, develop an emission factor for each 

compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), and 

(p)(1)(i)(C) of this section the compressor mode-source combinations specified in paragraphs 

(p)(6)(iii)(A) through (C). These emission factors must be used in Equation W–27 of this section 

to determine volumetric emissions from a reciprocating compressor in the mode-source 

combinations that were not measured in the reporting year. 

98.233(p)(6)(iii)(A) Emission factors must be calculated annually for each compressor modesource combination specified in paragraph ((p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this 

section. 

98.233(p)(6)(iii) (B) You must combine emissions for blowndown vents, measured in the 

operating and standby-pressurized modes. 

98.233(p)(6)(iii)(A) Rod packing in operating-mode. 

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98.233(p)(6)(iii)(B) Blowdown valve leakage in operating-mode and standby-pressurizedmode. You must combine emissions for blowdown vents, measured in the operating and 

standby-pressurized modes. 

98.233(p)(6)(iii)(C) Isolation valve leakage in not-operating-depressurized-mode. 

Response: The EPA has evaluated the commenter’s concerns and agrees that there are 

conflicting provisions in the proposed rule. We have determined that the proposed provision in 

§98.233(p)(6)(iii)(B) is the incorrect provision and should be deleted. In the final rule, we have 

revised §98.233(p)(6)(iii) to state that the emission factors must be calculated annually and we 

have deleted proposed §98.233(p)(6)(iii)(A) and (B).

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 63

Comment: The Proposed Rule revises §98.233(o) and (p), the emissions calculation sections for 

compressors. Compared to the current emission estimation paradigm, these proposed revisions 

improve rule organization and clarity, and correct and improve calculations and ties to the 

reporting sections. INGAA supports these revisions.

However, additional corrections, clarifications, and edits are needed. These include:

• Verification and clarification of the intent and implementation of the text in 

§98.233(p)(6)(iii)(B) (section 98.233(p)(7)(i)(A) in the current rule) is needed:

• "You must combine emissions for blowndown vents, measured in the operating and standbypressurized modes."

This requirement to combine blowdown valve leakage emissions from the two compressor 

modes is not consistent with the rule equations and the current reporting requirements of the eGGRT Excel reporting form. Equation W-28 is used to calculate an emission factor for each 

compressor mode-source combination specified in §§98.233(p)(1)(i)(A)-(C):

• Operating mode-rod packing,

• Operating mode-blowdown valve leakage,

• Standby-pressurized-mode-blowdown valve leakage, and

• Not-operating-depressurized-mode-isolation valve leakage.

Calculation of emission factors for each mode is required by §98.233(p)(1)(iii). In addition, 

separate operating mode-blowdown valve leakage and standby-pressurized-mode-blowdown 

valve leakage emission factors are needed because it is unlikely that annual blowdown valve 

leakage emissions would be measured in both the operating- and standby-pressurized-modes. 

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Separate emission factors are needed to estimate emissions in the unmeasured mode(s). For 

example, if the annual measurements for a compressor were conducted in the operating mode, 

then Equation W-26 would be used to calculate measured emissions for operating modeblowdown valve leakage and Equation W-27 would be used to calculate unmeasured emissions 

for standby-pressurized-mode-blowdown valve leakage. Combining the emissions would 

eliminate the two separate emission factors.

Either the intent and use of this text should be explained and clarified, or this text should be 

deleted.

Response: The EPA has evaluated the commenter’s concerns and agrees that the proposed 

provision in §98.233(p)(6)(iii)(B) is incorrect and should be deleted. In the final rule, we have 

revised §98.233(p)(6)(iii) to state that the emission factors must be calculated annually and we 

have deleted proposed §98.233(p)(6)(iii)(A) and (B).

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 65

Comment: The associated reporting sections for centrifugal and reciprocating compressors, 

§§98.236(o) and (p), report emissions from "emission vents" which trace back to "compressor 

sources," "compressors," and associated operating modes and measurement data. INGAA 

recommends that these sections be reviewed and "beta tested" to ensure the source(s), and 

associated compressor(s) operation and measurements for all reported emissions are clearly 

understood, and are consistent with data collected and emissions calculated by the equations in 

§98.233(o) and (p). With limited time to prepare these comments and schedule overlap with 

2013 GHGRP reporting, time was not available to complete such a detailed review.

Response: The EPA thanks the commenter for their input. We agree with the commenter that 

the reporting requirements should be consistent with the calculation requirements finalized in 

this rule. 

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 63

Comment: API also supports clarification that the count of compressors is the total number of 

centrifugal compressors that have wet seal oil degassing vents, as this removes confusion over 

screw compressors and rotary vane compressors.

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Response: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 21

Comment: Switch the order of 98.233(o)(6)(ii) and 98.233(o)(6)(iii). Switch the numbering of 

Equations W-22 and W-23: One cannot perform the calculation in (ii) without first performing 

the calculation in (iii). W-22 depends on W-23. This illogical reverse order is highly confusing

for reporters who are first reading the rule. This is a relic of the original Subpart W, and EPA 

should take this opportunity of expansive revisions to fix this. These same changes should be 

made for 98.233(p)(o)(6)(ii) and 98.233(p)(o)(6)(iii) and for Equations W-27 and W-28.

Response: The EPA has evaluated the commenter’s concerns and has determined the rule does 

not need to be revised. The order of equations in the final rule is logical from a top down 

perspective. A reporter is first shown the primary equation (i.e., Equation W-22) for calculating 

annual volumetric CH4 or CO2 emissions for unmeasured compressor mode-source 

combinations; and in order to properly use this Equation W-22, the variable “EFs,m” must be 

determined by using Equation W-23. This same top down perspective is used for Equations W27 and W-28. No change has been made to the final rule as a result of this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 62

Comment: The subscript order is inconsistent in Equations W-22, W-23, W-27 and W-28. All 

of the other compressor equation subscripts use the subscript "s" as the lead with exception of the 

terms EFm,s and MTm,p,s in Equations W-22, W-23, W-27 and W-28. These should be revised 

to EFs,m and MTs,m,p for consistency with the other compressor equations.

Response: The EPA agrees with the commenter’s suggested edits and has subsequently revised

the rule.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 23

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Comment: Add a subscript "s" to the term MTg,avg in Equations W-24B and W-29B: All other 

volumetric emission terms at standard conditions lead with an "s" subscript. This term should be 

changed to MTs,g,avg for consistency.

Response: The EPA agrees with the commenter’s suggested edits and has revised the final rule

accordingly.

Commenter Name: Jeff Applekamp

Commenter Affiliation:

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 34

Comment: Inappropriate use of the word "leak" in all centrifugal compressor and reciprocating 

compressor sections: Throughout sections 98.233(o), 98.233(p), 98.236(o) and 98.236(p), EPA 

inappropriately uses the word "leak" to refer to all compressor emission sources. This is 

incorrect, and both sections need to be extensively revised to delete this word or replace it with 

"vent" or "leak or vent". While it is appropriate to characterize emissions associated with 

isolation valves and blowdown vent valves as "leaks", wet seal oil degassing emissions and rod 

packing emissions occur by design and are definitely not leaks. It is appropriate to characterize 

these as emission sources as "vents".

Response: The EPA has evaluated the commenter’s concerns and agrees that the use of the 

word "leak" to refer to all compressor emission sources is inaccurate. The final rule has been 

revised such that the word “leak” is either replaced with the term “leak or vent” or simply 

deleted (as when used in the phrase “leak measurements” because the term “measurements” is 

sufficient and more accurate).

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 10

Comment: 98.236(o)(2) and 98.236(p)(2) language is confused on whether it contains reporting 

requirements for compressor sources or for emission vents. Both sections muddle requirements 

for both. As the requirements are currently structured, it appears one would report all the 

elements of 98.236(o)(2) for each compressor source including all the emission vent information 

in 98.236(o)(2)(iv), 98.236(o)(2)(v), 98.236(o)(2)(vi), 98.236(o)(2)(vii), and 98.236(o)(2)(viii). 

So, for example, if there are five compressor sources manifolded to one emissions vent, the 

information in 98.236(o)(2)(iv), 98.236(o)(2)(v), 98.236(o)(2)(vi), 98.236(o)(2)(vii), and 

98.236(o)(2)(viii) would be reported five times. This is a waste of time and resources. 

98.236(o)(2) should contain compressor source reporting elements only (i.e., 98.236(o)(2)(i) 

through (iii)). Then a new section 98.236(o)(3) should contain emission vent reporting elements 

only (i.e., 98.236(o)(2)(iii) through (viii)). The unique name or ID for the emission vent 

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(98.236(o)(2)(iii)) will tie the information together, just as the compressor name or ID ties the 

information in 98.236(o)(1) and (2) together. This comment and suggested correction also 

applies to the analogous requirements in 98.236(p).

Response: The EPA has evaluated the commenter’s concerns and has revised the final rule such 

that the reporting requirements at §98.236(o)(2) and §98.236(p)(2) more clearly differentiate 

between data elements required for each compressor source at each compressor and data 

elements required for each leak or vent.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 34

Comment: EPA should reconsider new reporting requirements. Numerous data elements have 

been arbitrarily added, are not needed to calculate GHG emissions, and will add unnecessary 

burden for reporters. 

The Proposed Rule significantly increases the number of data elements to report under §98.236. 

Although the preamble includes confidentiality determinations, and a docket memo tabulates the 

changes, EPA has not explained or justified the need for these data elements. As discussed in 

Comment 9, the new reporting requirements increase costs, and EPA should justify its decision 

for each data element added to §98.236.

If INGAA understood EPA’s objective for adding the data elements, it is possible that specific 

feedback on various data elements could be provided. A partial list of data elements added for 

T&S sources that should be reconsidered and justified if included follows:

• Compressor power rating – §98.236(o)(1)(xiii), §98.236(p)(1)(xiii);

• Year compressor was installed – §98.236(o)(1)(xiv), §98.236(p)(1)(xiv);

• Compressor model name and description – §98.236(o)(1)(xv), §98.236(p)(1)(xv);

• Date of last maintenance shutdown that compressor was depressurized – §98.236(o)(2)(viii);

• Date of last maintenance shutdown for rod packing replacement – §98.236(p)(1)(xvi);

• If emission vent is routed to flare, combustion, or vapor recovery, report the percentage of 

time the device was operational – §98.236(o)(2)(viii), §98.236(p)(2)(viii);

• Whether compressor was measured in operating mode or not-operating depressurized mode –

§98.236(o)(1)(iv);

• Whether compressor sources are routed to a flare – §98.236(o)(1)(vii), §98.236(p)(1)(ix);

• Whether compressor sources have vapor recovery – §98.236(o)(1)(viii), §98.236(p)(1)(x);

116
• Whether compressor sources are captured for fuel use or are routed to a thermal oxidizer –

§98.236(o)(1)(ix), §98.236(p)(1)(xi);

• Whether compressor has blind flanges installed – §98.236(o)(1)(x), §98.236(p)(1)(xii);

• Whether compressor is part of a manifolded group of compressor sources –

§98.236(p)(1)(viii);

Several specific examples are discussed further to demonstrate INGAA questions and concerns:

• Compressor power rating (hp);

• Year compressor was installed;

• Compressor model name and description;

• Date of last maintenance shutdown where centrifugal compressor was depressurized.

INGAA questions the utility of these four parameters / data points for purposes of the GHGRP 

inventory. For example, compressor driver horsepower is very likely a poor indicator of potential 

GHG emissions since GHG emissions are largely dependent on compressor run time and other 

factors rather than power rating. Also, regulatory definitions are not consistent and actual 

working horsepower could be significantly less than site rated horsepower or manufacturer 

nameplate horsepower. The need for these data is unclear, and there is no indication that these 

parameters could be used to predict potential GHG emissions based on compressor type or 

horsepower. In addition, the preamble and background documents do not provide justification for 

adding all of these elements, or consider the costs or benefits. If there are certain objectives EPA 

is trying to achieve by increasing reporting burden, the objectives should be explained and 

decisions should be justified. INGAA would welcome the opportunity to discuss the utility of 

various data elements further.

For these examples, while general compressor information (model, installation date, date of last 

maintenance shutdown) could be compiled, this information is superfluous to the GHG 

inventory. In addition, EPA should review its determination of whether these data are CBI (see 

Comment 20).

Response: The EPA has evaluated the commenter’s concerns. The additional reporting 

requirements included in the proposed rule provide production, capacity, and operational 

information that are useful for the verification of existing data. However, we have revised the 

reporting requirements based on our review of the comments received and have removed the 

reporting requirements for the year the compressor was installed and the model name and 

description of the compressor. We also revised the proposed “compressor power rating” element 

to clarify that this reporting element is the “power output of the compressor driver”. We have

also replaced the reporting requirement for the date of the last maintenance shutdown with a 

simple indication of whether the compressor had a scheduled depressurized shutdown during the 

reporting year. See Section II.E.2 of the preamble to the final rule for additional response to this 

comment. 

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Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 8

Comment: b) 98.236(o)(1)(xiv); 98.236(p)(1)(xiv) "Year compressor was installed." It’s 

unclear exactly what information EPA is seeking, but installation year is not a clear or 

necessarily informative piece of information as compressors are routinely moved from one 

facility to another. For example, a compressor that was originally manufactured in 1980 could be 

relocated and installed at a Subpart W reporting facility in 2014. Further, until recently when 

NSPS OOOO was proposed, operators had no need to track year of installation, manufacture, 

reconstruction, etc. of their compressors. Even now, operators only need to determine whether a 

compressor was in-service, in stock, or ordered prior to 8/23/2011, not the specific year of 

installation. Therefore, the "year of installation" data may not be readily available, if it is 

available at all. This data element is not required to calculate greenhouse gas emissions and will 

require time consuming research to provide. This reporting element should be removed.

c) 98.236(o)(1)(xv) and 98.236(p)(1)(xv) "Compressor model name and description." The term 

"description" is too vague. EPA needs to consider how e-GGRT will be programmed and clearly 

specify what information is to be reported for both "model name" and "description". This 

requirement should either be removed or revised to "Compressor manufacturer and model 

identification."

d) "98.236(o)(1)(xvi) Date of last maintenance shutdown that compressor was depressurized." 

This data element and the analogous 98.236(p)(1)(xvi) must be deleted. This is completely 

unrelated to greenhouse gas emissions. If EPA seeks information on compressor maintenance 

activities, it should do so under another means. Also, this question is vague. If a compressor 

automatically shuts down on an unscheduled basis due to a mechanical issue, and maintenance is 

performed on the compressor, would this be considered a "maintenance shutdown"? Some 

reporters will interpret that it is a "maintenance shutdown", while others will not, and thus the 

information generated here will be misleading at best.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 13

Comment: With respect to the Agency’s proposed reporting requirements, Kinder Morgan 

specifically supports the comments of API and INGAA. As API notes, many of the data 

elements that EPA requests in the Proposed Rule under § 98.236 are not required for calculation 

of GHG emissions (e.g., compressor power rating, year compressor was installed, and dates of 

last maintenance shutdown that compressor was depressurized21).

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Footnotes:

21 See proposed § 98.236(p)(xiii), (xiv) and (xvi).

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

Commenter Name: Carrie B. Crumpton

Commenter Affiliation: CONSOL Energy, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0080-A1

Comment Excerpt Number: 4

Comment: The rule itself incorporates data collection and reporting requirements that go 

beyond the requirements of a reporting program. This includes:

• Various compressor specifications not currently required for reporting which includes power 

ratings, model details, year of installation, model name and description, and date of last 

maintenance shutdown for centrifugal and reciprocating compressors.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 122

Comment: Proposed Citation Reference for Centrifugal Compressors: §98.236(o)(1)(xiii), 

Proposed Rule Text: Compressor power rating (hp).

API objects to reporting this information as it is does not reflect the emission efficiency or 

performance for well-maintained equipment. In addition, the terminology is not correct. 

Compressors do not have hp ratings, engines do. Compressors can be powered by electric 

motors, which also would not have a hp rating.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 127

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Comment: Proposed Citation Reference for Reciprocating Compressors: §98.236(p)(1)(xiii), 

Proposed Rule Text: Compressor power rating (hp).

API objects to reporting this information as it is does not reflect the emission efficiency or 

performance for well-maintained equipment. In addition, the terminology is not correct. 

Compressors do not have hp ratings, engines do. Compressors can be powered by electric 

motors, which also would not have a hp rating.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 123

Comment: Proposed Citation Reference for Centrifugal Compressors: §98.236(o)(1)(xiv), 

Proposed Rule Text: Year compressor was installed.

API objects to reporting this information as it is does not reflect the emission efficiency or 

performance for well-maintained equipment. In addition, the install year may not be available for 

every compressor. If EPA insists on requiring this information, companies will need to be able to 

use an estimate or best available information.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 128

Comment: Proposed Citation Reference for Reciprocating Compressors: §98.236(p)(1)(xiv), 

Proposed Rule Text: §98.236(p)(1)(xiv) Year compressor was installed.

API objects to reporting this information as it is does not reflect the emission efficiency or 

performance for well-maintained equipment. In addition, the install year may not be available for 

every compressor. If EPA insists on requiring this information, companies will need to be able to 

use an estimate or best available information.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

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Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 124

Comment: Proposed Citation Reference for Centrifugal Compressors:§98.236(o)(1)(xv), 

Proposed Rule Text: Compressor model name and description.

API objects to reporting this information as it is does not reflect the emission efficiency or 

performance for well-maintained equipment. It is also unclear what information would be 

reported for “description”.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 129

Comment: Proposed Citation Reference for Reciprocating Compressors: §98.236(p)(1)(xv), 

Proposed Rule Text: Compressor model name and description

API objects to reporting this information as it is does not reflect the emission efficiency or 

performance for well-maintained equipment. It is also unclear what information would be 

reported for “description”.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 125

Comment: Proposed Citation Reference for Centrifugal Compressors:§98.236(o)(1)(xvi), 

Proposed Rule Text: Date of last maintenance shutdown that compressor was depressurized.

API objects to reporting this information as it is does not reflect the emission efficiency or 

performance for well-maintained equipment. If EPA insists on requiring this information, 

companies will need to be able to use an estimate or best available information. 

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

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Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 130

Comment: Proposed Citation Reference for Reciprocating Compressors: §98.236(p)(1)(xvi), 

Proposed Rule Text: Date of last maintenance shutdown for rod packing replacement

API objects to reporting this information as it is does not reflect the emission efficiency or 

performance for well-maintained equipment. If EPA insists on requiring this information, 

companies will need to be able to use an estimate or best available information.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 131

Comment: Proposed Citation Reference for Reciprocating Compressors:§98.236(p)(2)(viii), 

Proposed Rule Text: If the emission vent is routed to flare, combustion, or vapor recovery, 

report the percentage of time that the respective device was operational.

This information is extremely difficult to collect for every compressor. Reporters will need to 

have the option to use engineering estimates based on available information.

Response: This reporting element is being retained in the final rule. The EPA clarifies in this 

response that this reporting requirement is not intended to add additional monitoring or 

measurement requirements. The percentage of time the device was operational may be 

determined using engineering estimates based on best available information.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 12

Comment: h) 98.236(o)(2)(viii) and 98.236(p)(2)(viii) "If the emission vent is routed to flare, 

combustion, or vapor recovery, report the percentage of time that the respective device was 

operational." Depending on the vapor recovery configuration, defining operational time is 

challenging. For example, if the compressor is only operating 50% of the year and the vapor 

recovery is therefore also only operating 50% of the year, what would be reported here? If 50% 

is reported, EPA may incorrectly assume that half of the vapors are not being captured. Also, the 

percent of time that "fuel gas" is "operational" doesn’t necessarily make sense. EPA should 

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consult with technical experts to reword this requirement appropriately, or simply eliminate the 

requirement, as it appears to have no relevance to GHG emission reporting. If EPA wants to 

assess emissions not captured, then they should require this to be reported directly using 

engineering judgment; a "percentage of time" requirement does not provide any useful emission 

data for EPA.

Response: We have clarified this requirement to be “If the leak or vent is routed to flare, 

combustion, or vapor recovery, report the percentage of time that the respective device was 

operational when the compressor source emissions were routed to the device.” The EPA clarifies 

in this response that this reporting requirement is not intended to add additional monitoring or 

measurement requirements. The percentage of time the device was operational may be 

determined using engineering estimates based on best available information.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 15

Comment: Proposed EPA Amendment: Among other additional data elements being requested 

for centrifugal and reciprocating compressors in 40 CFR 98.236 (o) and (p), EPA is seeking the 

following information:

• Compressor power rating (hp);

• Year compressor was installed;

• Compressor model name and description;

• Date of last maintenance shutdown that compressor was depressurized.

Williams questions the utility of the requested data for purposes of the GHG inventory. 

Compressor engine or motor horsepower is a poor indicator of potential GHG emissions since 

such emissions are largely dependent on compressor run time, not power rating. Also, actual 

working horsepower could be significantly less than rated horsepower. Thus, the likelihood of 

accurately predicting potential GHG emissions for a compressor based on compressor type and 

horsepower would be low. While general compressor information (model, installation date, date 

of last maintenance shutdown) is available, we view this information as unnecessary to the GHG 

inventory program. In addition, we view this data to be confidential business information (CBI).

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 34.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

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Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 36

Comment: Suggested edits to §98.236(p)(1):

(viii) Indicate whether which, if any, compressor sources are part of a manifolded group of 

compressor sources.

(ix) Indicate whether which, if any, compressor sources are routed to a flare.

(x) Indicate whether which, if any, compressor sources have vapor recovery.

(xi) Indicate whether which, if any, emissions from any compressor sources emissions are 

captured for fuel use or are routed to a thermal oxidizer.

(xii) Indicate whether the compressor has blind flanges installed. and associated dates. 

• §98.236(p) states that the information in §98.236(p)(2) applies to all reciprocating 

compressors at a facility. However, §98.236(p)(2)(vii) is for reporting methane and CO2 

emissions, and these requirements would not apply for compressors that vent all gas to a 

flare, VRU or combustion unit.

• Suggested edits to §98.236(p)(2):

(iii) Unique name or ID for the emission vent. If the emission vent is connected to a manifolded 

group of compressor sources, use the same emission vent ID for each compressor source in the 

manifold group.

• Suggested edits to §98.236(p)(3)(i):

(B) Sample Measurement date.

(E) For each compressor attached to the emission vent, report the compressor operating mode 

during the measurement of operation the compressor was in when the sample was taken.

Response: Except as discussed further in this paragraph, the EPA agrees with the commenter’s 

suggested edits and has subsequently revised the rule accordingly. EPA has also made analogous 

revisions to §98.236(o). The commenter suggests using the phrase “compressor operating mode” 

in §98.236(p)(3)(i)(e); however, the EPA disagrees with the use of the word “operating” in this 

phrase and has instead revised the phrasing to “compressor mode” because this term is defined in 

the final rule.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 10

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Comment: §98.236(p)(1)(iii) of the Proposed Rule incorrectly asks for reciprocating hours in 

the "standby-depressurized" mode. The three modes of operation are operating, standby 

pressurized and not-operating-depressurized. Therefore, §98.236(p)(1)(iii) should say:

• (iii) Hours in standby-depressurized-mode.

Similarly, §98.236(p) (l)(vi) should say:

• (vi) Indicate whether the compressor was measured in standby-depressurized-mode

Response: The EPA agrees with the commenter’s suggested edits and has subsequently revised 

the rule.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 7

Comment: 98.236(o)(1)(xiii) and 98.236(p)(1)(xiii) "Compressor power rating (hp)." It is 

unclear if EPA is truly requesting the power rating of the compressor or the power rating of the 

driver (e.g., engine, turbine, electric motor). The compressor power is limited by the driver 

power. For the driver, "power rating" is a historically complex term, as "rating" can be 

interpreted a number of different ways. For example, does this account for site conditions such as 

altitude? EPA should consult with technical experts to clearly and specifically distinguish what 

data is being requested and why it is being requested. GPA is not aware of evidence to suggest 

that the horsepower rating of compressor driver is an indicator of emissions from that 

compressor.

Response: In an effort to minimize interpretation, the EPA has revised the requirements in

§98.236(o)(1)(xiii) and §98.236(p)(1)(xiii) in the final rule to specify the “power output of the 

compressor driver (hp)”.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 8

Comment: It is assumed that the new activity data to be reported (i.e. dates of last maintenance 

shutdown) is associated with the new language for Mode 3 testing. The rule language will 

require new tracking systems to be implemented to be able to report accurately regardless of 

whether a mode 3 measurement has been taken or is needed to be taken to meet the 3 year 

criteria. This places another burden on the operator without any impact toward the reporting of 

actual or estimated emissions. Perhaps the intent of the data acquisition could be met by 

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modifying the wording to "Date of last Mode 3 Measurement" or only submitting the dates if 

deferred measurements are made:

98.236(o)(1)(xvi) Date of last maintenance shutdown that compressor was depressurized if a 

shutdown depressurized mode measurement was not taken at least once in any 3 

consecutive years.

98.236{p)(l)(xvi) Date of last maintenance shutdown for rod packing replacement if a shutdown 

depressurized mode measurement was not taken at least once in any 3 consecutive years.

Response: The EPA has replaced the reporting requirement for the date of the last maintenance 

shutdown with a simple indication of whether the compressor had a scheduled depressurized 

shutdown during the reporting year. This indication, reported each year, will provide the data 

needed by the EPA while minimizing the burden to the reporter.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 126

Comment: Proposed Citation Reference for Centrifugal Compressors: §98.236(o)(2)(viii), 

Proposed Rule Text: If the emission vent is routed to flare, combustion, or vapor recovery, report 

the percentage of time that the respective device was operational.

This information is extremely difficult to collect for every compressor. Reporters will need to 

have the option to use engineering estimates based on available information.

Response: We have clarified this requirement to be “If the leak or vent is routed to flare, 

combustion, or vapor recovery, report the percentage of time that the respective device was 

operational when the compressor source emissions were routed to the device. The EPA clarifies 

in this response that this reporting requirement is not intended to add additional monitoring or 

measurement requirements. The percentage of time the device was operational may be 

determined using engineering estimates based on best available information.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 9

Comment: e) 98.236(o)(2) and 98.236(p)(2) apply to all compressors, including compressors 

that have compressor sources routed to fuel, thermal oxidation, or vapor recovery. These types of 

compressor sources do not have to report emissions. However, 98.236(o)(2)(vii) and 

98.236(p)(2)(vii) require emissions to be reported; these requirements should be moved to 

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another section, or be made not-applicable for compressor sources routed to fuel, thermal 

oxidation, or vapor recovery.

Response: The EPA has evaluated the commenter’s concerns and has revised the final rule such 

that the requirements proposed at §98.236(o)(2)(vii) and (p)(2)(vii) do not apply to compressor 

sources routed to flare, combustion, or vapor recovery. The EPA notes that these requirements

are now in §98.236(o)(2)(ii)(D) and (p)(2)(ii)(D).

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 13

Comment: i) 98.236 (o)(3)(ii)(D) and 98.236(p)(3)(ii)(D) should be revised to eliminate the 

term "corporate" which is not defined in Subpart A or Subpart W and is not generally used in the 

reporting rule.

(D) Indicate whether the compressor mode-source combination reporter emission factor is 

facility-specific or corporate based on all of the reporter’s applicable facilities. 

Response: The EPA agrees with the commenter’s suggested edits and has subsequently revised 

the rule.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 6

Comment: Blowdown volumes could skew continuous measurement results: 98.233(o)(3)(ii), 

98.233(o)(5)(iii), 98.233(p)(3)(ii) and 98.233(p)(5)(iii) state, "If compressor blowdown 

emissions are included in the metered emissions... the compressor blowdown emissions may be 

included with the reported emissions for the... compressor source(s)." This reduces burden on 

reporters, but EPA needs to include a new reporting element to indicate whether such 

measurements include blowdown volumes. These blowdown volumes could have the potential to 

substantially skew compressor vent emission data which could lead to uninformed data 

interpretation and/or emission factors.

98.236(o)(4)(iii) Indicate whether the measured volume included blowdown emissions. 

98.236(p)(4)(iii) Indicate whether the measured volume included blowdown emissions. 

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Response: The EPA agrees with the commenter that a reporting element is needed to indicate 

whether continuous measurements include blowdown volumes. The final rule is revised to 

include this data element at §98.236(o)(4)(iii) and (p)(4)(iii).

15.7 Comments on emission factor approach for compressors

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 6

Comment: Alternative approaches that build on INGAA members commitment to 

measurement: Based on our experience and technical expertise gained from implementing 

ongoing GHG programs, previous INGAA comments recommended a programmatic approach 

for reporting and T&S inventory improvement where focused data collection and measurement 

would address primary data gaps. For example, INGAA recommended conducting high quality 

measurement over the initial years of the program to fill data gaps. Analysis of that data could 

provide a path to improved alternative methods for ongoing emission estimates.

In addition, INGAA has consistently requested equitable requirements for data collection and 

reporting for the natural gas industry, including T&S sources. Other industrial sectors subject to 

the GHGRP are generally allowed to estimate emissions rather than being required to conduct 

physical measurements. Other industries are allowed to use emission factors, engineering 

estimates, measurements already conducted for other purposes or generally available (e.g., fuel 

measurement), or minimal or simplistic additional measurements. In contrast, T&S and other 

natural gas segments are required to complete annual measurements and surveys of numerous 

process vents whose primary purpose is to safely vent gas away from personnel and equipment. 

Measurement or monitoring of vented emissions from these numerous vent lines has not 

previously been required for other EPA regulatory or emission inventory purposes. 

Consequently, Subpart W has required implementation of equipment modifications and the 

development of new practices and systems for these operations – e.g., for T&S, this includes 

installation of measurement ports and development of procedures to sample compressor valve 

and rod packing leakage, and implement facility-wide leak surveys that require screening of 

inaccessible components.

While its members abided by EPA’s requirement to complete measurements for Subpart W, 

INGAA has consistently recommended a process to collect quality data, and use that data to 

develop emission factors or other streamlined estimation methods for emissions from compressor 

vents and equipment leaks. INGAA recommendations are based on the fundamental premise that 

emission factors, engineering estimates, and related estimation methods are the longstanding 

technical approach to emission inventory development and are consistent with the requirements 

for other industries subject to the GHGRP. Subpart W measurements completed to date provide a 

voluminous data set in comparison to the amount of data typically available for developing 

emission factors that are used for inventory development – including emission factors used for 

other GHGRP industrial sectors.

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INGAA strongly believes that future Subpart W inventories for the T&S segments should be 

developed by leveraging the numerous data already collected, identifying and filling data gaps, 

and developing a reasonable engineering estimate approach based on these data (e.g., emission 

factors), and retiring the annual measurement requirement after a reasonable timeframe. INGAA 

members have consistently indicated and exhibited a willingness to complete measurements and 

to assist in development of new emission factors for the T&S sector. Since 2009, Subpart W 

measurements from the T&S sector have produced an extensive data set of methane emissions 

from compressors, process vents, and other sources in multiple operating modes. Data from 2011 

and 2012 reporting are publicly available, and significant additional measurement data will be 

available from 2013 and 2014 reporting.

INGAA members have completed thousands of measurements in 2011 to 2013 and reported 

associated emissions to fulfill Subpart W requirements. For the 2011 and 2012 reports currently 

available (2013 reporting was completed by March 31, 2014), INGAA member companies 

reported:

• For T&S reciprocating compressors, more than 5,000 measurements of compressor valve and 

rod packing leakage from over 1,400 affected compressors across the three compressor 

modes in Subpart W (i.e., operating, standby pressurized, and not operating, depressurized). 

Similar numbers of measurements were completed in each mode.

• For T&S centrifugal compressors, nearly 1,000 measurements from more than 475 

compressors across the two modes in Subpart W (i.e., operating and not operating, 

depressurized).

• For 2011 and 2012, INGAA member companies have collectively conducted over 600 

facility leak surveys, with a resulting conservative estimate of over a million components 

screened for leaks.

With 2013 activities recently reported and 2014 testing underway, data from these two years will 

approximately double the available reported data. Thus, a considerable and substantial data set is 

available for review and analysis. The Proposed Rule essentially continues with the status quo 

rather than assessing the significant resource available from these thousands of measurements, 

making correction where warranted, and devising a plan to utilize the measured data to develop 

alternatives to ongoing annual measurement.

Response: See Section II.B.11 of the preamble to the final rule for the EPA’s response to this 

comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 8

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Comment: EPA arbitrarily requires more rigorous and higher cost approaches for the natural

gas industry, including transmission and storage sources, than for other industries subject to the 

GHGRP. 

INGAA has consistently questioned EPA’s decision to require ongoing annual measurement for 

the natural gas industry, including T&S sources, while other industries and sources are allowed 

to use standard inventory approaches such as emission factors and engineering estimates, or 

straightforward measurements that are generally already conducted for other purposes. GHGRP 

requirements and the associated burdens for natural gas T&S facilities subject to Subpart W are 

disproportional to those of other covered industries with a similar magnitude of GHG/methane 

emissions. By requiring T&S direct measurements, the Proposed Rule treats similarly-situated 

entities differently without a reasoned explanation and substantial evidence in the record.

Natural gas T&S facilities have a multitude of new and complex data collection and reporting 

requirements for the GHGRP that include significant new measurement requirements for vent 

lines that have historically not been measured for any purpose and were not designed or 

constructed with measurement access considered. Requirements include:

• Annual (or more frequent) facility-wide equipment leak surveys;

• Annual (or more frequent) transmission storage tank surveys and measurements;

• Tracking and recording of compressor mode and annual leakage / vent measurements for 

reciprocating and centrifugal compressors at affected T&S facilities. In many cases, these 

new measurement requirements have required installation of sample ports, and vent line 

modifications or man-lift rental for safe access;

• On-going blowdown event tracking (type, location, frequency, volume, temperature, and 

pressure) following procedures that may differ from existing practices;

• Collection of combustion equipment emissions data for Subpart C;

• Emission calculations and reporting for the multiple emission sources;

• Annual population counts of gas driven pneumatic devices and storage wellhead 

components; and

• Setup, ongoing maintenance, and populating the recordkeeping systems used to compile and 

retain the thousands of data elements and measurements.

INGAA reviewed requirements for other industries, and Landfills and Underground Coal Mining 

(two of the industries addressed by the White House "Climate Action Plan") have similar 

magnitudes of methane emissions as natural gas systems, and sources within these industries 

have annual methane emissions similar in magnitude to compressors from T&S and gas 

processing. However, while gas processing and T&S require annual compressor measurement, 

the other industries have much simpler and less burdensome GHGRP requirements. Table 1 

compares methane emissions based on EPA’s 2012 draft U.S. GHG Inventory6, i.e., estimates 

are based on the EPA U.S. GHG Inventory report; Subpart W estimates are considerably lower 

for compressor related emissions.

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Table 1. U.S. GHG Inventory Methane Emission Estimates for Natural Gas Systems, 

Landfills, and Coal Mining. 

GHG emissions for Landfills are covered by Subpart HH (MSW Landfills) and Subpart TT 

(Industrial Landfills). Emissions are predominately from MSW landfills (i.e., about 95%), and 

the methane emission estimation methods are similar for both subparts. The mass of waste 

deposited in the landfill each year is determined and the volume of methane generated is 

estimated using a carbonaceous waste decay model. The volume of methane emitted to the 

atmosphere is calculated by adjusting the modeled emissions for methane oxidation by soil using 

a factor and the volume of methane destroyed by gas collection and combustion systems. Data 

collection requirements include:

• Mass of waste loads deposited in the landfill by mass scales or counts of vehicles and 

containers and capacity estimates. It is expected this is an ongoing activity (i.e., pre-dates the 

GHGRP) for billing and / or other purposes; and

• Volume of methane destroyed by gas collection and combustion systems by monitoring 

collected landfill gas flowrate and collecting samples to determine landfill gas methane 

concentration. This could be a new requirement for the GHGRP or could be an ongoing 

activity for operations, regulatory, or other purposes.

Summary data collected by the GHGRP for 20127 indicate that over 50% of the MSW landfills 

do not report combustion emissions under Subpart C and it is assumed these landfills do not have 

gas collection and combustion systems. Thus, it appears that over 50% of the MSW landfill 

facilities were not required to collect additional (i.e., new) data for the GHGRP, and the 

remaining facilities only have a single new data collection requirement.

GHG emissions for Underground Coal Mines are covered by Subpart FF and two emission 

sources are covered: ventilation systems which include ventilation shafts or vent holes where 

mine ventilation air is emitted; and, degasification systems which include degasification wells 

and gob gas vent holes deployed before, during, or after mining operations are conducted.

• Data collection requirements for ventilation systems include quarterly measurements of CH4

emissions. Results of the quarterly (or more frequent) testing performed by the Mine Safety 

and Health Administration (MSHA) for methane flowrate may be used for the GHGRP. This 

is an ongoing activity (i.e., pre-dates the GHGRP) and appears to add minimal burden to the 

facilities.

• Data collection requirements for degasification systems include weekly measurements of 

CH4 emissions. This could be a new requirement for the GHGRP or could be an ongoing 

activity for operations, regulatory, or other purposes.

Thus, it appears that additional data collection requirements for the GHGRP for underground 

coal mine facilities is limited to a single new emission source.

Contrasting these limited new GHGRP data collection requirements for landfills and 

underground coal mines (i.e., single new emission source or sink for each industry) with the 

multitude of new and complex GHGRP measurements and data collection requirements for the 

many emission sources at T&S facilities, it is apparent that the burden for T&S facilities is much 

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greater and disproportionate to the magnitude of GHG emissions. INGAA members have 

collected thousands of data points to date for the first three years of reporting, and it is 

reasonable to expect that data gaps associated with inventory development should be addressed 

and measurement burden should decrease over time.

Footnotes:

7 http://www.epa.gov/climate/ghgreporting/ghgdata/2012data.html

Response: See Section II.B.11 of the preamble to the final rule for the EPA’s response to this 

comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 15

Comment: EPA should review the existing Subpart W measurement data available for 

reciprocating and centrifugal compressors for T&S sources in 2011 and 2012. For reciprocating 

compressors, the reported compressor-mode data indicates that similar counts of measured data 

are being acquired in each of the three modes (i.e., operating; standby pressurized; not operating, 

depressurized or shutdown). Data from the first two years indicates an adequate number of 

measurements are being completed in each mode. This includes over a thousand reciprocating 

compressor measurements for each mode-source combination; hundreds of centrifugal 

compressor measurements for both isolation valve (shutdown mode) and blowdown valve 

(operating mode) leakage; and, nearly two hundred measurements of wet seal oil degassing 

vents. This data also indicates that there are far fewer centrifugal compressors with wet seals 

than previously estimated by EPA; thus estimated emissions from centrifugal compressors wet 

seal degassing are likely much lower than current estimates in EPA’s U.S. GHG Inventory.

As noted above, INGAA members have completed thousands of measurements in 2011 to 2013 

and reported associated emissions in response to Subpart W requirements. Additional detail is 

provided for 2011 and 2012 measurements. INGAA member companies reported more than 

5,000 measurements from over 1,400 affected reciprocating compressors in the T&S sector 

across the three modes with a similar number of measurements in each of the three modes. 

During the same period, member companies reported nearly 1,000 measurements from more than 

475 centrifugal compressors across two modes (i.e., operating and shutdown). GHGRP 2013 

reporting was completed by March 31, 2014, and is expected to increase the number of 

measurements by about 50% . Coupled with 2014 measurements currently underway, the number 

of reported measurements publicly available will approximately double. An initial review of 

these data records indicates modal tests provide operators the ability to calculate reporter specific 

emission factors.

Thus, a substantial data set is currently, and will remain, available for analysis. These GHGRP 

Subpart W measurements could be significantly augmented with a myriad of additional existing 

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data from a variety of sources. These sources include: earlier GRI EPA sponsored studies; GRI 

Canada, Canadian Association of Petroleum Producers (CAPP) and Petroleum Technology 

Alliance Canada (PTAC) sponsored studies; 2011 University of Texas Natural Gas Industry 

Methane Emission Factor Improvement Study; and T&S data that will become available from a 

current industry – EDF project being conducted by Colorado State University. Other than a 

desire to continue with the status quo, the need for mandating mode-specific tests has not been 

explained or justified. The provisions requiring shutdown mode measurements on a defined 

frequency should be eliminated.

Response: See Section II.B.11 of the preamble to the final rule for the EPA’s response to this 

comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 5

Comment: The Proposed Rule essentially continues the current measurement program while 

adding additional restrictions. INGAA understood EPA’s desire in the original 2010 final rule to 

gather additional measured data to address data gaps for key sources. With thousands of 

measurements already completed, it is unclear how or if EPA has used that data in developing 

the Proposed Rule. A path should be defined for data analysis, development of alternative 

emission estimation methods, and elimination or substantial reduction of the burden of ongoing 

annual measurements.

Response: See Section II.B.11 of the preamble to the final rule for the EPA’s response to this 

comment. 

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 14

Comment: As INGAA is requesting, Kinder Morgan notes that it would be interested in having 

further discussions with EPA about the development of accurate emission factors to replace the 

multitude of physical measurements currently required by Subpart W. Reporting entities under 

all other Subparts of Part 98 may use emission factors in lieu of costly and burdensome physical 

measurements and Kinder Morgan believes that there has been enough data gathered under 

Subpart W for accurate emission factors to be similarly incorporated into Subpart W.

Response: See Section II.B.11 of the preamble to the final rule for the EPA’s response to this 

comment.

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Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 13

Comment: The Future Use of Emission Factors. The proposal does not consider alternatives to 

annual measurement, such as the use of emission factors for compressor vents, which EPA has 

discussed with industry trade associations. During these discussions, EPA indicated a willingness 

to develop emission factors for compressor vents and other sources in lieu of direct 

measurement, however, the proposal is silent on this important point. This is most critical for 

compressor vents. Compressor vents are the most problematic sources to measure for the reasons 

discussed above, namely that they are required to be measured in one of three operating modes 

over a three year period and vents are sometimes manifolded so that measurements of individual 

compressors is not possible. EPA's proposals to alleviate these issues provide only a partial 

remedy. The use of good, accurate emission factors would more accurately reflect emissions 

over the year, rather than annualizing a snapshot measurement that may be flawed. We 

encourage EPA to continue discussions with the trade groups on this important issue with a 

specific goal of revision to the rule to reflect those discussions by the end of 2015.

Response: See Section II.B.11 of the preamble to the final rule for the EPA’s response to this 

comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 67

Comment: Fugitive emission measurements for compressors are expensive and EPA is 

collecting significant measurement data through Subpart W. API strongly encourages EPA to 

move from annual measurement of compressor emissions toward an emission factor approach 

using the measurement data they have received.

Response: See Section II.B.11 of the preamble to the final rule for the EPA’s response to this 

comment.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 8

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Comment: Williams also suggests that EPA consider the use of company-wide emission factors 

for compressor vents routed to flare, and for compressor vents routed to atmosphere that are 

inaccessible. Williams also requests that EPA consider industry-wide emission factors for 

compressors, in lieu of these measurements.

Response: See Section II.B.11 of the preamble to the final rule for the EPA’s response to this 

comment.

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 14

Comment: We specifically support amendments that will provide for the use of emission 

factors that are well researched and based on current operating standards and reflect the recently 

enacted New Source Performance Standards for the natural gas industry. (40 C.F.R. Part 60 

Subpart 0000). As discussed in the recently issued White House Climate Action Plan: Strategy to 

Reduce Methane Emissions, the need for a sound understanding of methane emissions from the 

natural gas industry is critical to ensuring that the benefits of natural gas are supported by 

transparent, complete, and accurate reporting. We are a partner in the natural gas transmission 

and storage study of the NGO-industry cooperative research initiative sponsored by the 

Environmental Defense Fund and supports this type of initiative to close the gaps in our 

understanding of methane emissions. Future amendments should incorporate new understandings 

of emissions as they evolve.

Response: See Section II.B.11 of the preamble to the final rule for the EPA’s response to this 

comment.

15.8 Other comments on issues not proposed related to centrifugal and 

reciprocating compressors

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 7

Comment: Because it appears EPA has failed to assess and scrutinize data collected to date, 

INGAA is very concerned that the Proposed Rule would retain flawed Subpart W requirements 

and fail to achieve the objective of an improved GHG emission estimate for T&S sources. 

Instead, a likely outcome is additional years of measurement and continued inventory uncertainty 

and questions about data gaps. Thus, the technical and policy objectives of the GHGRP will not 

be achieved. This outcome would also fail to fulfill the following key objectives in the recently 

released White House methane strategy5

: improving methane measurement (e.g., addressing 

areas of significant emissions and higher uncertainty in bottom up inventories, such as 

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compressors); promoting a common understanding of methane emissions from natural gas 

systems and related abatement opportunities; and, identifying downstream emission reduction 

opportunities (e.g., develop strategies for cost-effectively reducing methane emissions from 

natural gas processing, transmission and storage, LNG, and distribution).

Footnotes:

5 "Climate Action Plan – Strategy to Reduce Methane Emissions." White House (March 2014). 

http://www.whitehouse.gov/sites/default/files/strategy_to_reduce_methane_emissions_2014-03-

28_final.pdf

Response: The EPA disagrees with the commenter that the proposed rule fails to achieve the 

policy objectives of the GHGRP. As noted in the preamble to the April 10, 2009 proposed rule 

(74 FR 16448), the goal of the GHGRP is to collect data of sufficient accuracy and quality to 

inform future CAA policy development. Through data collected under this rule, the EPA is able 

to review the relative emissions of specific industry segments and sources, and the distribution of 

emissions from individual facilities within those industries and sources. This facility-specific 

data also improves understanding of the factors that influence GHG emission rates and actions 

that facilities are already taking to reduce emissions. As noted in the preamble to the April 10, 

2009 proposed rule (74 FR 16448), the goal of the GHGRP is to collect data of sufficient 

accuracy and quality to inform future policy development.

For these same reasons, the EPA disagrees with the commenter that the proposed rule would fail 

to achieve the objectives outlined in the White House Climate Action Plan - Strategy to Reduce 

Methane Emissions (hereinafter "the Strategy"). In fact, the strategy specifically mentions the 

proposed revisions to subpart W and notes that they would enhance the clarity and consistency of 

the reported data from petroleum and natural gas systems. The strategy notes the need for the 

EPA to continue to review regulatory requirements to address potential gaps in coverage, 

improve methods, and help ensure high quality data reporting.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 27

Comment: Data quality objectives (DQOs) and inventory uncertainty targets are not defined 

and are needed to rationally guide data collection requirements and develop a reliable inventory. 

Rule design, implementation, and end results (i.e., a reliable inventory consistent with GHGRP 

objectives) would greatly benefit from definition of and consistent adherence to DQOs for 

inventory uncertainty and completeness (e.g., first determine inventory uncertainty and 

completeness objectives and then design data collection to achieve these objectives). For 

compressor valve leakage and vent gas measurements, Subpart W has an apparent completeness 

objective of 100% for both the number of subject compressors tested and measurement of one or 

more vents associated with the "as found" operating mode for each compressor. INGAA 

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comments since 2009 have documented many barriers to this objective (e.g., safe access to vent 

lines, technical feasibility), and alternatives to the "all vents" target (i.e., 100% measured) have 

been offered.

Instead of considering alternatives, in an attempt to achieve "100% completeness," EPA adopted

an indirect method (see Comment 13 on the acoustic method) and still labored with the BAMM 

request and approval process over the first four years of Subpart W reporting. The Proposed Rule 

would eliminate BAMM in 2015 and the measurement program would continue unabated.

A cursory review of 2011 and 2012 data indicates that Subpart W compressor methane emissions 

are substantially lower than the estimate from the annual U.S. GHG Inventory. The relative 

count of facilities (and compressors) that report under Subpart W versus the count in the national 

inventory does not account for all of the difference. Several contributing factors could be 

hypothesized, including whether Subpart W measurements were completed using a direct or 

indirect measurement method. However, the Proposed Rule does not introduce a systematic 

approach to reconcile these differences, other than additional years of data collection (i.e., annual 

measurements) and requiring several additional data elements to be reported. In addition to 

exacerbating the current confusion regarding the "real" methane emissions attributable to T&S 

operations, failure to reconcile these differences in a timely manner does not comport with the 

White House methane strategy. INGAA strongly believes a much more efficient and effective 

approach could be designed and implemented that would provide improved and more complete 

results much quicker and at lower cost.

The inferred DQO of "measuring 100% of compressor vented emissions" is overly burdensome 

and unrealistic. EPA has made other decisions regarding covered compressor operating modesource combinations, sources included, estimation methods prescribed, etc., that do not appear to 

consistently follow defined objectives. Several examples where INGAA has raised questions

about inventory uncertainty due to methods used, compressor modes tested, and emission factor 

flexibility are identified in Comment 14.

Based on background provided in Comment 13, the record indicates that the 100% completeness 

objective for vent measurement is not achievable without some combination of unsafe work 

practices, inordinate costs (e.g., substantial redesign and re-plumbing on inaccessible vent lines, 

exhuming buried valves), and non-standard and indirect measurement methods. A more rational 

approach would be to set a completeness objective for "valid data" that considers the population 

of compressors and compressor vent lines that can be safely and efficiently tested. This 

population can be determined from emissions data, measurement records, BAMM requests for 

2011 – 2013, and additional communications with affected stakeholders. The representativeness 

of this "accessible" population can be considered against the total compressor population. 

Additional actions, such as screening inaccessible vents using an IR camera, can further 

document the status of vents where emission rate cannot be measured. This would allow the 

universal and consistent use of standard direct measurement test methods.

Such an approach could target an inventory uncertainty objective(s) that will result in a better 

understanding of emission sources and a data set suitable for its intended use (e.g., fill data gaps 

to improve GHG estimates and inform future policy). Continuing to burden operators with 

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questionable measurements serves no useful purpose – and alternatives are available. INGAA 

welcomes the opportunity to discuss this topic further.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 7.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 31

Comment: INGAA’s technical recommendations since 2009 provide approaches more likely to 

achieve GHGRP objectives than the Subpart W annual measurement mandate. Review and 

analysis of measurement data collected to date are recommended to assess lessons learned and to 

determine whether there are programmatic corrections that should be considered to improve data 

quality and achieve program goals. 

Entering the fourth year of Subpart W implementation, questions remain about Subpart W 

methane estimates and the associated methane T&S inventory in comparison to historical data 

and other papers and analysis, including the annual EPA U.S. GHG Inventory. There is an 

abundance of recent papers and publications exploring methane estimates from natural gas 

systems – with a common thread of disparate estimates and conclusions regarding methane 

losses from T&S and other segments. With three years of Subpart W measurements complete 

and a fourth underway, INGAA believes that a well-designed program could have filled T&S 

data gaps and resolved uncertainties associated with source-level estimates and a bottom up 

inventory. In that regard, Subpart W has failed to meet GHGRP objectives and EPA has failed to 

meet its obligation to develop a robust program.

If uninformed, one may conclude that the use of alternatives (e.g., prevalence of BAMM) is a 

root cause. However, T&S operators have demonstrated a willingness to complete 

measurements, as evidenced by the thousands of measured data results in 2011 and 2012 reports. 

Additionally, many operators who used BAMM did so as a means to address rule 

inconsistencies, to ensure the ability to comply as EPA continued to revise and amend Subpart 

W, and to address a subset of inaccessible vents. INGAA does not believe that the Proposed Rule 

provides a clear and efficient pathway to resolve the issues encountered to date, and the 

significant resources committed to annual measurements at hundreds of facilities will be for 

naught – or at best will require too many additional years of measurements and too much time to 

understand the Subpart W data implications. As a result, Subpart W will be marginalized – or 

deemed inconsequential or unreliable – by other, more effective measurement programs and/or 

research. This does not have to be the script that is followed.

In its 2009 and 2010 comments, INGAA strongly recommended a programmatic approach to 

address data gaps and improve emission estimation, and INGAA believes that an alternative 

Subpart W program could have (and should have) been designed and implemented. INGAA 

strongly recommends reconsideration of the current path and revisiting the design and intent of 

measurement requirements for T&S sources. Subpart W measurements could fill data gaps, be 

138
used to develop improved emission factors and estimation methods, reduce emission estimate 

uncertainties, and meet EPA regulatory and policy objectives. These objectives are consistent 

with the objectives in the White House methane strategy released in March 2014. As currently 

implemented and as amended in the Proposed Rule, INGAA believes that Subpart W will either 

fail to meet these objectives for T&S sources, or will only arrive at conclusions after many 

additional, unnecessary years of annual measurement.

INGAA is not re-hashing previous recommendations in these comments, but refers EPA to 

previous comments – especially 2009 and 2010 comments, as well as other communications and 

programs that have been discussed in meetings since GHGRP inception. INGAA would 

welcome the opportunity to engage EPA in additional discussions on this topic and 

complementary projects.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 7.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 73

Comment: INGAA and its members remain committed to projects that improve T&S GHG 

emission estimates. INGAA would welcome cooperative efforts with EPA.

Comment 1 reviews a partial list of INGAA and natural gas industry activities over the last two 

decades related to improving the understanding of GHG emissions from our operations, 

including many projects with EPA. These efforts continue, and an ongoing industry project could 

provide an opportunity to leverage Subpart W data and support the development of alternatives 

to current Subpart W requirements.

INGAA and the Pipeline Research Council International (PRCI, a pipeline collaborative research 

group) are collecting supplemental data from their members to provide additional insight into 

2011 and 2012 Subpart W measurements. Analysis is planned that may provide insight into 

measurement method uncertainties. That program also plans to collect 2013 Subpart W data and 

supplemental data from members, and assess whether that data facilitates a better understanding 

of data quality and emissions for key Subpart W sources – especially compressors. The project is 

not prejudging the likelihood of success, and insights from data analysis will define the path 

forward. For example, the project may consider options such as:

• Segments covered will include transmission and storage, but could be expanded to include 

other segments (e.g., gas processing) where Subpart W measurement is required.

• Sources will focus on compressors and each of the compressor mode – emission source 

combinations defined in Subpart W. The project may also assess equipment leak survey 

results (e.g., prevalence of leaks by component type and service) and the frequency and 

volume of transmission condensate tank dump valve leakage.

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• Data analysis will include the data elements submitted for Subpart W via the e-GGRT 

reporting form as well as supplemental data collected on operations, equipment, and 

measurement methods. Data review may indicate the need to revisit the supplemental data 

request and add more data elements – e.g., to address questions regarding test methods used 

and categorize measured data based on the measurement method used.

• Based on information collected to date, it appears that approximately 75% or more of the 

T&S facilities that are required to report per the GHGRP are INGAA and/or PRCI members 

sharing data for this project. At this time, the project does not plan to analyze publicly 

available data from other facilities, but quality control checks will likely be conducted to 

compare reported emissions for facilities within the INGAA/PRCI dataset to other facilities 

that reported. Similarly, data from other segments could be added by collaboration with third 

parties that facilitate access to supplemental data or other measurement reports.

• Following compilation and initial data analysis, the status will be discussed with INGAA and 

PRCI advisors to consider questions such as data representativeness and data quality. As 

appropriate, follow-up steps will be initiated and a determination will be made regarding 

whether: (1) analysis to initiate emission factor development is feasible, and/or (2) additional 

data and information is needed to facilitate emission factor development.

• If emission factor development is pursued, various approaches for segregating the data into 

different subsets will be considered based on equipment or operational characteristics, and 

other factors and alternatives that affect emission factor quality and emission estimation 

uncertainty. This could include consideration of approaches that include periodic tests or 

additional data gathering in an effort to continue to refine estimates or ensure uncertainty 

targets are met and maintained. Potential approaches will be vetted with INGAA/PRCI 

project advisors.

INGAA has offered alternative approaches in previous comments, but these are the first 

comments submitted since the project with PRCI was initiated. INGAA believes it is imperative 

that we learn from the measurements being completed and the INGAA/PRCI project is intended 

to address that objective. At this time, it is unclear what type of analysis EPA has undertaken or 

plans for future efforts. INGAA welcomes the opportunity to discuss this further with EPA, and 

cooperatively define a path to utilize the thousands of measurements completed and continuing 

in 2014, including assessing whether programmatic changes should be considered to ensure data 

quality. INGAA is very concerned that the Proposed Rule appears to continue the annual 

measurement mandate without reviewing measurement data collected to date, assessing lessons 

learned from three years or measurement and reporting, or determining whether there are 

programmatic corrections that should be considered at this time to improve data quality.

Response: The EPA appreciates the commenter's continued commitment to participating in the 

rulemaking process and providing input to help inform and improve the requirements of subpart 

W and the EPA is willing to consider an emission factor approach under Part 98 for compressors. 

The EPA agrees that facilities have collected data under part 98 related to centrifugal and 

reciprocating compressors that can be used to inform an emission factor. However, the data 

which are inputs to emissions equations have not yet been reported to the EPA because they are 

deferred for reporting until 2015. The deferred reporting elements include the reporter-specific 

emission factors that are used to calculate emissions and the total time that a compressor is in a 

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particular mode. The reporter-specific emission factors provide information on how measured 

data is applied to a reporter’s other compressors that were not measured in a particular mode, and 

these factors are applied to all compressors for the total time each compressor is operated in each 

mode. Therefore the deferred data provide important information that could help inform the 

development of emission factors for each mode of operation. The EPA intends to analyze this 

deferred information after it is received in 2015. In addition, the data that will be reported under 

these final rule amendments will provide additional data that can inform the development of 

emission factors, such as information on the power output of the compressor driver. Furthermore, 

the compressor revisions that are being finalized in this rule will improve the quality of the 

reported data and address technical issues received from stakeholders during program 

implementation. 

The EPA is committed to working with stakeholders to review regulatory requirements, methods, 

and the quality of the information reported. The EPA looks forward to reviewing the deferred 

Part 98 data, data that will be reported under these revisions and data from outside studies in 

order to determine if appropriate emission factors can be developed, and, if so, the EPA may 

revise the calculation and reporting requirements for compressors in a future rulemaking. See 

response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 7 and Section II.B.11 of the 

preamble to the final rule for further discussion regarding the final compressor requirements.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 74

Comment: INGAA has repeatedly raised questions on inventory completeness and accuracy 

that have not been specifically answered or were dismissed. In some cases, this may be 

detrimental to achieving GHGRP objectives. For example:

• INGAA raised questions about excluded sources that may be worth considering (e.g., sourcemode related emissions for compressors that are not included);

• INGAA requested an alternative method that would allow operators to use optical imaging to 

qualitatively assess leakage through a vent that cannot be accessed for measurement;

• INGAA asked for the ability to use higher quality data for combustion methane – i.e., more 

accurate exhaust methane emission factors for reciprocating engines estimates under Subpart 

C so that this methane source is more accurately reported.

If a comprehensive programmatic approach is considered for updating Subpart W requirements, 

INGAA would also be interested in additional discussions regarding those previous EPA 

decisions. In summary, INGAA remains committed to improving GHG estimates from T&S 

sources and would welcome a cooperative effort with EPA to address data gaps, improve GHG 

estimates, and address GHGRP objectives.

141
Response: The EPA notes that the issues addressed by the commenter have been responded to 

in previous rulemakings. In this final rule, the EPA has reviewed the optical gas imaging 

methods in §98.234(a) and determined that these methods are appropriate for pre-screening for 

leakage from compressor vents. The final rule allows the use the methods in §98.234(a) for prescreening of emissions from isolation valves, blowdown valves, or rod packing released through 

a vent, provided that sources conduct follow-up measurements if leaks are detected. See Section 

II.B.11 of the preamble to the final rule for additional information.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 28

Comment: Comparable use of the IR camera and acoustic instrument for screening purposes.

When vent measurement is required, Subpart W includes methods for detecting or pre-screening 

for leaks prior to measuring the vented emission rate, such as screening a transmission 

condensate tank dump valve for leakage. §98.234(a)(5) allows the use of an acoustic instrument 

to check for leakage, and vent emission rate measurement is not required if leakage through the 

valve is not detected. Although the rule text is not completely clear, this approach also appears to 

be allowed for leakage from compressor isolation valves in §98.233(o) and (p). Use of acoustic 

instruments for detecting leakage through valves was requested by INGAA and others in June 

2010 comments and added to Subpart W. Similarly, Subpart W allows optical imaging (i.e., "IR 

camera") for leak surveys required in 98.233(q) and for screening transmission condensate tank 

vented emissions from dump valve leakage in §98.233(k). INGAA has recommended that the IR 

camera also be allowed for screening other vents that require measurement. It is not clear why 

EPA selectively applies IR camera or acoustic instrument screening for some applications but 

not others, and this decision has never been explained or justified. INGAA recommends the 

flexibility to allow use of the IR camera for this purpose whenever vent measurement is required.

Similar to using an acoustic instrument to detect leaks across dump valves or isolation valves, or 

using the IR camera to screen for dump valve leakage through tank vents, the IR camera can be 

used to screen for leaks from compressor isolation valves, blowdown valves, or rod packing 

released through a vent and identify whether vent measurement is needed. This is especially 

important for screening vents that are unsafe or impractical to access. INGAA understands that 

several companies have received approval of BAMM requests to use the IR camera to screen 

these compressor sources for emissions. The use of the IR camera should not be unnecessarily 

restricted, and inconsistencies regarding methods (i.e., acoustic instrument or IR camera) and 

applications (e.g., dump valve, isolation valve, blowdown valve) in Subpart W have never been 

explained or justified by EPA. In fact, INGAA expected the Proposed Rule to include revisions 

to §98.233(o) and (p) to allow the use of the IR camera method in §98.234(a)(1) for compressor 

vent screening. INGAA recommends revisions to the Final Rule to address this issue.

Response: The EPA has considered these comments and has included in the final rule 

provisions to allow for the use of optical gas imaging equipment for compressor vent screening. 

142
We are finalizing provisions in §98.233(o)(2)(i)(D) and §98.233(p)(2)(i)(D) to allow the use of 

the methods in §98.234(a) to allow for pre-screening for leaks from compressor isolation valves, 

blowdown valves, or rod packing released through a vent. Reporters may use this method to 

identify whether further vent measurement is needed. If any emissions are detected, then 

reporters are required to use one of the methods currently specified in subpart W (acoustic leak 

detection device, calibrated bagging or high volume sampler, or temporary meter such as a vane 

anemometer) to quantify emissions. If no emissions are detected, the reporter would be allowed 

to use zero as the measured emissions rate and would not be required to follow-up with a 

measurement to further quantify emissions. See Section II.B.11 of the preamble to the final rule 

for additional information responding to this comment.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 9

Comment: EPA Should Clarify that Subpart W Does Not Require a Leakage Measurement 

Where Leak Screening Indicates that No Leakage Is Present.

Where Subpart W calls for the quantification of GHG emission leakage, it is unclear and 

inconsistent about when pre-screening for leaks can be used as a means to determine whether an 

actual leakage measurement is necessary or not.

Section 98.233(k) provides an example that should be replicated throughout Subpart W. Section 

98.233(k) requires that the annual emissions of a storage tank leak be quantified. However, § 

98.233(k)(2) expressly states that such leak must be quantified only if it is first identified through 

one of several leak screening methods. Under § 98.233(k), if leak detection determines that no 

leak is present, then a leak quantification is not required.

However, many other parts of Subpart W are silent about whether leakage measurement is 

required if leak pre-screening indicates that a leak is not present. For instance, § 98.233(o)(1) 

simply requires a reporting entity to "[m]easure emissions from all vents" annually including 

"blowdown valve leakage through the blowdown vent" for centrifugal compressors – without 

stating whether pre-screens indicating that no leakage is present might excuse the requirement 

to carry out the measurement process. Subpart W is similarly silent on whether leak screening 

indicating that no leakage is present can be used to excuse leakage measurement from rod 

packing and blowdown vents of reciprocating compressors under § 98.233(p)(1).

Wherever Subpart W contemplates the measurement or quantification of leakage, Kinder 

Morgan requests that EPA clarify that no further leak measurement or quantification is necessary

if leak screening technology indicates that no leak is present.

Response: In the final rule, we have clarified in §98.233(o)(2)(i)(D) and (p)(2)(i)(D) that if no 

emissions are detected, the reporter would be allowed to use zero as the measured emissions rate 

and would not be required to follow-up with a measurement to further quantify emissions.

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Commenter Name: Kelly Guertin

Commenter Affiliation: DTE Energy

Document Control Number: EPA-HQ-OAR-2011-0512-0076-A1

Comment Excerpt Number: 2

Comment: The Proposed Rule arbitrarily excludes viable measurement methods. DTE 

recommends measurement flexibility. Since the original rule proposal in 2009, DTE in 

association with INGAA has consistently requested measurement method flexibility that allows 

the use of viable technologies and methods for detecting leaks and for vent or leak rate 

measurement. The 2010 Subpart W final rule and subsequent amendments have accommodated 

some of the requests and significantly improved the rule. However, examples remain where EPA 

has excluded viable methods or included unnecessarily prescriptive criteria. DTE recommends 

measurement method flexibility when feasible. DTE wholeheartedly endorses comments 

submitted by INGAA with regards to measurement flexibility ["Comments on the Proposed 

Amendments to Subpart W of the Greenhouse Gas Mandatory Reporting Rule" Submitted by 

Interstate Natural Gas Association of America (INGAA) (April 24, 2014).]

Response: The EPA has corrected the measurement methods in the final rule to allow for the 

use of an acoustic leak detection device; additionally, the EPA is allowing for the use of optical 

gas imaging equipment for pre-screening of emissions from isolation valves, blowdown valves, 

or rod packing released through a vent. These revisions provide measurement flexibility for 

reporters and ensure that reporters are able to complete measurements and comply with subpart 

W requirements. See Section II.B.11 of the preamble to the final rule for additional information

responding to this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 65

Comment: EPA should make provision in §98.233(o) to include seal-oil/gas separation and 

recovery as a vapor recovery unit (VRU) for purposes of measurement of emissions from seal-oil 

degassing systems (vents). These systems are equivalent to the ones reported into EPA’s Natural 

Gas Star program by BP and others. API suggests the following edit to §98.233(o)(1)(i)(A) to

accomplish this goal:

98.233 (o)(1) (i) (A) For a compressor measured in operating-mode, you must measure

volumetric emissions from blowdown valve leakage through the blowdown vent as specified in 

either paragraph (o)(2)(i)(A) or (o)(2)(i)(B) of this section and, if the compressor has wet seal oil 

degassing vents, measure volumetric emissions from wet seal oil degassing vents as specified in 

paragraph (o)(2)(ii) of this section. If a compressor has a continuously operating vapor recovery 

system for the wet seal degassing, then measurement of wet seal degassing is not required.

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98.233 (o)(1)(A)(1) For purposes of this Subpart, a system of seal-oil and gas separation 

with recovery of separated gas is considered to be a vapor recovery system.

Response: The EPA has evaluated the commenter’s concerns and agrees that the seal-oil/gas 

separation and recovery is a vapor recovery. The introductory text in §98.233(o) states that “If 

emissions from a compressor source are routed to vapor recovery, paragraphs (o)(1) through 

(o)(12) of this section do not apply.” Based on this provision, we find that the last sentence 

proposed at §98.233(o)(1)(i)(A) to be redundant. If vapors in the wet seal oil are separated and 

recovered, then the wet seal oil degassing vent compressor source emissions are recovered and 

there are no measurement or calculation requirements for that compressor source. We are 

deleting the last sentence proposed at §98.233(o)(1)(i)(A).

16.0 Leak Detection Equipment and Emissions from Components 

16.1 Revisions to §98.233(q) and (r) and calculation of facility meter/regulator 

run emission factor

Commenter Name: Pamela Lacey

Commenter Affiliation: American Gas Association (AGA)

Document Control Number: EPA-HQ-OAR-2011-0512-0083-A1

Comment Excerpt Number: 1

Comment: One of AGA’s key remaining concerns with the Subpart W rule was the confusion 

generated by the inconsistent use of "meter runs" or individual "components" as the basis for 

developing emission factors for natural gas distribution facilities. Our member natural gas 

distribution companies were unsure about what the rule required. And they were concerned that 

the inconsistent language in the rule might be interpreted to require counting individual 

components, including not only the few found to be leaking but millions of non-leaking 

components, which would have imposed tremendous reporting burdens without any offsetting 

benefit. We are very pleased that this was not EPA’s intent, and that EPA now proposes to make 

that clear by placing the meter/regulator run emission factor calculation to section 98.233(q) 

instead of 98.233(r), and clarifying that the emission factor is calculated separately for CO2 and 

CH4 and is based on a meter-regulator run rather than the individual components within a run.

Response: The EPA thanks the commenter for their support. The revisions clarifying that the 

emission calculations are based on meter/regulator runs are finalized as proposed. 

16.2 Calculation of emissions from above grade transmission-distribution (T-D) 

transfer stations.

Commenter Name: Bert Kalisch

Commenter Affiliation: American Public Gas Association

Document Control Number: EPA-HQ-OAR-2011-0512-0074-A1

Comment Excerpt Number: 3

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Comment: Minimum Reporting Required to Estimate GHG from Above Grade TransmissionDistribution Transfer Stations and Other Above Grade Metering Regulating Stations 

In addition, EPA’s rule requires utilities to conduct leakage surveys at transmission/distribution 

transfer stations ("TD transfer stations") and calculate component-specific emissions estimates 

using Equations W-30, W-31 and W-32B:

EQ W-30:

Es,p,i = EFs,p * GHGi * Sum(Tp,z)

Where:

Es,p,i = Annual total volumetric emissions of GHGi from specific component type "p" in standard 

("s") cubic feet.

xp = Total number of specific component type "p" detected as leaking during annual leak 

surveys.

EFs,p = Leaker emission factor for specific component types listed in Table W–7 of this subpart.

GHGi = For natural gas distribution, GHGi equals 1 for CH4 and 1.1 × 10-2 CO2.

Tp,z = The total time the surveyed component "z", component type "p", was found leaking and 

operational, in hours.

EPA could calculate the annual total volumetric emissions of GHGi from specific component 

type "p" using Equation W-30 if operators submitted the following:

1. Total number of specific component type detected as leaking during annual leak surveys and

2. Total time the surveyed component types were found leaking and operational.

The result of Equation W-30 is used in Equation W-31 to calculate an emission factor for 

meter/regulator runs.

EQ W-31

EFs,MR,i = Double sum(Es,p,i,y) / Double sum(Tw,y)

Where:

EFs,MR,i = Meter/regulator run population emission factor for GHGi based on all surveyed above 

grade transmission distribution transfer stations over "n" years, in standard cubic feet of GHGi 

per operational hour of all meter/regulator runs.

Es,p,i,y = Annual total volumetric emissions at standard conditions of GHGi from component type 

"p" during year "y" in standard ("s") cubic feet, as calculated using Equation W–30.

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p = Seven component types listed in Table W–7 for transmission distribution transfer stations.

Tw,y = The total time the surveyed meter/ regulator run "w" was operational, in hours during 

survey year "y."

CountMR,y = Count of meter/regulator runs surveyed at above grade transmission distribution 

transfer stations in year ‘"y".

y = Year of data included in emission factor "EFs,MR,i."

n = Number of years of data used to calculate emission factor "EFs,MR,i".

EPA could calculate the meter/regulator run population emission factor "EFs,MR,i" for the 

distribution system using Equation W-31 if operators submitted the following:

1. Total time the surveyed meter/ regulator run was operational during survey year,

2. Count of meter/regulator runs surveyed at above grade transmission distribution transfer 

stations in the year of data included in emission and the number of years of data used to calculate 

emission factor "EFs,MR,i".

The result of Equation W-30 is used in Equation W-32B to calculate annual volumetric 

emissions of GHGi.

EQ W-32B

Es,MR,i = CountMR * EFs,MR,i * Tw,avg

Where:

Es,MR,i = Annual volumetric emissions of GHGi from all meter/regulator runs at above grade 

metering regulating stations that are not above grade transmission distribution transfer stations, 

in standard cubic feet.

CountMR = Total number of meter/regulator runs at above grade metering-regulating stations that 

are not above grade transmission-distribution transfer stations.

EFs,MR,i = Meter/regulator run population emission factor for GHGi based on all surveyed above 

grade transmission distribution transfer stations over "n" years, in standard cubic feet of GHGi 

per operational hour of all meter/regulator runs., as determined in Equation W–31.

Tw,avg = Average estimated time that each meter/regulator run was operational in the calendar 

year, in hours per meter/ regulator run.

EPA could calculate the annual volumetric emissions of GHGi from all meter/regulator runs at 

above grade metering regulating stations that are not above grade transmission distribution 

transfer stations using Equation W-32B if operators submitted the following:

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1. Total number of meter/regulator runs at above grade metering-regulating stations that are not 

above grade transmission-distribution transfer stations and

2. Average estimated time that each meter/regulator run was operational in the calendar year.

Everything from this point on relies on equations and fixed factors specified in the rule with no 

further information needed from the responder. EPA could calculate GHG mass emissions in 

metric tons by converting the GHG volumetric emissions estimated using Equations W-32 A & 

B into estimated mass emissions using Equation W–36.

EQ W-36

Massi = Es,i * pi * 10-3

Where:

Massi = GHGi mass emissions in metric tons.

Es,i = GHGi volumetric emissions at standard conditions, in cubic feet, calculated using 

Equations W-32 A&B

pi = Density of GHGi.

EPA should modify its e-GGRT program to collect only the 12 data elements listed above from 

natural gas distribution operators reporting under Subpart W. These data are sufficient to allow 

e-GGRT to calculate volumetric, metric tons and metric ton CO2e without any additional input 

from the responding distribution operator. E-GGRT should alert the reporting entity whether the 

data entered results in estimated emissions at or above the 25,000 metric ton CO2e reporting 

threshold.

Response: The EPA disagrees with the commenter that the above data elements are the only 

data elements that should be collected from natural gas distribution operations. It is our practice 

to allow reporters to override emissions calculated by the e-GGRT system. In order to do that, 

the emissions (or emission factors), must be reporting elements. We have reviewed the required 

reporting elements and have determined that the proposed reporting elements are useful and 

necessary for the purpose of emissions reporting and verification of the reported data. Therefore, 

the EPA is finalizing these reporting requirements as proposed, with minor clarifications.

With respect to the request that the e-GGRT system alert the reporting entity whether the data 

entered results in estimated emissions at or above the 25,000 metric ton CO2e reporting 

threshold, this request is beyond the scope of this rulemaking. However, per the requirements set 

forth in §98.2(i), reporters may need to continue to report for a certain period of time if their 

emissions are less than 25,000 metric tons CO2e and they exceeded the reporting threshold in a 

previous reporting year. Given these requirements, we are concerned that providing a simple 

alert at the 25,000 metric ton CO2e threshold might be misinterpreted to suggest an annual report 

is not required, when in fact the report may still be required to be submitted.

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Commenter Name: Pamela Lacey

Commenter Affiliation: American Gas Association (AGA)

Document Control Number: EPA-HQ-OAR-2011-0512-0083-A1

Comment Excerpt Number: 2

Comment: Clarify Calculation of Emissions Over Multiple Year Cycle: Under the Subpart W 

Proposed Revisions, annual equipment leak surveys would be conducted at above grade 

transmission-distribution (T-D) transfer stations according to §98.233(q). Section 98.233(q)(8)(i) 

allows all distribution facility above-grade T-D transfer stations to be surveyed over multiple 

years up to a five year cycle. It appears that the emission calculation requirements of §98.233(q) 

and the emission reporting requirements of §98.236(q)(2) only apply to equipment leaks at the 

above grade T-D transfer stations surveyed during the reporting year. Emissions for equipment 

leaks at the above grade T-D transfer stations not surveyed during the reporting year are not 

calculated or reported. AGA suggests revising the associated text and equations so that these 

emissions could be calculated using Equation W-32B and the emission factors calculated using 

Equation W-31.

Response: The EPA agrees with the commenter and is revising the final rule to clarify that

emissions from equipment leaks at above grade transmission-distribution stations not surveyed 

during the reporting year are to be calculated using Equation W-32B (which uses the emissions 

factor calculated using Equation W-31), as suggested by the commenter. See Section II.B.11 of 

the preamble to the final rule for additional discussion responding to this comment.

16.3 Calculation of emissions from below grade Emissions from below grade 

metering regulating stations, below grade transmission-distribution

transfer stations, distribution mains, and distribution services.

Commenter Name: Bert Kalisch

Commenter Affiliation: American Public Gas Association

Document Control Number: EPA-HQ-OAR-2011-0512-0074-A1

Comment Excerpt Number: 2

Comment: Minimum Reporting Required to Estimate GHG from Mains, Service Lines and 

Below Grade Metering Regulating & Transmission-Distribution Transfer Stations 

Estimated GHG emissions from below grade metering regulating stations, below grade 

transmission-distribution transfer stations, distribution mains, and distribution services are 

calculated using Equation W–32A of 40 CFR 98.233(r):

EQ W-32A

Es,e,i = Counte * EFs,e * GHGi * Te

Where:

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Es,e,i = Annual volumetric emissions of GHGi from the emission source type in standard cubic 

feet. The emission source type may be a component (e.g. connector, open-ended line, etc.), 

below grade metering-regulating station, below grade transmission-distribution transfer station, 

distribution main, or distribution service.

Counte = Total number of the emission source type at the facility. Natural gas distribution 

facilities must count: (1) The number of distribution services by material type; (2) miles of 

distribution mains by material type; and (3) number of below grade metering-regulating stations, 

by pressure type; as listed in Table W–7.

EFs,e = Population emission factor for the specific emission source type, as listed in Table W–7.

GHGi = 1 for CH4 and 1.1 × 10-2CO2.

Te = Average estimated time that each emission source type associated with the equipment leak 

emission was operational in the calendar year, in hours, using engineering estimate based on best 

available data.

EPA could calculate the metric tons of GHGs using Equation W-32A and other equations in the 

rule if operators submitted the following:

1. Number of distribution services by material type;

2. Miles of distribution mains by material type;

3. Number of below grade metering-regulating stations, by pressure type;

4. The number of below grade transmission-distribution transfer stations and

5. Average estimated time that each emission source type associated with the equipment leak 

emission was operational in the calendar year.

Everything from this point on is calculated using equations and factors mandated by EPA. From 

that data, EPA can calculate estimated emissions from these sources, so requiring the reporting 

operators to perform those calculations is an unnecessary reporting burden increases the 

likelihood of calculation errors that would reduce the value of the resulting data.

Response: See response to comment EPA-HQ-OAR-2011-0512-0074-A1, Excerpt 3 in Section 

16.2 of this document.

16.4 Comments on applicable definitions and other minor revisions and 

restructuring of reporting requirements for leak detection and emissions 

from components.

Commenter Name: Bert Kalisch

Commenter Affiliation: American Public Gas Association

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Document Control Number: EPA-HQ-OAR-2011-0512-0074-A1

Comment Excerpt Number: 1

Comment: APGA commends EPA for proposing to simplify the reporting. APGA encourages 

EPA to even further simplify reporting by natural gas distribution operators by limiting reporting 

to only those data that are necessary for EPA to calculate estimated Greenhouse Gas ("GHG") 

emissions. EPA could and should further reduce the number of calculations reporting distribution 

operators need to perform.

Specifically, EPA should modify the regulation and it’s electronic Greenhouse Gas Reporting 

Tool ("e-GGRT") to require natural gas distribution operators reporting under Subpart W to 

report only the following:

1. The number of distribution services by material type;

2. Miles of distribution mains by material type;

3. The number of below grade metering-regulating stations, by pressure type;

4. The number of below grade transmission-distribution transfer stations;

5. Average estimated time that each emission source type associated with the equipment leak 

emission was operational in the calendar year;

6. The total number of specific component type detected as leaking during annual leak surveys of 

above grade transmission/distribution transfer stations;

7. The total time the surveyed component types, were found leaking and operational;

8. The total time the surveyed meter/ regulator run was operational during survey year;

9. The count of meter/regulator runs surveyed at above grade transmission distribution transfer 

stations;

10. The number of years of data used to calculate emission factor;

11. The total number of meter/regulator runs at above grade metering-regulating stations that are 

not above grade transmission-distribution transfer stations; and

12. The average estimated time that each meter/regulator run was operational in the calendar 

year.

From these data EPA can calculate the estimated metric tons of GHG emissions from natural gas 

distribution system operators. Reducing the number of calculations EPA requires responders to 

perform would ease reporting burdens and improve the quality of the data by reducing the 

potential for calculation errors.

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Even though EPA is proposing to no longer require natural gas distribution operators to convert 

metric tons of individual GHGs into CO2e, APGA notes that these operators must still determine 

if their estimated GHG emissions exceed the reporting threshold of 25,0000 in metric tons CO2e. 

This conversion should be performed by e-GGRT and e-GGRT should alert the reporting entity 

if the results of calculations using the 12 data elements listed above result in estimated GHG 

emissions at or above the reporting threshold of 25,000 metric tons CO2e.

APGA commends EPA for proposing to simplify the reporting of estimated greenhouse gas 

emission under Subpart W. The Subpart W regulations are extremely complex and confusing. 

Public gas utility managers have made best efforts to comply with EPA’s reporting requirements 

but still report difficulty understanding the equations and calculation methods. EPA should 

reduce reporting burdens and increase the accuracy of its data by limiting reporting to only those 

data necessary for EPA to calculate estimated GHG emissions.

Response: See response to comment EPA-HQ-OAR-2011-0512-0074-A1, Excerpt 3 in Section 

16.2 of this document.

Commenter Name: Pamela Lacey

Commenter Affiliation: American Gas Association (AGA)

Document Control Number: EPA-HQ-OAR-2011-0512-0083-A1

Comment Excerpt Number: 3

Comment: Clarify Section 98.236(r) Applicability: Section 98.236(r)(1) does not apply to 

equipment leaks at above grade metering-regulating stations that are not above grade 

transmission-distribution transfer stations, but this may not be sufficiently clear based on the 

proposed text. This should be clarified by revising the text in §98.236(r) or §98.236(r)(1). In 

addition, EPA should make it clear that section 98.236(r)(1) would not apply to equipment leaks 

at the above grade T-D transfer stations not surveyed during the reporting year.

Response: The EPA agrees with the commenter that the current reporting requirements may 

potentially be unclear. We have clarified the applicability of the reporting requirements of 

§98.236(r)(1) to be specific to emission source types required to use Equation W-32A. Only 

natural gas distribution facilities with above grade metering-regulating stations that are not above 

grade transmission-distribution transfer stations are required to report under §98.236(r)(2).

Commenter Name: Pamela Lacey

Commenter Affiliation: American Gas Association (AGA)

Document Control Number: EPA-HQ-OAR-2011-0512-0083-A1

Comment Excerpt Number: 4

Comment: AGA recommends the use of consistent nomenclature and terminology throughout 

the data collection sections [§§98.233(q) and (r)] and reporting sections [§§98.236(q) and (r)].

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For example, the units for the meter/regulator run emission factor (EFs,MR,i) in Equations W-31 

and W-32B are "standard cubic feet of GHGi per operational hour of all meter/regulator runs"; 

however, different terminology is used in the associated reporting section. The following are 

suggested clarifying edits to ensure that the rule uses consistent terminology. We have identified 

our suggested additional text in bold underline text and suggested deletions in strikethrough 

text.

"§ 98.236 Data reporting requirements.

...

(q) Equipment leak surveys.

...

(3) Natural gas distribution facilities must report the information specified in paragraphs (q)(3)(i) 

through (q)(3)(viii) of this subpart.

...

(vii) Meter/regulator run CO2 emission factor based on all surveyed transmission-distribution 

transfer stations in the current leak survey cycle, in standard cubic feet of CO2 per operational 

hour of all meter/regulator runs operating hour ("EFs,MR,i" for CO2 calculated using Equation 

W-31 of this subpart).

(viii) Meter/regulator run CH4 emission factor based on all surveyed transmission-distribution 

transfer stations in the current leak survey cycle, in standard cubic feet of CH4 per operational 

hour of all meter/regulator runs operating hour ("EFs,MR,i" for CH4 calculated using Equation 

W-31 of this subpart)."

Response: The EPA agrees with the commenter that the terminology used in §98.233(q) and 

§98.236(q) should be consistent, and for clarity, we have revised the final rule as suggested by 

the commenter.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 39

Comment: (§98.238) New definition for Meter/regulator run Meter/regulator run means a 

series of components used in regulating pressure or metering natural gas flow or both. At least 

one meter, at least on regulator, or any combination of both on a single run of piping is 

considered one meter/regulator run.

API requests that this definition include a statement that it applies specifically to the onshore 

natural gas distribution sector, so as not to confuse this definition with “meters/piping” as listed 

153
in Table W-1B for major onshore natural gas production equipment. API suggests the following 

revision to the definition:

“Meter run means a series of components used in metering natural gas flow or both in the 

onshore natural gas distribution sector. At least one meter, at least one regulator, or any 

combination of both on a single run of piping is considered one meter/regulator run.”

Response: The EPA finds the commenter's suggested revisions to the definition of 

“meter/regulator run” to be reasonable. We are finalizing changes to clarify that, for the purposes 

of subpart W, the term “meter/regulator run” applies to the natural gas distribution industry 

segment. The EPA notes that “onshore” is not part of the title for the natural gas distribution 

industry segment. 

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 29

Comment: Leaking and venting time – reporting requirements: Reporting element 

98.236(q)(2)(iii) should be reworded to more accurately reflect reality. The component leaking 

time that is used in Equation W-30 is based on broad assumptions; the time is not based on actual 

field observations. For example, many operators will fix leaks that are detected during the 

survey, but they may not choose to perform an additional survey to "get credit" for those fixes. It 

would be inaccurate to characterize this time as "found leaking and operational".

Response: The EPA agrees that the provisions of §98.236(q)(2)(iii) may be reworded to clarify 

that the time leaking is an assumed leak time. We have revised the definition of the term “Tp,z” in 

Equation W-30 and §98.233(q)(2)(iii) to refer to the time the surveyed components were 

assumed to be leaking and operational.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 36

Comment: Leaking and venting time – reporting requirements: Reporting element 

98.236(q)(2)(iii) should be reworded to more accurately reflect reality. The component leaking 

time that is used in Equation W-30 is based on broad assumptions; the time is not based on actual 

field observations. For example, many operators will fix leaks that are detected during the 

survey, but they may not choose to perform an additional survey to "get credit" for those fixes. It 

would be inaccurate to characterize this time as "found leaking and operational". Transmission 

storage tanks have a similar issue. The following changes are suggested:

154
98.236(q)(2)(iii) Average time the surveyed components were found leaking and operational are 

assumed to be leaking and operational according to 98.233(q), in hours (average of ‘‘Tp,z’’ 

from Equation W–30 of this subpart for the component type). 

Response: The EPA agrees that the provisions of §98.236(q)(2)(iii) may be reworded to clarify 

that the time leaking is an assumed leak time. We have revised the definition of the term “Tp,z” in 

Equation W-30 and §98.233(q)(2)(iii) to refer to the time the surveyed components were 

assumed to be leaking and operational.

17.0 Calculation of GHG Emissions from Natural Gas Volume Emissions

17.1 Comments on the use of default or site-specific gas composition

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 11

Comment: The Use of Site-Specific Composition Data Should Be Optional, Not Mandatory.

Subpart W currently specifies default methane and CO2 composition values for the onshore 

natural gas transmission compression; underground natural gas storage; LNG storage; LNG 

import and export; and local distribution pipeline natural gas industry segments.17

In the Proposed Rule, EPA has proposed to supplement this set of default gas composition values 

for each industry segment with the option to use site-specific data based on best engineering 

estimates.18 In the Proposed Rule, EPA also requests comment on whether the use of site-specific 

composition data that EPA proposes to include should be required or optional.19 

Kinder Morgan supports EPA’s proposal to add the option to use site-specific data as proposed, 

while retaining the option to use the default methane and CO2 composition values currently 

specified in Subpart W. Kinder Morgan unambiguously answers EPA’s question about whether 

the use of site-specific composition data should be mandatory in the negative. Compressor 

stations are normally not equipped with gas chromatographs for determination of site-specific 

gas composition, so the use of default values at those stations without gas chromatographs is 

absolutely essential. Mandatory reporting of site-specific gas composition would require the 

collection of extended gas analyses annually at each compressor station. That would result in 

increased costs and burden to natural gas operators with the installation of dozens (or hundreds) 

of gas chromatographs, ancillary equipment, and additional staff resources to monitor and 

maintain this equipment. Kinder Morgan and other companies operate gas chromatographs 

located at strategic points along their pipeline systems, but not at every compressor station or gas 

plant. The gas chromatographs are primarily used to confirm that the natural gas being 

transported meets gas tariff and customer specifications.

The default gas composition values currently found in Subpart W should be retained. While the 

optional use of site-specific composition data adds flexibility for operators already using site gas 

155
quality data for other reporting purposes, the use of default composition values simplifies 

reporting without compromising GHG emission estimates for operators, because natural gas 

composition values downstream of processing facilities are much less variable than upstream 

operations. For these reasons, Kinder Morgan strongly supports the Agency’s proposal as 

written, which provides for optional reporting of site-specific gas composition data when such 

data is available.

Footnotes:

17 See 40 C.F.R. § 98.233(u)(2)(iii)-(vii).

18 Although the Proposed Rule does not propose this option for the underground natural gas 

storage industry segment, see Proposed Rule at 13445 (not proposing to amend § 

98.233(u)(2)(iv)), Kinder Morgan believes this is an oversight by EPA and requests that the same 

change be applied to the underground natural gas storage industry segment. See INGAA 

Comments.

19 Proposed Rule at 1339.

Response: The EPA is finalizing revisions to allow facilities the option to use either sitespecific composition data or to use a default gas composition for the onshore natural gas 

transmission compression; underground natural gas storage; LNG storage; LNG import and 

export; and natural gas distribution industry segments. See Section II.B.13 of the preamble to the 

final rule for additional discussion responding to this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 46

Comment: Gas Composition: INGAA supports revisions that clarify the optional use of site 

data or default methane and CO2 values for gas composition for T&S sources. 

Subpart W currently includes default values for natural gas methane and CO2 composition for 

T&S and other segments downstream of processing and also allows the use of site data. EPA 

added these default values in previous Subpart W amendments in response to INGAA comments. 

INGAA has also requested that the rule clearly allow operators to use specific data rather than 

the default values, with this choice optional at the discretion of the operator. For example, some 

operators are using site-specific gas quality data for other reporting purposes and prefer 

consistency. The optional use of site data or default values provides flexibility, while the use of 

default values simplifies reporting without compromising estimates, because gas quality 

downstream of processing is much less variable than upstream operations. Thus, INGAA 

supports the Proposed Rule revision to §98.233(u)(2)(iii) that clearly allows default values or site 

data based on best available data, "either a default 95 percent methane and 1 percent carbon 

156
dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based 

on best available data."

In addition, at 79 FR 13398 EPA requests comment on whether the use of site data should be 

required or optional. INGAA strongly supports maintaining the option to use default values or 

site-specific data at the discretion of the reporter. As noted above, default values were added in 

previous amendments and EPA should not undermine earlier progress in this rulemaking. If 

additional background is desired, EPA should refer to earlier comments and decisions regarding 

the use of default composition for T&S.

Response: The EPA is finalizing revisions to allow facilities the option to use either site-specific 

composition data or to use a default gas composition for the onshore natural gas transmission 

compression; underground natural gas storage; LNG storage; LNG import and export; and 

natural gas distribution industry segments. See Section II.B.13 of the preamble to the final rule 

for additional discussion responding to this comment.

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 7

Comment: Mandatory Use of Site Specific Gas Composition. The proposed rule adds the 

option of using site-specific gas composition rather than the current default gas composition and 

the preamble requests comment on whether using site specific data should be mandatory. The 

mandatory use of site specific gas composition is potentially problematic due to the additional 

sampling and recordkeeping required. Unless there is a significant difference between the site 

specific composition and the default composition, the additional cost would not likely be 

warranted. We do not maintain site-specific gas compositions at each station and the logistics 

and cost of conducting additional gas analysis will increase the program costs. We request that 

the agency does not make the use of site-specific gas composition mandatory because the default 

value of 95% methane and 1 % carbon dioxide is conservative in that most natural gas 

compositions that are significantly different than the default would have a lower CO2e than that 

of the default composition. The use of site-specific gas composition should be used only if it is 

available. We ask that the agency allow reporters to have the option of sampling should they 

choose to do so.

Response: The EPA is finalizing revisions to allow facilities the option to use either sitespecific composition data or to use a default gas composition for the onshore natural gas 

transmission compression; underground natural gas storage; LNG storage; LNG import and 

export; and natural gas distribution industry segments. See Section II.B.13 of the preamble to the 

final rule for additional discussion responding to this comment.

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Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 53

Comment: The Proposed Rule inadvertently omits analogous revisions for underground 

storage. EPA completed the revision noted above to §98.233(u)(2)(iii) and (v) – (vii), which 

encompasses all segments downstream of processing other than section (iv) for underground 

storage. INGAA had requested this revision for T&S – i.e., natural gas transmission compression 

and underground natural gas storage segments. The preamble indicates that EPA intended to 

include this revision for underground storage and this appears to be an oversight. If not, EPA has 

not explained why this option is not allowed for underground storage. The preamble text 

regarding underground storage follows:

"We are proposing to allow either the use of site-specific composition data for natural gas 

transmission compression and underground natural gas storage facilities or the use of a default 

gas composition..." [79 FR 13398]

For consistency with (u)(2)(iii) and the preamble discussion, §98.233(u)(2)(iv) for underground 

storage should be revised consistent with the proposed text in §98.233(u)(2)(iii). It is appropriate 

to clearly provide the same flexibility to underground storage as is provided for transmission 

compression and other downstream segments.

Response: The commenter is correct that it was the EPA's intention to revise §98.233(u)(2)(iv); 

however, this change was inadvertently omitted from the proposed rule text. In this final rule, we 

have revised §98.233(u)(2)(iv) to be consistent with the changes to §98.233(u)(2)(i) through (iii) 

and (v) through (vii) to allow for the use of either site-specific or default gas compositions for all 

industry segments. See Section II.B.13 of the preamble to the final rule for additional discussion 

responding to this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 48

Comment: Gas Composition: EPA requested comment on whether T&S sources should be 

required to use site data on gas composition or its use should be optional. The Proposed Rule 

clarifies that default gas composition or site-specific data can be used. INGAA requested and 

supports the option to use site data or default values at the operator’s discretion. In addition, EPA 

should address an apparent oversight, and include the same text regarding optional use of site 

data in §98.233(u)(2)(iv) for the underground storage segment.

Response: The commenter is correct that it was the EPA's intention to revise §98.233(u)(2)(iv); 

however, this change was inadvertently omitted from the proposed rule text. In this final rule, we 

have revised §98.233(u)(2)(iv) to be consistent with the changes to §98.233(u)(2)(i) through (iii) 

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and (v) through (vii) to allow for the use of either site-specific or default gas compositions for all 

industry segments. See Section II.B.13 of the preamble to the final rule for additional discussion 

responding to this comment.

17.2 Comments on the need to use “actual” versus “standard” conditions

Commenter Name: Carrie B. Crumpton

Commenter Affiliation: CONSOL Energy, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0080-A1

Comment Excerpt Number: 6, 8 and 9

Comment: Requiring the conversion of gas flow rates from "standard conditions" to "actual 

conditions" when applying required estimation methodology is burdensome and overly 

complicated. These estimations then have to be converted back into standard conditions for 

reporting under the regulatory requirements. Since instrumentation used in the industry typically 

measures gas flow rates in standard conditions, CONSOL request the EPA to revise Equations 

W-3, W-4A, W-4B, W-7, W-17A, W-17B, W-34, W-39A, and W-39B to reflect that the 

measured gas volumes and/or estimated gas volumes used in these equations, and the resulting 

emissions, are in standard conditions to better meet reporting requirements and consistency.

Response: The EPA recognizes that there are flow or volume measurement systems that 

automatically convert measurements to standard conditions. It was not our intent to require 

facilities to convert this data to actual conditions to fulfill the certain calculation and reporting 

requirements, then convert the volumes back to standard conditions prior to determining GHG 

mass emissions. We are finalizing revisions to the introductory text at §98.233 and §98.236 to 

clarify that use of systems that automatically correct to standard conditions is allowed for these 

equations. See Section II.B.13 of the preamble to the final rule for additional discussion 

responding to this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 17, 19 and 20

Comment: Gas Flow Rate Measurements. In discussions with EPA, API has emphasized the 

need to use industry standard conditions for gas flow and volume measurements. API urges EPA 

to revise the terms for Equations W-3, W-4A, W-4B, W-7, W-17A, W-17B, W-39A, and W-39B 

to reflect that measured or estimated gas volumes used in these equations and the resulting 

emissions are in standard conditions. This is particularly the case for Equation W-34 because it 

makes no sense to take a gas flow rate already determined in standard conditions to convert it to 

actual conditions just to apply a required estimation methodology which, in turn, will again 

convert it back to standard conditions per the rule requirements.

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Response: The EPA recognizes that there are flow or volume measurement systems that 

automatically convert measurements to standard conditions. It was not our intent to require 

facilities to convert this data to actual conditions to fulfill the certain calculation and reporting 

requirements, then convert the volumes back to standard conditions prior to determining GHG 

mass emissions. We are finalizing revisions to the introductory text at §98.233 and §98.236 to 

clarify that use of systems that automatically correct to standard conditions is allowed for these 

equations. See Section II.B.13 of the preamble to the final rule for additional discussion 

responding to this comment.

Commenter Name: V. Bruce Thompson

Commenter Affiliation: American Exploration & Production Council (AXPC)

Document Control Number: EPA-HQ-OAR-2011-0512-0085-A2

Comment Excerpt Number: 10

Comment: AXPC and the Alliance request that EPA allow for the use of site‐specific sampling 

analyses for use in modeling acid gas removal systems, dehydration units, and storage tanks. 

These analyses are sometimes permit required or available for other reasons and we believe that 

their use should be allowed in lieu of a sub‐basin analysis where they are available as they are 

more representative. However, AXPC believes that the option to use the sub‐basin analysis needs 

to be retained for those sources that do not have site‐specific analyses available. Likewise, we 

support the optional use of site‐specific samples for calculating pneumatic device emissions.

Response: The commenter refers to calculation methods in §98.233(d)(4), (e)(1), and (j)(1) that 

require modeling using standard simulation software packages, such as AspenTech HYSYS®, 

API 4679 AMINECALC, GRI-GLYCalcTM, or API 4697 E&P Tank. The rule currently provides 

for the use of either site-specific analyses or sub-basin analyses for use with these methods. For 

example, for acid gas removal units, §98.233(d)(4) provides for parameters determined by 

engineering estimate and process knowledge based on best available data. For dehydrators, 

§98.233(e)(1)(xi) provides for use of wet natural gas composition as calculated in 

§93.233(u)(2)(i) and (u)(2)(ii), which allows for the use of either a sub-basin or facility analysis, 

or other representative analysis, standard method, or standard industry practice. For onshore 

production storage tanks, §98.233(j)(1) specifies that all parameters must be determined by 

engineering estimate and process knowledge based on best available data and provides that 

facilities perform an analysis of oil composition on a sub-basin basis only if a current analysis is 

not available. Since reporters currently have the ability to use site-specific analyses for these 

calculation methods, we are making no revisions to the final rule.

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18.0 Onshore Petroleum and Natural Gas Production and Natural Gas 

Distribution Combustion Sources

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 74

Comment: Onshore petroleum and natural gas production and natural gas distribution 

combustion emissions.

Revisions to §98.233(z): EPA is proposing clarifying text revisions. These include specifying 

that the term Va in Equations W-39A and W-39B is the actual volume, the Y terms refer to mole 

fractions instead of “concentrations”, and N2O mass emissions are calculated in tonnes of N2O 

instead of tonnes of CO2e.

Industry practice is to calculate or meter gas volume in standard conditions, not actual 

conditions. API requests that Equations W-39A and W-39B be revised to reflect that the gas 

volume terms and the resulting emissions are in standard conditions.

Response: See response to comment EPA-HQ-OAR-2011-0512-0080-A1, Excerpt 6 in Section 

17.2 of this document.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 75

Comment: API requests the option to use a site specific heating value in Equation W-40 for 

field gas or process vent gas, where this information is available. This is similar to EPA’s 

consideration of the use of site specific gas composition data for §98.233(a) and (b).

Response: The EPA agrees with the commenter. We had proposed to revise the definition of the 

“HHV” term in Equation W-40 specifically to indicate that the higher heating value must be 

determined on fuel-specific basis although we provided a default HHV value when the fuel is 

field or process vent gas. However, we did not intend to mandate the use of this default HHV 

value when site-specific data are available to determine HHV for these fuels. To further clarify 

our intent, we are revising parameter “HHV” of Equation W-40 as follows: “Higher heating 

value of fuel, mmBtu/unit of fuel (in units consistent with the fuel quantity combusted). For the 

higher heating value for field gas or process vent gas, you may use 1.235 × 10−3 mmBtu/scf for 

HHV. For natural gas that in not of pipeline quality or that has a high heating value of less than 

950 Btu per standard cubic foot, use a site-specific higher heating value (based on best available 

data).”

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19.0 Revisions to Missing Data Provisions 

19.1 Revisions to §98.235 to specify the use, treatment, and reporting of missing 

data 

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 15

Comment: Acid Gas Removal Vents

Section 98.235(a) states that where there is a missing sample from quarterly gas samples taken 

pursuant to § 98.233(d)(8)(ii), concerning emissions calculations for acid gas removal vents, 

"you must substitute the average value of the last four samples for which data are available." The 

text of § 98.235(a) should be amended to accommodate new acid gas removal vents that may not 

have four previously taken samples available (e.g., for a new unit that starts up during the 

reporting year or at facilities that were previously below the reporting threshold). For this reason, 

Kinder Morgan proposes that § 98.235(a) be modified as indicated in Figure 2.

Figure 2: Proposed Modifications to 40 C.F.R. §98.235(a).

Proposed 40 C.F.R. § 98.235. Procedures for estimating missing data.

. . .

(a) If you choose to take quarterly gas samples as allowed in § 98.233(d) in lieu of using a 

continuous gas analyzer, and there is a missing sample, you must substitute the average value of 

the last four samples for which data are available. Where the last four samples are not 

available, you should use the average of all available samples that are representative.

Response: The EPA agrees with the commenter that there may be situations, particularly for 

new acid gas removal vents, when the reporter will not have results available from four previous 

quarterly samples. In considering potential clarifications for the missing data procedures for acid 

gas removal vents in light of the various scenarios of data availability, the missing data 

procedures for this source mirrored the procedures proposed in §98.235(d). Furthermore, we 

determined that the use of the average of a “before” and “after” sample would provide as good 

an estimate of the missing data as the average of four “before” samples. Therefore, we are 

generalizing the proposed missing data procedures in §98.235(d) to apply to all measurements 

that are required to be performed quarterly or more frequently. See Section II.C of the preamble 

for further discussion regarding missing data procedures for acid gas removal vents.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 77

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Comment: In the proposed rule, the BAMM section, §98.234(f) is deleted and the missing data 

section §98.235 is significantly revised. As EPA well knows, use of BAMM to address issues 

with requirements under the rule was common for the 2011, 2012, and 2013 reporting years. API 

assumes that EPA is proposing to revise §98.235 to provide an avenue to compliance for 

instances where the complex and voluminous requirements for data collection and measurement 

are not fully met. However, API and its members find the missing data procedures in the 

proposed rule to be somewhat confusing, unnecessarily burdensome, and not sufficient to 

provide the flexibility needed to enable compliance. Specifically, API provides the following 

commentary regarding the proposed missing data procedures and suggested changes to address 

the problems identified.

The proposed language at §98.235(d) poses a problem where “before” or “after” values are not 

available for a data element that requires measurement. The proposed language is:

(d) For each missing value of a parameter that should have been measured using a continuous 

flow meter, composition analyzer, thermocouple, or pressure gauge, you must substitute the 

arithmetic average of the quality-assured values of that parameter immediately preceding and 

immediately following the missing data incident. If the “after” value is not obtained by the end 

of the reporting year, you may use the “before” value for the missing data substitution. If, for a 

particular parameter, no quality-assured data are available prior to the missing data incident, you 

must use the first quality assured value obtained after the missing data period as the substitute 

data value. A value is quality-assured according to the procedures specified in §98.234.

Instances where a “before” or “after” value is not available for substitution can occur and will 

require additional flexibility to enable compliance. For example:

• Where information from a third-party equipment operator, such as a third-party operated 

dehydrator greater than 0.4 MMSCF/Day, is not received, the reporter may very well not 

have either “before” or “after” data to substitute in order to run the prescribed model to

calculate emissions. Although, in general, the calculation procedures at §98.233(e)(1) specify 

that an engineering estimate based on best available data may be used in this instance, the 

reporter has limited or no data on which to base an engineering estimate. Unless the reporter 

is successful in getting the required data they will have no ability to substitute values in order 

to comply. This situation is exacerbated by the significantly expanded requirements for 

reporting of data elements in §98.236(e).

• Where taking a required measurement on a compressor vent source is not safe due to facility 

configuration or other characteristics, and use of an acoustic device is not feasible due to 

background vibration noise, the reporter will not have “before” or “after” data

available for substitution. API recognizes and appreciates that EPA has eliminated many of 

these potential issues by enabling measurement of manifolded compressor vents and 

changing compressor vents routed to flare to be included in the flare calculations, these 

changes will not eliminate the potential for such unsafe instances to occur.

• Where a well completion in a sub-basin category/county/well-type combination is a single 

unique well for a particular reporter and the measurement equipment necessary to measure 

flowback or calculate flowback malfunctions, a reporter will not have “before” data to 

substitute. Where the reporter does not drill and complete another well in the same sub-basin 

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category/county/well-type combination prior to the reporting due date (or ever) they will 

have no “after” data to substitute. This scenario becomes more likely with EPA’s proposed 

expansion of “well types”, addressed elsewhere in these comments, that will in theory, 

quadruple the number of completions and/or workovers that require either measurement or 

calculation of flowback volume post hydraulic fracturing of a well.

In prior years a reporter would rely on BAMM and use data from an analogous source to “fill in” 

the data which was not obtained. However, with the elimination of BAMM this option is no 

longer available. To solve this issue API recommends modifying 98.235 (d) as follows:

(d) For each missing value of a parameter that should have been measured using a continuous 

flow meter, composition analyzer, thermocouple, or pressure gauge, you must substitute the 

arithmetic average of the quality-assured values of that parameter immediately preceding and 

immediately following the missing data incident. If the “after” value is not obtained by the end 

of the reporting year, you may use the “before” value for the missing data substitution. If, for a 

particular parameter, no quality-assured data are available prior to the missing data incident, you 

must use the first quality-assured value obtained after the missing data period as the substitute 

data value. A value is quality-assured according to the procedures specified in §98.234. Where a 

“before” or “after” value for a data element is not available a reporter may substitute a 

value based on engineering estimate using the best available data.

Modifying §98.235(d) to address those instances where “before” or “after” values are not 

available for data substitution is necessary if BAMM is to be eliminated as EPA has proposed. If 

EPA is not willing to make these changes, API is more opposed to BAMM elimination that 

discussed elsewhere in these comments.

Response: The proposed provisions of §98.235(d) were not meant to address measurement data 

that are required annually or biannually or situations such as the supply of information by thirdparty vendors. Reporters should know what information is needed for the annual reports and 

must make every effort to collect all necessary data. If reporters elect to use third-party vendors 

for certain services, the information needed for the annual reports may be specified in the thirdparty contract or agreement to ensure the necessary information is provided. We are not 

including any missing data provision in the final rule to allow for use of third-party operators that 

do not provide the required information needed for determining the emissions from dehydrators 

or other emissions sources. We are providing missing data provisions specific to annual 

measurement requirements. See Section II.C of the preamble to the final rule for further 

discussion regarding the final missing data procedures.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 78

Comment: In the revisions to §98.235(d) above, API requests that “thermocouple” be removed 

from the list of measurement devices applicable to the missing data procedures. The Monitoring 

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and QA/QC requirements under §98.234(b) do not list thermocouples as a measurement device. 

So, best engineering estimates are already permitted for missing thermocouple data.

Response: The EPA has determined that the error is in the omission of temperature monitors 

(thermocouples) in the list of monitors §98.234(b). Many of the calculation procedures require 

the determination of temperature. The provisions of §98.235(d) are intended to provide guidance 

for reporters to determine a substitute data value for situations in which a continuous or frequent 

measurement data are missed, and we have determined that these procedures should be applied 

when temperature measurement data needed for the calculations are missed. We are not 

amending §98.234(b) at this time because no revisions to this paragraph were proposed. 

However, we will consider whether it is necessary to make revision to §98.234(b) in future 

regulatory actions.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 3

Comment: §98.235(e) should be revised to allow best engineering estimates for the first 

reporting year for facilities that become newly subject to Subpart W. An unexpected late year 

(e.g., December) event (e.g., a large pipeline blow down or increased compressor throughput at a 

transmission station due to increased customer demand for natural gas in the winter months) 

could trigger first time applicability for a facility. An allowance to use best engineering estimates 

for six months would not cover the entire calendar year, and under this circumstance the facility 

would require the use of best engineering estimates for the initial reporting year because the 

previously not subject facility would not have been collecting all data required for Subpart W 

reporting. The ongoing reporting obligation would require measurements, data collection, etc. in 

the second year, shortly after the facility applicability change following a late year triggering

event.

To address late year events that trigger first time facility applicability, SoCal Gas recommends 

that the following revisions be made to §98.235(e):

"For the first six months of required data collection, For the first reporting year, facilities that 

become newly subject to this subpart W may use best engineering estimates for any data that 

cannot reasonably be measured or obtained according to the requirements of this subpart.

Response: The EPA contends that 6 months is enough time for a newly subject facility to begin 

using the methods required in §98.233. This time period is consistent with requirements in the 

final subpart W rule, in which we previously allowed the use of BAMM for the first six months 

of data collection to allow reporters newly subject to subpart W to comply. See Section II.C of 

the preamble to the final rule for additional discussion responding to this comment.

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Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 13

Comment: §98.235(g) and related reporting requirements in §98.236(bb) should be revised to 

clarify broad applicability.

As discussed above, it is imperative that missing data provisions address situations where 

measurement cannot be conducted or alternatives are necessary. Since §98.235(g) addresses 

"other" situations not specifically defined within other missing data subsections, it appears that 

§98.235(g) is intended to have broader applicability than the provisions in §98.235(a) – (f). 

However, INGAA recommends that EPA include clarifications in order to clearly address 

measurement and monitoring related issues. Additional explanation of §98.235 terminology 

(e.g., "activity data") is also needed. This can be accomplished via additional discussion and 

explanation in the preamble or related background memos (e.g., the technical support memo), 

but INGAA’s preferred approach for clarifying applicability to measurement data is to also 

include minor clarifying revisions to §98.235(g):

"(g) For each missing value of any activity data or measurement not described in this section 

you must substitute data value(s) using the best available estimate(s) of the parameter(s), based 

on all available process data (including, but not limited to, processing rates, operating hours) or 

other measurements."

INGAA also recommends complementary discussion in the preamble of the final rule. In 

addition, the associated reporting obligation should be revised for consistency and clarity. 

INGAA recommends the following revisions to §98.236(bb):

"...

(3) The description of the unique or unusual circumstance or measurement barriers that led to 

missing data use, including information on any equipment or components involved and any 

procedures that were not followed.

(4) The description of the procedures used to substitute an unavailable value of a parameter.

(5) The description of how the owner or operator will avoid or minimize the use of missing data 

in the future, such as mitigation strategies or changes to standard operating procedures."

As discussed in comments above, Subpart W measurement requirements are inextricably linked 

to access to alternative measurement and estimation methods when measurement is precluded. 

These revisions are requested to provide clarity, and additional discussion in the preamble or 

support documents should further elucidate EPA’s intent. Without this interpretation and clear 

applicability of missing data provisions, INGAA strongly objects to the elimination of BAMM 

provisions.

Response: The provisions proposed in §98.235(g) were intended to be used for data for which 

direct measurements are not required, such as the time a compressor was in a specific mode of 

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operation. The provisions in this paragraph were not intended to be applied to data required to be 

directly measured so we are not making the revision suggested by the commenter to §98.235(g).

With respect to the reporting requirements, these reporting elements cited by the commenter 

have been significantly revised and the edits suggested by the commenter are not applicable to 

the final missing data reporting requirements. See Section II.C of the preamble to the final rule 

for further discussion regarding the missing data procedures and the reporting requirements for 

the use of missing data procedures in the final rule.

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 10

Comment: The solution proposed by the rule to address situations when data is not available is 

found in the "missing data" provisions (40 C.F.R. 98.235, as proposed) which read: " ... 

whenever a value of a parameter (emphasis added) is unavailable for a GHG emission 

calculations required by this subpart (including, but not limited to, if a measuring device 

malfunctions during unit operations, a required gas sample is not taken, or activity data are not 

collected), you must follow the procedures specified in paragraphs (a) through (h)."

It is not clear if this means that a reporter would be allowed to estimate calculation inputs only, 

or if it means that they can also estimate emissions from points that are required to be directly 

measured. If it means that emissions can be estimated for sources that are required to be directly 

measured, then this is a viable solution; if not, then this will not solve the problem of 

inaccessible monitoring points that may be new to the program as described above. We ask that 

EPA review this provision and clearly indicate the circumstances, if any, where estimations per 

the "missing data" provisions would not be allowed. Further, we ask that the agency consider 

minor clarifying revisions to §98.235(g):

"(g) For each missing value of any activity data or measurement not described in this section 

you must substitute data value(s) using the best available estimate(s) of the parameter(s), based 

on all available process data (including, but not limited to, processing rates, operating hours) or 

other measurements."

Response: The provisions in §98.235 are applicable to parameters used for the GHG emission 

calculations (i.e., used in the equations in §98.233). Some of these “parameters” are direct 

emission measurements (e.g., for compressors) that are then used in subsequent reporter-specific 

emission factor calculations. We have clarified specific missing data procedures in §98.235 

based on the measurement frequency required for that parameter. The provisions proposed in 

§98.235(g) were intended to be used for data for which direct measurements are not required, 

such as the time a compressor was in a specific mode of operation. The provisions in paragraph 

§98.235(g) were not intended to be applied to data required to be directly measured so we are not 

making the revision suggested by the commenter to §98.235(g). See Section II.C of the preamble 

to the final rule for further discussion regarding the missing data procedures and the reporting 

requirements for the use of missing data procedures in the final rule.

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Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 6

Comment: Clarification of "Activity Data" for Emissions Calculations

Section 98.235(g) states that for each missing value of "activity data" not described in § 98.235, 

the reporting entity must substitute data values using the best available estimates of parameters, 

based on all available process data. Kinder Morgan believes the Agency intends for this term to 

be interpreted broadly and supports such an approach.7 Consistent with this understanding, 

Kinder Morgan urges EPA to clarify that the term "activity data" encompasses the following:

• Dehydrator vents: the following data elements used in Equation W-6 (part of Calculation 

Method 3) in § 98.233(e): atmospheric pressure (P1); pressure of the gas being discharged 

(P2); percent of packed vessel volume that is gas (%G); and the number of dehydrator 

openings in the calendar year (N).

• Blowdown vent stacks: the following data elements used in Equations W-14A and W-14B in 

§ 98.233(i): number of occurrences of blowdowns for each unique physical volume in the 

calendar year (N); temperature at actual conditions (Ta,Ta,p); absolute pressure at actual 

conditions (Pa, Pa,b,p, Pa,e,p); and compressibility factor at actual conditions (Za).

• Equipment leaks by population count: the following data elements used in Equation W-32A 

in § 98.233(r): total number of underground natural gas storage wellhead components 

(Counte); and average estimated time that each emission source type associated with the 

equipment leak emission was operational in the calendar year, in hours (Te).

• GHG volumetric emissions using actual conditions: the following data elements used in 

Equation W-34 in § 98.233(t): temperature at actual conditions (Ta); absolute pressure at 

actual conditions (Pa); compressibility factor at actual conditions for GHGi (Za).

Accordingly, Kinder Morgan requests that EPA make the clarifications noted above by 

modifying proposed § 98.235(g) as indicated in Figure 1:

Proposed 40 C.F.R. § 98.235. Procedures for estimating missing data.

. . .

(g) For each missing value of any activity data (including any information or data necessary 

to comply with this subpart) not described in this section, you must substitute data value(s) 

using the best available estimate(s) of the parameter(s), based on all available process data 

(including, but not limited to, processing rates, operating hours).

FOOTNOTE:

7 See Proposed Rule at 13404 (noting that the new missing data procedures would apply to many 

new areas of Subpart W, and connecting that to the proposed removal of BAMM).

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Response: The activity data referred to in §98.235(g) includes data describing facility activities, 

such as counts. For example, activity data would include the number of dehydrator openings in 

the calendar year, number of occurrences of blowdowns for each unique physical volume in the 

calendar year, and total number of underground natural gas storage wellhead components. The 

provisions of §98.233(g) do not refer to values that are already determined using engineering 

estimates based on best available data or that are required to be measured, such as pressures or 

temperatures. The EPA has provided specific missing data procedures to address missing 

measured values in other paragraphs of §98.235. We are not incorporating the language 

suggested by the commenter because it is too broad. See Section II.C of the preamble to the final 

rule for further discussion regarding the missing data procedures and the reporting requirements 

for the use of missing data procedures in the final rule.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 5

Comment: §98.235(g) and related reporting requirements in §98.236(bb) should be revised to 

clarify applicability of the Missing Data provisions. As discussed above, it is imperative that 

missing data provisions cover circumstances where standard measurement procedures cannot be 

utilized, making alternative methods necessary. Because §98.235(g) addresses "other" situations 

(I.e., not specifically defined within other missing data subsections), it appears that §98.235(g) is 

intended to have broader applicability than the other subsections. SoCal Gas recommends minor 

revisions to §98.235(g) to more clearly address measurement and monitoring related issues:

"For each missing value of any activity data or measurement not described in this section you 

must substitute data value(s) using the best available estimate(s) of the parameter(s), based on all 

available process data (including, but not limited to, processing rates, operating hours), other 

measurements or information."

In addition, the associated reporting obligation should be revised for consistency and clarity, and 

the following revisions to §98.236(bb) are recommended:

"...

(3) The description of the unique or unusual circumstance or measurement barriers that led to 

missing data use, including information on any equipment or components involved and any 

procedures that were not followed.

(4) The description of the procedures used to substitute an unavailable value of a parameter.

(5) The description of how the owner or operator will avoid or minimize the use of missing data 

in the future, such as mitigation strategies or changes to standard operating procedures."

Response: See response to comment EPA-HQ-OAR-2011-0512-0073-A1, Excerpt 10 in this 

section.

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Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 80

Comment: The proposed language at §98.235(g) is not clear and needs to be revised for clarity. 

The requirement to use “all available process data (including but not limited to, processing rates, 

operating hours).” when making a “best available estimate” is overly broad and not clear. For 

instance, a reporter may be making an estimate that is related to or dependent on a small subset 

of process data, in which instance the requirement to use “all available process data” is not useful 

or logical. To address this issue API recommends modifying the proposed §98.235(g) language 

as follows:

Existing proposal language: (g) For each missing value of any activity data not described in this 

section, you must substitute data value(s) using the best available estimate(s) of the parameter(s), 

based on all available process data (including, but not limited to,

processing rates, operating hours).

Suggested language: (g) For each missing value of any activity data not described in this section, 

you must substitute data value(s) using the best available estimate(s) of the parameter(s), based 

on all applicable and available process or other data (including, but

not limited to, e.g. processing rates, operating hours).

Response: The EPA agrees with the commenter that the language in §98.235(g) could be made 

clearer by replacing the term “all available process data” with the term “all applicable and 

available process data”. We have not made the changes associated with the parenthetical phrase 

to keep the language consistent with similar language throughout the rule. The final language for 

§98.235(g) is as follows:

“Unless addressed in another paragraph of this section, for each missing value of any activity 

data, you must substitute data value(s) using the best available estimate(s) of the parameter(s), 

based on all applicable and available process or other data (including, but not limited to, 

processing rates, operating hours).”

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 17

Comment: Specific Missing Data Provision for Centrifugal Compressors, Reciprocating 

Compressors, and Equipment Leak Surveys: 

Because Subpart W requires detailed annual measurements of emissions of centrifugal 

compressors and reciprocating compressors, and to avoid any confusion with or misinterpretation 

of the other missing data provisions under § 98.235, Kinder Morgan recommends the addition of 

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separate missing data provisions specific to each of these compressor types, as indicated in 

subparagraphs (i) and (j) of Figure 4.

Because Subpart W requires annual leak detection surveys for subject facilities, but reporters 

may not know whether subject facilities need surveys until after the reporting year has 

concluded, Kinder Morgan recommends the addition of a separate missing data provision 

specific to leak detection surveys as indicated in subparagraph (k) of Figure 4.

Figure 4: Proposed Additions to 40 C.F.R. § 98.235.

. . .

(i) For any leak measurements for centrifugal compressors (including continuous measurements) 

under Section 98.233(o) that were unable to be completed during a reporting year, the use of best 

available data considered representative of the compressor(s) may be substituted and this 

representative data may include, but is not limited to, the use of the reporter emission factor for 

the corresponding compressor-mode source combination for the reporting year. The reporter 

emission factor(s) are calculated using Equation W-23 under Section 98.233(o)(6)(iii).

(j) For any leak measurements for reciprocating compressors (including continuous 

measurements) under Section 98.233(p) that were unable to be completed during a reporting 

year, the use of best available data considered representative of the compressor(s) can be 

substituted and this representative data may include, but is not limited to, the use of the reporter 

emission factor for the corresponding compressor-mode source combination for the reporting 

year. The reporter emission factor(s) are calculated using Equation W-28 under Section 

98.233(p)(6)(iii).

(k) If a facility is unable to complete its leak detection survey during the reporting year in which 

the leak detection survey was required to be performed, that facility shall document the reason(s) 

for not completing the leak survey during the reporting year and the leak detection survey will be 

completed as soon as possible in the subsequent calendar year, but no later than 90 days after the 

beginning of the subsequent calendar year. This leak detection survey may only be used for the 

reporting year’s emission estimation and it may not be used for the subsequent calendar year’s 

emission estimation. The facility shall perform another leak detection survey performed for the 

subsequent calendar year, and a minimum of 30 days must separate the two leak detection 

surveys.

Response: The EPA has added specific missing data procedures for measurements that are 

required to be performed annually; these procedures require repeat measurement as soon as 

possible, including in the subsequent calendar year, similar to the language suggested by the 

commenter for paragraph (k). These missing data procedures are applicable to all measurements 

that required to be performed annually; we are not providing different, source-specific missing 

data procedures as suggested by the commenter. For compressors that use continuous 

measurements, the appropriate missing data procedures are outlined in the proposed paragraph at 

§98.235(d); these provisions are finalized, with minor revisions as paragraph §98.235(b). With 

respect to new sources, we proposed specific provisions for them at §98.235(e) and (f); these 

provisions are finalized with minor clarifying revisions (to broaden the applicability of paragraph 

(f) to “sources” rather than “wells”).

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Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 11

Comment: Eliminating BAMM compromises the ability to comply unless Missing Data 

provisions address alternative approaches.

The Proposed Rule deletes the BAMM section, §98.234(f), and significantly revises §98.235, 

which addresses Missing Data. Since access to alternatives is a regulatory imperative, especially 

when measurement is required, INGAA presumes that proposed Missing Data revisions are 

intended to address all types of BAMM requests previously approved by EPA.

Several new provisions are proposed for the missing data section. Section 98.235(b) 

contemplates a measurement issue associated with transmission tanks; §98.235(d) contemplates 

certain aspects of missing data associated with a measurement, §98.235(e) and (f) consider 

facility and source-level issues, and §98.235(g) broadly covers situations other than those 

addressed in those defined in §98.235(a) – (f).

If the BAMM section is deleted, it is imperative that §98.235 address all scenarios that have been 

addressed for 2011 through 2014 compliance using BAMM requests. Comment 6 recommends 

revisions to clarify and improve proposed revisions to §98.235 based on example scenarios 

where missing data provisions would need to be applied.

In some cases, it is apparent that missing data provisions would apply. For example:

• BAMM has been requested to address the occurrence of (or potential for) a late year event 

(e.g., unexpected blowdown) that results in a facility that has not reported becoming newly 

subject. §98.235(e) addresses the scenario by allowing best engineering estimates.

− However, INGAA recommends the rule allow the use of best estimates for the first 

reporting year. As an example, facility emissions could be well below the reporting threshold 

for many years, until a single late year (e.g., December) pipeline blowdown within the station 

boundary triggers applicability. A six month allowance for using best engineering estimates 

does not provide enough coverage, and in this scenario, the facility should be allowed to use 

best engineering estimates for the initial reporting year. The ongoing reporting obligation 

would require measurements, data collection, etc., in the second year, shortly after 

applicability changes following a late year triggering event. INGAA recommends the 

following revision to §98.235(e):

"For the first reporting year, facilities that become newly subject to subpart W may use 

best engineering estimates for any data that cannot reasonably be measured or obtained 

according to the requirements of this subpart."

• §98.235(b) addresses the situation where transmission tank monitoring is not completed, and 

indicates that leakage for the entire year should be assumed.

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− However, the provision does not indicate what leak rate should be assumed. Previous data 

could be used if available. If previous data is not available, a leak rate equivalent to the leak 

threshold defined in §98.234(a)(5) could be used. The reporting obligation in §98.236(bb)(5) 

would identify how this missed data scenario would be avoided in the future. There may be 

scenarios where safe access is precluded.

For a number of examples where BAMM was previously requested, similar scenarios will occur 

in 2015 and beyond. Missing data provisions should apply to these situations. Revisions are 

needed to add or clarify applicability of the missing data provisions and EPA’s intent must be 

clearly understood to avoid implementation or compliance problems. Primary concerns include:

• Late year changes at a facility that trigger reporting for the first time or where a new source is 

added at a subject facility. Data many not be available and best engineering estimates should 

be allowed.

• Applicability is clear for the former case (newly affected facility) but not the latter (subject 

facility with new emissions source);

• Vent lines that cannot be safely or feasibly measured and where acoustic device 

measurement is not an option;

• Data that is not available for compressor measurements mandated in a specific mode, 

especially when a wealth of measurement data is available to develop operator emission 

factors for modes not measured.

Several more specific examples and related discussion follows:

• §98.235(f) applies for subject production facilities when new wells are added. INGAA 

supports this provision, but its applicability should be broadened to cover similar scenarios 

for all Subpart W segments – i.e., the scenario where there is a change (e.g., new source) at a 

subject facility, and the reporter cannot reasonably acquire necessary data.

− For example, BAMM has been requested to address unforeseen changes, especially late in 

the year, at an affected facility because it may not be feasible or reasonable to collect all 

required data for a newly affected source at an existing, reporting facility. For example, at an 

existing compressor station, new compression capacity may be added to address anticipated 

demand. The compressor may come on-line late in the year (e.g., December) in preparation 

for the heating season. In this case, the new source (compressor) should be provided the same 

allowance afforded to wells in §98.235(f). Comment 6 provides recommended revisions to 

§98.235(f).

• INGAA has consistently requested reasonable approaches for vent lines that cannot safely be 

measured or are inaccessible (e.g., cannot add a port at a lower elevation). EPA has provided 

the acoustic device method to address some cases, but there are still instances where 

measurement is not possible. For example:

− Vent line access is not safe or feasible to access and acoustic device measurement of the 

relevant valve is not possible. Some valves are buried and not accessible unless exhumed; 

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other valves may include insulation or have other accessibility problems that eliminate the 

acoustic method as an option.

− Vent line is not safe or feasible to access (e.g., wet seal degassing vent) and valve leakage 

measurement (i.e., acoustic method) is not applicable.

• For "missing" vent measurements, §98.235(d) contemplates missing data associated with a 

measured parameter. However, it does not appear to address the situation where an annual 

measurement is not completed, such as a vent line where measurement is not feasible. This 

implies that §98.235(g) would need to apply for missing vent measurements.

− It is not clear if §98.235(g) is intended to include missing compressor vent measurements. 

Comment 6 recommends revisions to §98.235(g) to clarify applicability. Alternatively and as 

discussed above, a provision similar to §98.235(b) could be added to address compressor 

vents in a similar manner as tank vents.

− Missing data provisions must apply for scenarios when vent measurement is not feasible. If 

not, INGAA strongly opposes eliminating BAMM. Clarity is needed and can be provided 

through revision to one or more subsections in §98.235.

In addition to or as an alternative to the revisions recommended below for section §98.235(g), 

missed compressor vent and rod packing measurements could be added to the tank monitoring 

provisions in §98.235(b). Or, a similar, separate provision could be added for compressor 

measurements. In this case, the operator should use reporter emission factors to estimate 

emissions for all operating modes for the vent not measured.

Response: The EPA indicated in the preamble to the proposed rule that missing data procedures 

may provide clarity for reporters who may have unintentionally missed collecting required data, 

but the missing data procedures are not intended to replace BAMM. By the 2015 reporting year, 

facilities will have had four years to implement any necessary changes in equipment in order to 

fully comply with subpart W, which we have determined to be sufficient time to make any 

equipment modifications or installations. Furthermore, many of the revisions that we are

finalizing were specifically proposed to address the commenter’s concerns related to BAMM:

• For a late year event (e.g., unexpected blowdown) that results in a facility that has not 

reported becoming newly subject, we are finalizing the missing data provisions in 

proposed §98.235(e). The EPA contends that 6 months is enough time for a newly subject 

facility to begin using the methods required in §98.233. This time period is consistent 

with requirements in the final subpart W rule, in which we previously allowed the use of 

BAMM for the first six months of data collection to allow reporters newly subject to 

subpart W to comply. We are also broadening proposed missing data provisions in

§98.235(f) to consider new “sources” rather than “wells” as suggested by the commenter.

• The EPA has revised the proposed missing data procedures to provide more general 

procedures for emission sources that are measured quarterly or more often and for 

emission sources with annual measurement requirements. Thus, the missing data 

provisions now cover a wider range of measurements than initially proposed. See Section 

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II.C of the preamble to the final rule for further discussion regarding the missing data 

procedures in the final rule 

• With respect to vent lines that cannot safely be measured or are inaccessible, we are 

finalizing many of the proposed revisions that will allow for the testing of these 

compressor vents without the use of BAMM. For example, we are clarifying that 

operators do not have to shut a facility down for the sole purpose to test a compressor in 

its non-operating mode, but that the measurement must be made at the next scheduled 

shutdown that requires a compressor to be taken off-line for planned or scheduled 

maintenance. We have provided for reporters to conduct a single annual as found 

measurement for manifolded compressors routed to a common vent, in lieu of a 

measurement for each individual compressor manifolded to the common vent. We are 

also allowing the use of optical gas imaging equipment for pre-screening of emissions 

from blowdown valves on compressors in operating-mode or standby-pressurized-mode 

and for isolation valves on compressors in not-operating-depressurized-mode. If no 

emissions are observed, then the measurement value of zero may be used and no further 

measurement is required. The option to use optical gas imaging equipment to screen for 

emissions, in addition to the current allowance for use of acoustic measurement devices, 

eases the burden on facilities with inaccessible or unsafe-to-measure vents. Finally, for 

compressors routed to a flare, we are finalizing provisions to allow operators to calculate 

and report emissions with other flare emissions. In this case, reporters are no longer 

required to sample compressors routed to a flare individually. The revisions in this final 

rule resolve the technical and safety issues for which BAMM has been used in previous 

years. See Section II.B.11 of the preamble to the final rule for additional information. 

Even though many of the proposed revisions that we are finalizing were intended to eliminate 

the need for BAMM, we have determined that there are certain data elements in the newly 

proposed calculation methods for which measurement systems may not be available. We are, 

therefore, finalizing several revisions to the BAMM requirements to allow the short-term 

transitional use of BAMM for reporters subject to these new requirements (e.g., for well 

venting for liquids unloading, for well completions and workovers, or for vents from 

manifolded compressors). See Section II.D.2 of the preamble to the final rule for a discussion 

of these changes. 

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 18

Comment: In the event that EPA nevertheless moves forward with the elimination of BAMM, 

Kinder Morgan strongly urges EPA to ensure that Subpart W’s missing data provisions apply to 

sources and cover case-specific monitoring circumstances for which EPA has previously 

reviewed and approved BAMM requests. Such case-specific circumstances include, but are not 

limited to, equipment and piping configurations that cannot be easily modified without incurring 

significant expense and operational delays; unsafe access to compressor, tank and other 

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equipment vents for which Subpart W requires measurement; and data gaps associated with 

downtime and malfunctions of continuous meters, including continuous flow meters. Unlike 

most other industries subject to the GHGRP, Kinder Morgan and other natural gas industry 

operators are required to conduct actual physical measurements of their equipment components.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 11 in this 

section.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 66

Comment: It is not clear if revisions to the missing data section are intended to balance the 

elimination of BAMM. Requirements for GHG estimates should provide flexibility for 

calculations, input parameters, and measurement methods based on defined data quality 

objectives and consistent application of those objectives across source types, segments, and 

industries.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 11 in this 

section.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 2

Comment: Elimination of the BAMM provisions will compromise the ability of Reporters to 

comply unless Missing Data provisions broadly address alternative approaches. In the Proposed 

Rule, the BAMM provisions are deleted and the Missing Data Provisions are significantly 

revised. Consequently, what is left of the Missing Data Provisions will be needed to address all 

BAMM requests previously approved by EPA, and to broadly cover unforeseen future 

circumstances. For example, the revised Missing Data Provisions would have to be utilized when 

measuring emissions from compressor vent lines that cannot be safely accessed (e.g. vent lines 

that are elevated above high pressure pipelines and are not safe to access) or are technically 

infeasible to measure. Doing so may likely result in a level of measurement precision and 

accuracy that is less than ideal.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 11 in this 

section.

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Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 47

Comment: INGAA supports revisions to §98.235 (Missing Data). It is imperative that this 

section provides access to alternatives for measurement and monitoring. 

INGAA supports proposed revisions to §98.235 that address facility-level, source-level, and 

measurement and method circumstances that may result in missing data. As discussed in 

Comments 3 through 6 above, it is imperative that Subpart W include provisions that provide 

operators the ability to address unforeseen scenarios and measurement challenges. INGAA 

recommends clarifying revisions to §98.235 in Comment 6. With those revisions and with 

preamble or support document discussion to clarify potential implementation questions, INGAA 

supports the revisions to Missing Data provisions.

Response: The EPA thanks the commenter for their support of the proposed revisions to 

§98.235. See Section II.C of the preamble to the final rule for additional discussion regarding the 

missing data procedures in the final rule.

Commenter Name: Ritu Talwar

Commenter Affiliation: Spectra Energy Corp

Document Control Number: EPA-HQ-OAR-2011-0512-0079-A1

Comment Excerpt Number: 6

Comment: EPA should clarify its definition of Missing Data to allow operators to utilize 

alternative methodologies to comply with reporting requirements. It is imperative that EPA 

address all scenarios that have been addressed from 2011 through 2014 using BAMM requests.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 11 in this 

section.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 11

Comment: The revised missing data procedures should not be promulgated as proposed. 

Related to EPA’s proposed elimination of BAMM, EPA proposes to extensively modify the 

missing data procedures in §98.235. As proposed, the missing data procedures are confusing, 

unnecessarily burdensome, and not sufficient to provide the flexibility needed to enable 

compliance by the regulated industry. 

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Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 11 in this 

section.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 9

Comment: Should BAMM be phased-out, then reporters should be provided an alternate means 

of reporting data that cannot be safely or feasibly collected. EPA has communicated its intention 

to use the amended missing data procedures section in 40 CFR 98.235 as a replacement for 

BAMM.

While Williams agrees with this approach, we believe the amended missing data section lacks 

clarity. In 40 CFR 98.235(g), EPA should clearly communicate to reporters that data may be 

substituted for venting measurements that are not collected due to safety concerns or 

inaccessibility.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 11 in this 

section.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 1

Comment: SoCal Gas supports the proposed revisions to the Missing Data Provisions in 

§98.235 that address facility- and source-level measurement and data collection circumstances 

which may result in missing data. If Best Available Monitoring Methods (BAMM) provisions in 

§98.234(f) are removed from Subpart W, however, then it becomes imperative that Subpart W 

include missing data provisions which would enable operators to address unforeseen data 

collection complications and measurement challenges.

Why is access to alternative methods and procedures for collecting data so essential and must be 

provided for Subpart W? Compliance with air quality regulations, including those that regulate 

criteria or hazardous air pollutants (e.g., NSPS and NESHAP), necessarily requires 

measurement, testing, or monitoring methods to demonstrate compliance. Sometimes, however, 

alternative measurement or monitoring procedures are needed, especially when circumstances 

beyond a facility's reasonable control prevent utilization of the standard measurement or 

monitoring methods. In the case of Subpart W, the Best Available Monitoring Methods 

(BAMM) in §98.234(f) provide access to alternatives for Subpart W measurements and other 

data collection requirements.

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Response: The EPA thanks the commenter for their support of the proposed revisions to 

§98.235. See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpt 11 of this 

section.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 81

Comment: API is seriously concerned with the provision in §98.235(h) which directs the 

reporter to §98.236(bb) that requires reporting of information for “all measured and substitute 

values of a parameter, and the procedures used to substitute an unavailable value of a parameter 

per the requirements in §98.236(bb).” In turn, the provisions of §98.236(bb) requires reporters to

report information that API views as inappropriate for a GHG reporting program and that

constitutes overreach by EPA. In particular API objects to the following provisions of

§98.236(bb):

• Provisions that require reporting of all information for “each individual missing data value 

used in a calculation”; that prohibit “Aggregation of missing data values within a component, 

well, sub-basin, or basin” and that require reporting all information items for each temporal 

instance separately “If missing data is substituted for the same parameter in non-consecutive 

periods during the calendar year, the information in paragraphs (bb)(1) through (bb)(5) in this 

section should be reported for each period separately.” This constitutes an inefficient set of 

requirements that creates unneeded burden on reporters.

Response: After considering the proposed reporting requirements in light of the comments 

received and the reporting provisions in other subparts, we determined that revisions were

needed to the proposed missing data reporting requirements. In this final rule, we are requiring 

reporting of the use of missing data procedures according to the general provision requirements 

in §98.3(c)(8), except we are providing for the reporting of number times missing data 

procedures were used for an element that is not based on continuously monitored parameters. 

See Section II.C of the preamble to the final rule further discussion on the missing data reporting 

requirements.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 82

Comment: API specifically objects to the following information items required in §98.236:

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98.236 (bb) (3): The description of the unique or unusual circumstance that led to missing data 

use, including information on any equipment or components involved and any procedures that 

were not followed.

98.236 (bb) (5) The description of how the owner or operator will avoid the use of missing data 

in the future, such as mitigation strategies or changes to standard operating procedures.

API views both of these provisions to be beyond any reasonable requirements for a GHG

reporting program, a clear overreach of EPA’s authority, of no use to EPA or the reporter, and a

substantial additional burden that is not warranted. API suggests the following modifications to

the language in 98.236 (bb) to address these concerns.

(bb) For any missing data procedures used, report the information in paragraphs (bb)(1) through 

(bb)(5) in this section for each individual missing data value used in a calculation. Aggregation 

of missing data values within a component, well, sub-basin, or basin is not acceptable. If missing 

data is substituted for the same parameter in nonconsecutive periods during the calendar year, the 

information in paragraphs (bb)(1) through (bb)(5) in this section should be reported for each 

period separately.

(1) The date(s) the missing data is used.

(2) The equation(s) in which the missing data is used.

(3) The description of the unique or unusual circumstance that led to missing data use, including 

information on any equipment or components involved and any procedures that were not 

followed.

(4) The description of the procedures used to substitute an unavailable value of a parameter.

(5) The description of how the owner or operator will avoid the use of missing data in the future, 

such as mitigation strategies or changes to standard operating procedures.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 81 of this 

section. 

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 143

Comment: Proposed Citation Reference: §98.236(bb), and (bb)(1), Proposed Rule Text:(bb) 

For any missing data procedures used, report the information in paragraphs (1) through (5) in this 

section for each individual missing data value used in a calculation. Aggregation of missing data 

values within a component, well, sub-basin, or basin is not acceptable. If missing data is 

substituted for the same parameter in non-consecutive periods during the calendar year, the 

information in paragraphs (1) through (5) in this section should be reported for each period 

separately. (1) The date(s) the missing data is used.

API urges EPA to remove the phrase “Aggregation of missing data values within a component, 

well, sub-basin, or basin is not acceptable. If missing data is substituted for the same parameter 

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in non-consecutive periods during the calendar year, the information in paragraphs (1) through 

(5) in this section should be reported for each period separately.” API objects to these provisions.

Response: After considering the proposed reporting requirements in light of the comments 

received and the reporting provisions in other subparts, we have significantly revised the 

proposed missing data reporting requirements. In this final rule, we are requiring reporting of the 

use of missing data procedures following the general provision requirements in §98.3(c)(8). In 

the final rule, the reporter is required to identify each data element for which a missing data 

procedure was used and the number times missing data procedures were used for that element. 

Depending on the data element, this may include reporting at the emission unit level without 

aggregation within a well, sub-basin, or basin. However, the detailed information proposed to be 

reported at §98.236(bb)(1) through (5) are not being finalized. See Section II.C of the preamble 

to the final rule further discussion on the missing data reporting requirements.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 144

Comment: Proposed Citation Reference:§98.236(bb)(3), and (bb)(1), Proposed Rule Text: The 

description of the unique or unusual circumstance that led to missing data use, including 

information on any equipment or components involved and any procedures that were not 

followed.

API views this requirement to be beyond any reasonable requirements for a GHG reporting 

program, a clear overreach of EPA’s authority, of no use to EPA or the reporter, and a substantial 

additional burden that is not warranted. EPA should remove this requirement from the final rule.

Response: The EPA is not finalizing the detailed information proposed to be reported at 

§98.236(bb)(1) through (5). See Section II.C of the preamble to the final rule further discussion 

on the missing data reporting requirements.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 145

Comment: Proposed Citation Reference:§98.236(bb)(5), Proposed Rule Text: The description 

of how the owner or operator will avoid the use of

missing data in the future, such as mitigation strategies or changes to standard operating 

procedures.

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API views this requirement to be beyond any reasonable requirements for a GHG reporting 

program, a clear overreach of EPA’s authority, of no use to EPA or the reporter, and a substantial 

additional burden that is not warranted. EPA should remove this requirement from the final rule.

Response: The EPA is not finalizing the detailed information proposed to be reported at 

§98.236(bb)(1) through (5). See Section II.C of the preamble to the final rule further discussion 

on the missing data reporting requirements.

Commenter Name: Carrie B. Crumpton

Commenter Affiliation: CONSOL Energy, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0080-A1

Comment Excerpt Number: 10

Comment: The rule itself incorporates data collection and reporting requirements that go 

beyond the requirements of a reporting program. This includes:

• Reporting a description of how the owner or operator will avoid the use of missing data in 

the future for each missing data value used in a calculation.

• Reporting the description of the unique or unusual circumstance that led to missing data use.

• Including information on any equipment or components involved and any procedures that 

were not followed for each missing data value used in a calculation.

Response: The EPA is not finalizing the detailed information proposed to be reported at 

§98.236(bb)(1) through (5). See Section II.C of the preamble to the final rule further discussion 

on the missing data reporting requirements.

Commenter Name: V. Bruce Thompson

Commenter Affiliation: American Exploration & Production Council (AXPC)

Document Control Number: EPA-HQ-OAR-2011-0512-0085-A2

Comment Excerpt Number: 5

Comment: AXPC and the Alliance believe that the missing data provisions which were added 

to the proposed rule are unreasonable to comply with. Reporters under this rule have hundreds of 

thousands to millions of data points to gather and now report to comply with this rule. Given the 

sheer volume of information and inherent imperfection in data collection and storage systems 

there will always be a number of individual data elements that are going to be unavailable for 

some portion of time during the year. As such, it would be infeasible if not impossible to track 

and report on each missing data element to the level of detail that EPA is proposing. While we 

do not object to reporting on the occurrence, dates, and data substitution methods employed we 

believe that doing this individually for each occurrence is unnecessarily burdensome. Generally, 

the same type of inadvertent and unavoidable data collection issues will affect several data 

elements and instances and it would be extremely time consuming and unbeneficial to have to 

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report this level of detail. We also believe that these data collection errors and occasional failures 

are unavoidable and object to the requirement to explain the unique circumstances that led to the 

missing data and the steps the operator will take to avoid future missing data. Examples of 

unavoidable data gathering errors and failures include loss of radio communication of a SCADA 

system, loss of electricity, and data collection system wires losing contact due to natural 

conditions such as wind, precipitation, animal contact, heat, cold, or equipment vibration. In 

order to resolve this issue AXPC and the Alliance urge EPA to remove the requirement to report 

on individual missing data instances in §98.236(bb) and the specific requirements in 

§98.236(bb)(3) and (5).

Response: The EPA is not finalizing the detailed information proposed to be reported at 

§98.236(bb)(1) through (5). See Section II.C of the preamble to the final rule further discussion 

on the missing data reporting requirements.

19.2 Provisions for newly acquired wells or sources

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 12

Comment: §98.235(f) should be revised to address all Subpart W sources and segments.

§98.235(f) addresses a situation where a change (i.e., new well) occurs at a facility already 

subject to Subpart W and allows best engineering estimates in lieu of measured data for six 

months. INGAA strongly supports the concept addressed by §98.235(f), where a change at an 

affected facility is allowed to use best estimates for an abbreviated period. However, similar 

complications can arise for sources other than wells, and this section should be broadly 

applicable to all Subpart W affected segments and source types that are required to report. There 

are many scenarios where additions to an affected facility could result in complications similar to 

the well scenario addressed in the Proposed Rule.

For example, compressors are a listed source type for T&S operations. A new compressor (i.e., 

additional or replacement capacity) could be added at a compressor station that reports under 

Subpart W. Since pipeline demand typically increases over the winter months, new capacity may 

be brought on-line late in the year to accommodate the heating season. In this scenario, it may be 

difficult and overly burdensome to require measurements from newly commissioned equipment, 

and the logistics associated with scheduling and conducting a test do not warrant this level of 

effort for the minimal operation that would occur within the calendar year. In this scenario, 

§98.235(f) should apply and the operator would likely use reporter emissions factors for 

emission estimates from the new compressor. Many similar scenarios can be envisioned for 

facilities already subject to Subpart W.

To address changes that occur at existing facilities already subject to GHGRP reporting, 

§98.235(f) should be revised to accommodate all segments. INGAA recommends the following 

revision:

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(f) For the first six months of required data collection, facilities that are currently subject to 

subpart W and that acquire a new source(s) listed in §98.232 may use best engineering estimates 

for any data related to those newly acquired sources that cannot reasonably be measured or 

obtained according to the requirements of this subpart.

Response: The EPA agrees with the commenter and we have expanded the provisions in

§98.235(f) in the final rule to account for scenarios in which facilities have acquired new sources 

(rather than new well) from another facility that were not previously subject to subpart W. See 

Section II.C.2 of the preamble to the final rule for additional discussion responding to these 

concerns. 

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 79

Comment: API contends that §98.235(f) should be applicable to newly acquired wells whether 

or not they were subject to Subpart W previously. Upon acquisition of new production 

operations companies need sufficient time to merge the data collection and reporting systems to 

ensure that the integrated data can undergo the required QA/QC and be certified for reporting. 

API suggests the following changes to §98.235(f):

• (f) For the first six months of required data collection, facilities that are currently subject to 

this subpart W and that acquire new wells that were not previously subject to this subpart W

may use best engineering estimates for any data related to those newly acquired wells that 

cannot reasonably be measured or obtained according to the requirements of this subpart.

Response: The EPA disagrees that §98.235(f) should be extended to new wells acquired from 

other companies that were previously subject to subpart W. Sources that were previously subject 

to subpart W should have the necessary sampling ports or monitoring equipment needed to 

comply with the measurement requirements in the rule. See Section II.C.2 of the preamble to the 

final rule for additional discussion responding to this comment.

Commenter Name: Darrell R. Johnson

Commenter Affiliation: Southern California Gas Company (SoCal Gas)

Document Control Number: EPA-HQ-OAR-2011-0512-0086-A2

Comment Excerpt Number: 4

Comment: §98.235(f) should be revised to address all Subpart W sources and segments, and 

cover both new and newly acquired equipment and operations. §98.235(f) addresses a situation 

where a specific change (i.e., new well) occurs at an onshore production facility already subject 

to Subpart Wand allows best engineering estimates for any associated data that cannot 

reasonably be measured or obtained for the first six months. SoCal Gas strongly supports the 

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concept addressed by §98.235(f) where an affected facility is allowed to use best estimates for an 

abbreviated period after a change. However, complications associated with new equipment and 

operations are not limited to wells, therefore this section should be revised broadly apply to all 

Subpart W segments and emission sources that are required to report. There are numerous 

circumstances where new equipment and operations at an affected facility could result in 

complications similar to the well scenario in the Proposed Rule.

For example, centrifugal and reciprocating compressors are listed source types for transmission 

and storage operations. As natural gas demand typically increases over the winter months, new 

compression capacity may be brought on-line late in the year at a transmission or storage facility 

subject to Subpart W. Under these circumstances, it would be difficult and overly burdensome to 

require vent measurements from newly installed compressors. The logistics and the level of 

effort associated with scheduling and conducting a test are difficult to justify for the abbreviated 

operation that would occur towards the end of the calendar year. §98.235(f) therefore should 

apply and the operator should be allowed to use reporter emissions factors as best engineering 

estimates of emissions from the new compressor. Many similar situations can be envisioned for 

facilities already subject to Subpart W.

In addition, this provision should apply to any newly acquired emission source, regardless of 

whether or not the source was previously subject to Subpart W. A similar level of effort is 

needed to integrate newly developed and newly acquired equipment and operations into an 

existing reporting program. Further, obtaining all the acquired source data from the previous 

owner can take time, and depending on the source acquisition timing, may not be available by 

the reporting due date.

To address changes that occur at existing facilities already subject to GHGRP reporting 

requirements, §98.235(f) should be revised to accommodate all sources and segments and to 

cover both new and newly acquired equipment. SoCal Gas recommends the following revision:

"For the first six months of required data collection, facilities that are currently subject to subpart 

Wand that acquire a new source(s) listed in §98.232 wells that were not previously subject to 

subpart W may use best engineering estimates for any data related to those newly acquired 

sources that cannot reasonably be measured or obtained according to the requirements of this 

subpart."

Response: The EPA agrees with the commenter and we have expanded these provisions in 

§98.235(f) in the final rule to account for scenarios in which facilities have acquired new sources 

from another facility that were not previously subject to subpart W. The EPA disagrees that 

§98.235(f) should be extended to newly installed sources or sources acquired from other 

companies that were previously subject to subpart W. See Section II.C.2 of the preamble to the 

final rule for additional discussion responding to these concerns. 

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20.0 Best Available Monitoring Methods

20.1 Removal of BAMM requirements for 2015 and beyond

Commenter Name: Brian Korpics

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2011-0512-0087-A2

Comment Excerpt Number: 1

Comment: When EPA finalized Subpart W in November 2010, the Agency limited BAMM to 

situations in which regulated facilities were unable to install the proper monitoring equipment.2

These provisions allowed specific facilities to use BAMM until June 30, 2011, and any facilities 

requesting BAMM beyond that date were required to submit a written petition to EPA requesting 

an extension.3 Importantly, no facility could request an extension beyond December 31, 2011, 

except “under extreme and unique circumstances, which include safety, or a requirement being 

technically infeasible or counter to other local, State or Federal regulations.”4 Further, the 

facilities authorized to use BAMM were strictly limited to gas well workovers using hydraulic 

fracturing, gas well completions using hydraulic fracturing, and well testing and flaring.5

Despite this intended provisional nature of the program, EPA expanded the availability of 

BAMM in subsequent revisions to Subpart W in September 2011.6 These revisions allowed a 

presumptive extension of BAMM for all applicable facilities through December 31, 2011, 

expanded the availability of BAMM to the entire oil and gas sector, and substantially relaxed 

requirements for extending BAMM beyond 2011.7 The changes transformed BAMM from a 

limited, transitional program to a more substantial fixture of Subpart W. Indeed, numerous 

facilities deployed these non-standardized methods in reporting year 2012, during which 44 

percent of onshore production facilities and 46 percent of natural gas transmission facilities 

utilized BAMM.8 This widespread use of BAMM has created some difficulties in comparing 

data across facilities and understanding discrepancies between Subpart W and other GHG 

inventories and measurement studies.

Given these concerns, we strongly support EPA’s proposal to eliminate all BAMM provisions in 

40 C.F.R. § 98.234 by January 1, 2015.9 The proposed rule recognizes that the oil and gas sector 

is the only industry-specific subpart of the Reporting Rule that continues to permit the use of 

BAMM.10 Moreover, eliminating BAMM will strengthen Subpart W reporting and help to 

promote data accuracy and comparability across facilities.

In proposing to phase out BAMM, the Agency has demonstrated that BAMM is no longer 

needed by closely examining past BAMM requests11 and providing workable, standardized 

pathways to help ensure compliance. In particular, the proposal creates additional, standardized 

reporting methods for sources that frequently requested BAMM, including centrifugal 

compressors, reciprocating compressors, blowdown vent stacks, and combustion emissions. The 

proposed rule also expands the missing data procedures and provides a compliance pathway for 

facilities that become subject to Subpart W in the future.12 For example, for newly acquired 

wells, the proposed rule allows the use of best engineering estimates for any parameter that 

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cannot be reasonably measured or obtained for up to six months from the first date of Subpart W 

applicability.13

EPA requested comments and rigorous technical evidence on specific contexts where operators 

believe unique and unusual circumstances would require the use of BAMM after its proposed 

elimination on January 1, 2015. In the event narrow circumstances exist where operators require 

even more flexible measurement methodologies than the ones EPA has proposed, such as to 

ensure worker safety, these flexibilities should be incorporated through a rulemaking effort 

rather than ongoing BAMM requests.

Footnotes:

2 75 Fed. Reg. 74,458, 74,471 (Nov. 30, 2010).

3 Id.

4 Id.

5 Id.

6 76 Fed. Reg. 59,533, 59,536–38 (Sept. 27, 2011).

7 Id. EPA modified the original rule’s language governing extension of BAMM past 2011 except 

under “extreme and unique circumstances,” and replaced it with considerably broader language, 

which permitted extensions under “unique or unusual circumstances such as data collection 

methods that do not meet safety, technical, or legal issues rendering them unable to meet the 

requirements of Subpart W.”

8 EPA, Petroleum and Natural Gas Systems 2012 Data Summary 17 (Oct. 2013), available at 

http://www.epa.gov/ghgreporting/documents/pdf/2013/documents/SubpartW-2012-DataSummary.pdf.

9 79 Fed. Reg. at 13,404–05.

10 Id. at 13,405.

11 Id. at 13,404.

12 Id.

13 Id.

Response: The EPA thanks the commenter for their support. See Section II.D of the preamble to 

the final rule for the EPA’s decision to remove existing BAMM provisions and to provide for 

short-term transitional BAMM in 2015 for reporters that may need to obtain the necessary 

equipment to conduct measurements as required under the revised calculation methods in the 

final rule.

Commenter Name: Pamela Lacey

Commenter Affiliation: American Gas Association (AGA)

Document Control Number: EPA-HQ-OAR-2011-0512-0083-A1

Comment Excerpt Number: 5

Comment: EPA has requested comment on its proposal to remove the provisions in 40 C.F.R. 

section 98.234(g) that allowed the optional use of BAMM in unique or unusual circumstances. 

98 Fed. Reg. at 13,404. BAMM was a helpful safety valve at the start of the Subpart W reporting 

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program. It allowed reporters to cope with situations that did not fit neatly into the regulatory 

framework or that were not clearly addressed in the rule. AGA believes that with the 

clarifications EPA has proposed for reporting emissions from natural gas distribution facilities, 

together with the minor clarifications we request in these comments, there should be no further 

need to use BAMM to report greenhouse gas emissions after January 1, 2015 from natural gas 

distribution facilities.

Response: The EPA thanks the commenter for their support. See Section II.D of the preamble to 

the final rule for the EPA’s decision regarding the removal of existing BAMM provisions and to 

provide for short-term transitional BAMM in 2015 for facilities that may need to obtain the 

necessary equipment to conduct measurements as required under the revised calculation methods 

in the final rule.

Commenter Name: Kathleen McNeil

Commenter Affiliation:

Document Control Number: EPA-HQ-OAR-2011-0512-0069

Comment Excerpt Number: 1

Comment: I am writing in support of the proposal to remove the Best Available Monitoring 

Methods (“BAMM”) from Subpart W of the Greenhouse Gas (GHG) Reporting Rule (40 CFR 

98). Replacing BAMM standards with explicit reporting requirements for petroleum and natural 

gas systems to comply with greenhouse gas rules will reduce transaction costs and improve 

compliance. Common criticisms of “best available” practices currently apply to the reporting 

rule, including the industry’s reliance on practices that are merely “good enough” or that do not 

work for certain situations. The reporting under BAMM standards have caused many problems, 

including missing data. Removing BAMM standards will greatly enhance the quality of the 

reporting, and importantly will greatly enhance the consistency of the reporting. The proposed 

amendment that will allow the optional use of BAMM in certain circumstances for one reporting 

year is a fair compromise for companies to achieve the reporting necessary to meet the proposed 

standards. Increasing consistency will reduce transaction costs for reporting companies and 

garner more confidence in the Greenhouse Gas Reporting Program.

The EPA’s Greenhouse Gas Reporting Program is a vital educational tool for making policy, 

business, and regulatory decisions. Mandatory “reporting pushes companies to be more 

disciplined about their environmental performance, which, in turn, reduces their environmental 

risk.” The reporting regimen is critical for businesses to make decisions about their own 

environmental risks, and for government and the public to make decisions about the 

environmental costs that they expect companies, especially those working within the energy 

sector, to undertake.

The Oil & Gas sectors in particular should have stringent obligations to report and internalize the 

costs stemming from their production of greenhouse gases. The United Nations, through its 

climate chief, recently called on the oil & gas industry to transform their production to 

incorporate measures that would reduce carbon output or risk having to leave valuable fuel 

reserves unexplored. This move came in response to leading scientists warning that climate 

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change will have a negative impact on food supplies, economic growth, and the causes of armed 

conflicts. The agreement struck at the 2010 United Nations Climate Change Conference was to 

take action to avoid increasing the average global temperature by 2° Celsius above pre-industrial 

levels; however, temperatures are going in the direction of breaching that ceiling. Despite

encroachment on the upper limits of global temperatures, oil & gas companies assure that they 

are adequately addressing climate change through changes to their technology and extraction 

measures. Disclosure and mandatory reporting requirements are the primary and most important 

tools to ensure that the promises being made to the public are being actually enforced internally 

within the business.

For those reasons, the missing data problem that existed before the proposed amendments to 

Subpart W were unacceptably hindering the public’s and government’s access to vital 

information about what is actually occurring in the oil and gas sector. Because of the recent push 

for oil and gas companies to take increased measures in order to comply with international 

agreements about reducing global temperatures, the need for accurate reporting is stronger than 

ever. To the extent that companies could take advantage of loopholes and confusion emerging 

from the use of BAMM, the information that is crucial to making policy determinations was not 

being accurately reflected. Therefore, the amendments to Subpart W are a needed change to 

make sure that companies are held to the standards they project.

Response: The EPA thanks the commenter for their support. See Section II.D of the preamble to 

the final rule for the EPA’s decision to remove existing BAMM provisions and to provide for 

short-term transitional BAMM in 2015 for reporters that may need to obtain the necessary 

equipment to conduct measurements as required under the revised calculation methods in the 

final rule.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 4

Comment: To date, a number of INGAA comments have been addressed and Subpart W has 

improved significantly since the original 2009 proposal. For example: EPA has added 

measurement method flexibility and additional methods for some applications (but measurement 

methods remain an issue in some cases); EPA added default natural gas methane and CO2 

composition for emission estimates from T&S and other segments downstream of processing; 

and EPA added emission factors for pneumatic device emission estimates. In addition, rule

revisions provided technical corrections (e.g., correcting units and references to standard 

temperature and pressure in various equations) and improved rule clarity in some instances.

However, fundamental issues remain for key T&S sources. Examples include:

• Access to alternative methods is a tenant to regulations, especially when measurement is 

required. Deleting the BAMM section may strand sources that become subject to GHG 

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reporting, where unpredictable future events occur, or where vent measurement is unsafe or 

infeasible.

Response: The EPA is finalizing multiple revisions to the rule that address commenter concerns 

related to BAMM. See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 81 in 

Section 19.1 of this document and Sections II.C and II.D of the preamble to the final rule 

regarding additional discussion responding to this comment. 

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 83

Comment: As an alternative to the proposed byzantine procedures for use of the missing data 

provisions and reporting of information related to the use of missing data, EPA can simply retain 

an ongoing availability of BAMM for those instances where a reporter demonstrates a legitimate

reason and need for such flexibility.

Response: The EPA disagrees with the commenter that BAMM provisions should be provided 

on an ongoing basis. The EPA is finalizing the removal of all prior BAMM provisions. We are

also finalizing multiple revisions to the missing data procedures and reporting requirements. See 

Sections II.C and II.D of the preamble to the final rule regarding additional discussion 

responding to this comment.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 6

Comment: Williams objects to the proposed universal elimination of BAMM. Williams has 

historically used BAMM in cases where required monitoring activities posed a serious safety 

concern, or where such measurement was not possible. In most cases, Williams has employed 

BAMM for compressors with vents routed to flare, or for compressor vents that could not be 

safely accessed. In the absence of BAMM, Williams recommends that EPA revise the Missing 

Data section of Subpart W to allow the reporting of data that cannot be measured for the reasons 

noted above.

Response: The final rule revisions address many of the concerns raised by the commenter (e.g. 

monitoring of compressor vents routed to a flare is no longer required). See response to comment 

EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 81 in Section 19.1 of this document and Sections 

II.C and II.D of the preamble to the final rule regarding additional discussion responding to this 

comment.

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Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 9

Comment: BAMM and Missing Data 

Regulations requiring measurement and monitoring must have access to alternative methods. 

INGAA strongly believes that the measurement requirements unique to Subpart W are integrally 

linked to the need for alternatives within Subpart W that may not be necessary for other GHGRP 

subparts with fewer or more simplistic measurement demands. However, the Proposed Rule 

would eliminate the Best Available Monitoring Methods (BAMM) section8 in its entirety. This 

action may be reasonable if other amendments (i.e., Missing Data revisions in §98.235) address 

the resulting void. As discussed in this comment and the three following comments, Subpart W 

includes more measurement and more complex measurement than other GHGRP subparts, so 

robust and thorough Subpart W missing data provisions are needed if the BAMM section is 

eliminated.

It is common for air quality regulations, such as regulations that address criteria pollutants or 

hazardous air pollutants, to include measurement, testing, or monitoring to verify compliance. 

An integral component of measurement requirements is access to alternative methods. The 

GHGRP includes measurements for some emission estimates, but those are often based on 

processes already in place (e.g., fuel measurement, CEMS for utilities that have existing 

requirements under 40 CFR, part 75). Subpart W requires vent measurement for lines not 

previously measured, for processes and equipment not designed with measurement access 

considered. Following the established standard for air quality regulations, access to alternative 

methods or procedures is integral when measurement is required.

BAMM provisions in §98.234(f) provides access to alternatives for Subpart W measurements, 

and approaches that provide representative alternative data needed to perform Subpart W 

emission estimates.

Examples of access to alternative monitoring, methods, and related QA/QC procedures are 

common in air quality regulations, and are often included in the general provisions. In addition, 

access to alternative emission standards or operating limits is typically provided. Several 

examples follow:

• National Emission Standards for Hazardous Air Pollutants (NESHAPs) in 40 CFR, Part 63 

typically include compliance testing or monitoring and emission standards. Alternative 

options that are available include:

− §63.7 – Performance Testing Requirements: Includes major alternatives to test methods in 

§63.7(e)(2)(ii) and (f);

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− §63.8 – Monitoring Requirements: Includes reference to alternatives throughout, with 

details in §63.8(f);

− §63.6 – Compliance with standards and maintenance requirements: Includes alternative 

emissions and operating limitations in §63.6(g)

− §63.90 includes definitions related to major and minor changes in monitoring, test 

methods, etc. and includes examples of the wide array of alternatives that are accessible to 

sources subject to NESHAPs.

• New Source Performance Standards (NSPS) in 40 CFR, Part 60 typically include compliance 

testing or monitoring to ensure compliance with emission standards. Alternative options that 

are available include:

− §60.8 – Performance Tests: Includes alternatives in §60.8(b);

− §60.13 – Monitoring Requirements: Includes alternatives in §60.13(i) – (j);

• Part 75 addresses Continuous Emission Monitoring Systems (CEMS) for utilities subject to 

the Acid Rain Program and includes Subpart E – Alternative Monitoring Systems.

This list shows that regulations that require compliance with emission limits provide access to 

regulatory alternatives for the emission standard, monitoring, and performance tests. Subpart W 

should include this common regulatory paradigm, especially since the outcome for an inventory 

rule such as Subpart W has less environmental consequence than for an emission standard.

FOOTNOTE:

8 See 40 C.F.R. §98.234(f).

Response: The EPA acknowledges that the provisions of NSPS and NESHAP allow facilities to 

request alternative monitoring and testing methods. However, the NSPS and NESHAP 

provisions typically require that specific monitoring methods be used (e.g. EPA Method 18 for 

gas compositional analysis) and they do not allow facilities to use alternative monitoring and 

testing methods without the method first being approved by the EPA. 

The EPA has provided a great deal of flexibility in the methods allowed in subpart W, such as 

certain provisions that allow the use of standard methods published by consensus-based standard 

organizations and that allow the use of industry standard practice. Given the great flexibility in 

the methods allowed in the rule, the need for alternative monitoring method provisions in the 

GHGRP are not the same as those for the NSPS or NESHAP programs. 

The EPA has previously provided BAMM provisions to allow facilities time to prepare their 

facilities for meeting subpart W requirements. By the 2015 reporting year, facilities will have 

had four years to implement any necessary changes in equipment in order to fully comply with 

subpart W, which we have determined to be sufficient time to make any equipment 

modifications or installations. Additionally, we have made a number of revisions to the rule, 

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such as allowance to monitor manifolded compressors, to address those cases where the use of 

BAMM was most often approved. Therefore, we are removing the prior BAMM requirements in 

§98.234(f) because we have determined that these provisions are no longer necessary to comply 

with the final rule. The EPA has provided multiple options for conducting measurements that 

provide flexibility to reporters, and we have provided for short-term transitional BAMM for 

facilities that may need to obtain the necessary equipment to conduct measurements under the 

revised calculation methods in this final rule. See response to comment EPA-HQ-OAR-2011-

0512-0084-A2, Excerpt 81 in Section 19.1 of this document and Section II.D of the preamble to 

the final rule for additional information responding to this comment. 

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 10

Comment: INGAA has consistently commented that measurement and BAMM are inextricably 

linked. 

INGAA has consistently commented that method flexibility and access to alternative methods is 

important, especially when measurement is required. Safety and access concerns for vent 

measurement have been consistent themes in INGAA comments, along with the fact that some 

measurement challenges cannot feasibly be remedied. Therefore, the alternative (e.g., use of 

emission factors for a small set of lines that cannot be measured) will always be needed for those 

cases. As long as measurement is required in Subpart W, access to alternatives is needed. As 

discussed in Comment 3, regulations commonly provide access to alternative methods, and the 

use of BAMM has served that purpose for Subpart W. Compared to other GHGRP subparts, 

Subpart W requires more measurement, measurement of more lines, and access to existing lines 

that were not designed with measurement in mind. Thus, it is reasonable to retain BAMM 

sections in Subpart W while it may not be necessary for other industrial sectors.

The importance of BAMM is evident by the rulemaking activity that has transpired since the 

original Subpart W final rule was published. Of the ten Subpart W rulemakings noted in 

Comment 1, several have dealt specifically with BAMM specifications and schedules, thus 

demonstrating the importance of BAMM for Subpart W compliance.

INGAA has previously commented that the sunset of BAMM provisions could strand sources 

that subsequently become subject to GHG reporting (i.e., alternatives are not available to address 

initial implementation challenges) or where unpredictable future events occur. INGAA has 

commented that method flexibility is important so that progress (e.g., new technology 

development) is not stymied. INGAA has commented that EPA should consider allowances if 

facility design precludes reasonable access to vent lines or condensate tank vents at a safe 

measurement location, and that criteria for approving alternatives should more fully recognize 

employee safety. These issues have been expressed repeatedly in INGAA written comments, in 

meetings, and in other communications with EPA.

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The thousands of measurements completed in 2011 – 2013 confirm the commitment of INGAA 

members to completing measurements when feasible. In addition, the number of BAMM 

requests related to compressor vent measurement demonstrate that access to alternatives is 

imperative. In the current Subpart W rule, allowances for missing data are limited in scope, but 

revisions to §98.235 will likely address many scenarios previously covered by use of BAMM. 

However, it is not clear if those revisions comprehensively address scenarios evident based on 

implementation (and BAMM requests) to date. It is imperative that alternatives are available 

when measurement is required – whether via BAMM provisions (the current rule approach) or 

via missing data provisions (the apparent approach in the Proposed Rule).

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 81 in 

Section 19.1 of this document, response to comment EPA-HQ-OAR-2011-0512-0081-A1, 

Excerpt 9 in this Section 19.1 and Sections II.C and II.D of the preamble to the final rule for 

additional discussion responding to this comment.

Commenter Name: Ritu Talwar

Commenter Affiliation: Spectra Energy Corp

Document Control Number: EPA-HQ-OAR-2011-0512-0079-A1

Comment Excerpt Number: 1

Comment: If BAMM is eliminated from Subpart W, missing data must be robust enough to 

account for measurement, equipment and new asset exceptions.

EPA has acknowledged in prior rulemaking the importance of BAMM for Subpart W 

compliance, which allows alternative measurement methods for sources subject to the 

Greenhouse Gas Reporting Rule. By eliminating BAMM the Proposed Rule will compromise 

compliance of impacted sources, specifically in instances when it is not reasonably feasible to 

obtain a required measurement or where direct measurement may be unsafe.

BAMM was designed to ensure data quality and relieve unnecessary cost burdens while 

providing emission estimates. In other regulatory programs, EPA has elected to allow alternative 

compliance and monitoring methods. For example, New Source Performance Standards (NSPS) 

include alternative options for compliance and monitoring. BAMM serves that role for Subpart 

W. Spectra Energy uses BAMM in a limited, focused way, primarily to reduce safety risks 

associated with measurement in certain circumstances but also to provide information not 

otherwise available, such as information from buried valves. Access to vent lines for 

measurement and other measurement challenges that cannot be feasibly remedied are situations 

that require and will continue to require alternatives.

It is overly simplistic and unrealistic to assume that by eliminating BAMM the Agency will have 

a more complete and improved greenhouse gas emissions estimate. However, should EPA 

ultimately decide to eliminate BAMM, a replacement for BAMM is required.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 81 in 

Section 19.1 of this document, response to comment EPA-HQ-OAR-2011-0512-0081-A1, 

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Excerpt 9 in this Section 19.1 and Sections II.C and II.D of the preamble to the final rule for 

additional discussion responding to this comment.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 5

Comment: Kinder Morgan supports INGAA’s comments opposing the removal of Best 

Available Monitoring Method (BAMM) as unwarranted at this time.

In the Proposed Rule, EPA states that removing BAMM "would not add to previous burden 

estimates for subpart W reporters."6 For this to be true with respect to the natural gas sector’s 

Subpart W reporting obligations, modifications to the missing data provisions are necessary.

FOOTNOTE:

6 Proposed Rule at 13420.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 81 in 

Section 19.1 of this document and Sections II.C and II.D of the preamble to the final rule for 

additional discussion responding to this comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 50

Comment: Need for BAMM: EPA requests comments on the circumstances that would require 

BAMM after January 1, 2015. As discussed in Comments 3 through 6, it appears that revisions 

to the Missing Data section address scenarios that have required BAMM or could require 

BAMM in the future. INGAA requests clarifications and revisions to missing data provisions in 

those comments. Dependent upon that outcome, some longstanding issues that have required 

BAMM could remain. In some cases, the scenario is not necessarily "unique or unusual," 

depending on how those terms are viewed. Example scenarios include: vent lines that are unsafe 

to access or infeasible to measure and do not have the ability to assess through-valve leakage 

with an acoustic device; operating modes that are rarely employed (e.g., centrifugal compressor 

standard practice is to remain in standby mode) but nevertheless require measurement in 

shutdown, de-pressurized mode; and, subject T&S facilities where a late year addition of a new 

source at the facility precludes the ability to gather data (e.g., complete vent measurements). 

These are a few examples and INGAA has commented at length on BAMM scenarios in 

previous comments (referenced in Comment 1) which can be reviewed for more detail. In 

addition, BAMM scenarios have been discussed many times with EPA. Those circumstances and 

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examples have not changed. Therefore, inclusion of BAMM or an equivalent alternative in 

Subpart W (e.g., to address access to alternative methods) is imperative.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 81 in 

Section 19.1 of this document and Sections II.C and II.D of the preamble to the final rule for 

additional discussion responding to this comment.

Commenter Name: Pamela Faggert

Commenter Affiliation: Dominion Resources Services, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0073-A1

Comment Excerpt Number: 9

Comment: Best Available Monitoring Methods (BAMM) and Missing Data: The proposed rule, 

if finalized, will remove the Best Available Monitoring and Measurement (BAMM) provisions 

of the rule, effective for the 2015 reporting year. BAMM allows companies to use Best 

Engineering Knowledge and Calculations to estimate emissions from sources that are unsafe or 

inaccessible to measure directly. Future changes in operation or addition of equipment to existing 

facilities may cause them to exceed the MRR reporting threshold and could result in a 

circumstance where existing emission points do not meet the Subpart W criteria. This situation 

would not necessarily be known until the facility was surveyed and may not allow enough time 

to resolve the situation before the monitoring deadline. Therefore, BAMM, or a replacement 

policy mechanism, such as a robust missing data provision (discussed below), is needed in the 

final rule because changes to existing facilities may cause the facility as a whole to exceed the 

threshold for Subpart W reporting (25,000 tons per year of CO2e).

Response: The EPA has provided missing data provisions to address changes in operation or 

addition of equipment to existing facilities that may cause them to become subject to subpart W. 

Specifically, the final provisions in §98.235(d) provide for facilities that become newly subject 

to this subpart W. These facilities may use best engineering estimates for any data that cannot 

reasonably be measured or obtained according to the requirements of the rule. Additionally, 

§98.235(e) provides for facilities that are currently subject to subpart W and that acquire new 

sources from another facility that were not previously subject to this subpart W. See Section II.C 

of the preamble to the final rule for additional information.

Commenter Name: Kelly Guertin

Commenter Affiliation: DTE Energy

Document Control Number: EPA-HQ-OAR-2011-0512-0076-A1

Comment Excerpt Number: 1

Comment: Access to alternative methodologies is imperative through Missing Data or BAMM 

provisions. Eliminating Best Available Monitoring Method (BAMM) alternatives compromises 

the ability of affected sources to comply, especially where annual measurement may be 

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precluded due to safety or operational concerns. DTE presumes that proposed revisions to the 

Missing Data provisions address, in its entirety, the significant void caused by eliminating 

BAMM. DTE recommends revisions to the Missing Data section to achieve this objective. DTE 

currently uses the BAMM provisions in order to eliminate safety concerns that come with 

obtaining measurements from specific sources of leaking and/or fugitive emissions including 

those from blowdown valves from compressor engines.

Response: As noted in the preamble to the proposed rule, the missing data procedures are not 

intended to replace BAMM. The EPA understands the safety and inaccessibility concerns raised 

by commenters, and we are finalizing many provisions to the monitoring requirements for 

compressors to address these concerns. These revisions include provisions to monitor manifolded 

compressor systems, provisions to use continuous flow monitoring systems, allowance to use an 

acoustic leak detection device for blowdown valve leakage measurement, and provisions to use 

optical gas imaging equipment for compressor vent screening. See response to comment EPAHQ-OAR-2011-0512-0084-A2, Excerpt 81 in Section 19.1 of this document and Sections

II.B.11, II.C and II.D of the preamble to the final rule for additional discussion responding to this 

comment.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 25

Comment: When discussing the removal of the BAMM provisions for measuring compressor 

emissions, the TSD only addresses sampling from manifolded vents and fails to address unsafe 

to access and technically infeasible vent measurements for both individual and manifolded 

compressor sources. These are the primary issues requiring both historical and continued use of 

BAMM provisions.

Response: By the 2015 reporting year, facilities will have had four years to implement any 

necessary changes in equipment in order to fully comply with subpart W in a safe manner, which 

we have determined to be sufficient time to make any equipment modifications or installations. 

We are providing short-term provisional BAMM in 2015 for reporters that may need to obtain 

the necessary equipment to conduct measurements as required under the revised calculation 

methods in the final rule, including manifolded compressors. See response to comment EPAHQ-OAR-2011-0512-0084-A2, Excerpt 81 in Section 19.1 of this document and Sections II.C 

and II.D of the preamble to the final rule for additional discussion responding to this comment.

Commenter Name: Carrie B. Crumpton

Commenter Affiliation: CONSOL Energy, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0080-A1

Comment Excerpt Number: 5

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Comment: Use of best available monitoring methods (BAMM) should be allowed for newly 

acquired wells that had been previously reported by former owners, as well as wells that have 

never been reported. The level of effort required to include both categories into an existing 

program is essentially identical. If the applicable well data cannot be obtained from the previous 

owner, reporting delays and late submittals are inevitable. This language should be removed 

from the proposal.

Response: The EPA disagrees that BAMM should be allowed for newly acquired wells that 

were previously subject to subpart W. The reporting rule general provisions in §98.4(h) provide 

for changes in owners and operators and provide that such owner or operator shall be responsible 

for the representations, actions, inactions, and submissions of the designated representative and 

any alternate designated representative of the facility or supplier. As such, reporters are 

responsible for gathering data in a timely manner for acquired sources. Also, for wells acquired 

from companies that were previously subject to subpart W, any necessary sampling ports or 

other modifications would have previously been made to the equipment to accommodate 

measurement. See Section II.C of the preamble for additional information.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 10

Comment: BAMM should be available in 2015 and beyond for newly acquired wells. Although 

EPA proposes to allow a six month period for use of engineering estimates for acquired wells 

that have not previously been reported under Subpart W, there is no reason not to extend this 

provision to acquired wells that were previously reported by another company. There is no 

distinction in the level of effort required to integrate a newly acquired well into an existing 

reporting program based on whether the well was previously subject to Subpart W or not. In fact, 

because an owner of a newly acquired well may need to obtain information from the prior owner, 

the newly acquired well owner may need more time to obtain the information from the seller.

Response: See response to comment EPA-HQ-OAR-2011-0512-0080-A1, Excerpt 5.

20.2 Requests for transitional BAMM for 2015

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 9

Comment: Transitional BAMM should be available for a limited period following the final 

rule. API understands that EPA would like to remove all provisions regarding BAMM as part of 

the final rule. At the same time, our collective experience with the GHGRP has demonstrated 

that industry will need adequate lead time to implement changes in the final rule. Consistent with 

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past precedent and EPA’s desire to bring finality to BAMM, API proposes a reasonable six 

month timeframe for “Transitional BAMM” that would begin January 1, 2015 or the effective 

date of the rule, whichever is later. Given the limited time between the finalization of the rule 

and January 1, 2015, “Transitional BAMM” would allow the reporters to read and digest the rule 

and to put all elements in place to ensure that all data collection can, in fact, go forward and 

other systems can be implemented to facilitate timely and accurate reporting.

Response: The EPA agrees that short-term transitional BAMM provisions are needed for 

emission sources that are subject to new monitoring or measurement requirements as part of 

these final revisions. In the final rule, the EPA is providing a short-term (3 month) transitional 

BAMM period where BAMM may be used without submitting a formal request to the EPA. 

Reporters will also have the opportunity to request an extension for the use of BAMM beyond 

March 31, 2015; those owners or operators must submit a request to the Administrator by 

January 31, 2015. The EPA is not providing transitional BAMM for these revised requirements 

beyond December 31, 2015. See Section II.D of the preamble to the final rule for additional 

discussion responding to this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 22

Comment: API is not proposing that EPA should continue to allow BAMM indefinitely. 

Rather, consistent with EPA’s past practice, API and its members request that EPA provide 

reporters with a six-month period of “transitional BAMM” that would begin January 1, 2015 or 

the effective date of the rule, whichever is later. This six-month period is necessary to allow API 

members adequate and sufficient lead time to read and digest the rule once it becomes final, to 

provide time for facilities to put systems into place, and to accommodate what appears to be 

greatly expanded (and burdensome) measurement and reporting requirements in the proposed 

rule (discussed further below). Furthermore, extending “transitional BAMM” for six months will 

provide necessary flexibility to reporters and also accommodate inevitable issues regarding 

situations beyond the companies’ control which would require BAMM during this transitional 

period. Providing this six-month lead time would accommodate the possibility that the terms as 

finalized in the rule will require further clarification or that reporters will find that it is more 

difficult than expected to develop the required systems. API believes that this six-month period 

is necessary and critical to resolving any additional issues that arise from the ultimate finalization 

of the rule.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 9.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

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Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 23

Comment: Transitional BAMM is Necessary. In the proposed rule, EPA states that “[i]n order 

to provide facilities with time to adjust to the requirements of the rule, Subpart W has provisions 

allowing the optional use of best available monitoring methods (BAMM) for unique or unusual 

circumstances.” See 46 Fed. Reg. at 13404. EPA, however, in its next breath states that it is 

proposing to “remove all provisions in 40 C.F.R. 98.234 for BAMM.” Id. According to EPA, 

although BAMM has been available and frequently used since 2010, removing BAMM at this 

time is appropriate because EPA expects that facilities would be able to comply with the 

monitoring and QA/QC methods required under Subpart W once the rule is final and effective 

because, according to EPA, “reporters with issues that were unidentified by the final rule will 

have adequate time to resolve these issues.” This unsupported statement, however, is unrealistic 

particularly where the timing and substance of the final rule is uncertain, the proposed rule adds 

additional new requirements that the reporters must analyze, and in order to analyze these issues, 

the reporters must have some meaningful and reasonable lead time within which to understand 

the new finalized provisions and determine whether BAMM is needed.

EPA also states that its intent was that BAMM would be a transitional program serving as a 

bridge to full compliance with the rule here reporters faced reasonable impediments. EPA 

believes that based on several years of the industry working with these reporting requirements, 

the facilities have “successfully transitioned so that they either no longer need to use BAMM or 

will not need to use BAMM if these proposed revisions are finalized.” Id. EPA also solicited 

comment requesting “strong technical evidence” for site-specific unique or unusual 

circumstances that would require BAMM after January 1, 2015. Id.

API is not taking issue with EPA’s general approach to phase out BAMM; however, given the 

timing of revisions to be implemented in this final rule and the compliance deadline of January 1, 

2015, a final six-month extension of BAMM is critical and necessary. Experience has shown that 

BAMM has been critical to bridge the gap between the timing of EPA’s final rules and 

compliance obligations. EPA has allowed BAMM since 2010. Even in 2010, EPA stated that 

“EPA does not anticipate a need for Best Available Monitoring Measurements (BAMM) beyond 

2011.” But, EPA found that further extensions were necessary in limited circumstances. In 

March 2011, BAMM was automatic, meaning that no requests for approvals were required. In 

2012, BAMM remained available by submitting a Notice of Intent by December 31, 2011 

followed by a BAMM request consistent with the regulations and BAMM would be 

automatically granted through June 2012 regardless of whether EPA ultimately approved the 

request. EPA also made clear that BAMM was available beyond December 2012 by submitting a 

BAMM request by September 20 of the year prior to the reporting year for which BAMM is 

being sought. See Subpart W: Best Available Monitoring Methods, Greenhouse Gas Reporting 

Program, March 2012. In 2013, BAMM continued to be available and, in fact, EPA revised the 

deadline by which BAMM requests must be submitted to the Administrator. See 78 Fed. Reg. 

11585 (Feb. 19, 2013).

API has found, over the course of implementing the GHGRP, that it can be more difficult than 

anticipated to develop processes for monitoring data or activities that have never been subject to 

federal or state mandated reporting. This is particularly so where various companies already 

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may, for instance, have upwards of 8,000 separators and thousands of valves that must be 

monitored and where, for example, the proposed rule would sweep in hundreds (maybe 

thousands) of small storage tanks. Given the reporting burdens that already exist, the burdens 

that will occur under the proposed rule, and the additional burdens of the expansion of the 

measurement and data reporting requirements proposed in the rule, transitional BAMM is 

imperative.

API members have relied upon Subpart W BAMM provisions to remedy unique or unusual 

circumstances during transitional periods. BAMM has been used to address safety issues, issues 

associated with the shutdown of plants, issues addressing rule interpretation questions, 

measurement flexibility issues, and technical deficiencies as Subpart W has undergone numerous 

revisions since its adoption in 2010. Given EPA’s further revisions in 2014, with a limited 

amount of lead-time prior to January 1, 2015, now is not the time to eliminate BAMM from the 

GHGRP.

As noted above, API is not advocating for a permanent BAMM approach. Rather API believes 

that it is reasonable to provide a six-month time frame (beginning the later of January 1, 2015 or 

the effective date of the Rule) to ensure that the reporters have resolved all of their equipment 

issues and any other issues that may require further clarification. This is particularly true where, 

as described below, in this very rule EPA is proposing to remove BAMM while simultaneously 

expanding the measurement and data reporting requirements, including changes to measurements 

or calculations from various types of equipment and events. Until the final rule has been issued, 

reporters will not be able to ascertain what is truly required, and it will not be clear whether 

BAMM is needed or not.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 9.

Commenter Name: V. Bruce Thompson

Commenter Affiliation: American Exploration & Production Council (AXPC)

Document Control Number: EPA-HQ-OAR-2011-0512-0085-A2

Comment Excerpt Number: 4

Comment: AXPC and the Alliance appreciate that EPA developed BAMM for the initial 

implementation of the GHG Reporting Rule and did not intend to keep it indefinitely. However, 

for the same reasons stated above, We strongly believe that BAMM needs to be available for at 

least six months if the rule timing is pushed back and at least one year if the timing remains as 

proposed. This would allow reporters sufficient time to get the additional data collection, 

management, and reporting systems in place for the newly required data elements. This will take 

a significant amount of time and effort and if EPA does not decide to extend BAMM on an 

applied for or presumptive basis then small operators without the resources to quickly implement

the rule would be unfairly disadvantaged.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 9.

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20.3 Dehydrators

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 12

Comment: Third-Party Dehydrators. Well-pad owners/operators must report emissions under 

the GHGRP including emissions from dehydrators that are owned and operated by third-party 

companies. Thus, the GHGRP inappropriately requires well-pad owners/operators who must 

report to EPA to obtain, report, and certify information regarding emissions from an independent 

third-party source -- namely, the gathering system operators. In practice, however, the well-pad 

owner/operator has no ability to measure the emissions from the third-party dehydrators, has no 

mechanism or ability to QA/QC the information that the third-party provided, and has no ability 

to ensure that the third-party will provide timely emissions data to enable reporting. The GHGRP 

thus puts the regulated industry in an impossible position of having to report and certify 

information over which it lacks direct control. In past practice, BAMM has been used 

to overcome these issues. As described further below in section C and as previously provided to 

EPA [see 3rd Party Dehydrator - Issues and Reporting Alternatives. Follow-up from discussions 

with EPA on September 12, 2013. EPA Issue Tracker #18, September 26, 2013], there are 

various means to correct the rule that provide EPA with high quality data without creating an 

impossible and infeasible compliance burden on the regulated industry that EPA should adopt in 

the final rule.

Response: Subpart W reporters know what information is needed for their annual reports. If 

reporters elect to use third-party vendors for certain services, the information needed for the 

annual reports may be specified in the third-party contract or agreement to ensure the necessary 

information is provided. 

Additionally, as articulated in the preamble to the Final Mandatory GHG Reporting Rule (“Final 

GHGRR”), (40 CFR part 98) (74 FR 56260), the preamble to the final 2010 Subpart W rule (75 

FR 74458), Volume 9, Legal Issues, of the Mandatory GHGRR: EPA’s Response to Public 

Comments (September 2009; available at 

http://www.epa.gov/ghgreporting/documents/pdf/2009/Volume9-RTCLegalIssuesRTCFINAL.pdf), and Volume 9, Legal Issues, of the Mandatory GHGRR Subpart W- Petroleum and 

Natural Gas: EPA’s Response to Public Comments (November 2010; available at 

http://www.epa.gov/ghgreporting/documents/pdf/2010/Subpart-W_RTC_part2.pdf), the scope of 

Section 114 is quite broad and applies beyond persons who own or operate an emission source or 

who are otherwise subject to regulation under the CAA. Its purpose extends to the collection of 

information for “carrying out any provision” of the Act (emphasis supplied). We note, however, 

that subpart W does not require a contractor or third party to report emissions; that responsibility 

lies with the owner or operator of the applicable subcategory and industry sector. Section 

114(a)(1) provides that the Administrator may require any person who owns or operates an 

emissions source to collect and provide relevant CAA information to EPA. As explained, the 

owner or operator is in the best position to collect and report that information to the Agency.

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The fact that emissions might be generated by equipment or processes owned by a party 

independent of the owner or operator of a particular facility is not determinative. The owner or 

operator has ultimate responsibility for the facility and the obligation and responsibility to assure 

that the required information can be collected through legally binding contracts, leases, or other 

agreements. This position that an owner or operator, through contract or other third-party 

agreement, cannot otherwise shirk CAA responsibility has long been that of the Agency (see 

authorities cited below). 

Although the GHGRR is not delimited by other CAA programs such as NSR or Title V, and the 

EPA deems it inappropriate to tailor the provisions of the reporting rules to any specific program, 

we have explained this concept numerous times in the context of NSR or Title V which is here 

instructive and of precedential value. The premise underlying this position lies in the notion that 

the owner or operator has the power to control, the “...power of authority to guide, manage, or 

regulate the pollutant-emitting activities of those facilities....” See, Guidance for Major Source 

Determinations at Military Installations under the Air Toxics, New Source Review, and Title V 

Operating Permit Programs of the Clean Air Act in Memorandum for Major Source 

Determinations for Military Installations, John S. Seitz, Director, Office of Air Quality Planning 

and Standards, August 2, 1996. Therein it is explained that because the contracting entity can 

control the contract operator’s performance through contract terms, contract-for-service activities 

are considered part of a source. Likewise, the Agency has flatty stated its policy that “temporary 

and contractor-operated units [must] be included as part of the source with which they operate or 

support” and “that there are no provisions in title I or title V of the Act, or in regulations 

developed pursuant to them, for excluding contracted or temporary operations in defining major 

sources.” Letter from John S. Seitz to Lisa J. Thorvig, Division Manager, Minnesota Pollution 

Control Agency, November 16, 1994. The underlying rationale for including sources over which 

an owner or operator exercises control in making major source determinations in the permitting 

context is thoroughly explained in 1995 guidance, Letter from William Spratlin, Director, Air, 

RCRA, and Toxics Division, EPA Region VII, to State and Local Air Directors, September 18, 

1995.

Further, as explained in Section V of the preamble of the 2009 final part 98 (74 FR 56355), all 

reporters must select a designated representative (DR) who is responsible for certifying, signing, 

and submitting all submissions to EPA. This provision provides flexibility to the owners and 

operators to choose any individual, employee or non-employee, to represent them, while 

ensuring EPA has one accountable point of contact. As explained in the preamble to the final 

part 98, the high level of public interest in the data collected, as well as its importance to future 

policy, warrants establishment of a high standard for data quality and consistency and high level 

of accountability for reported data. The DR provisions and certification requirements help ensure 

the standard for high quality data and consistency is met. The DR provisions are crafted similarly 

to the provisions of the Acid Rain Program (ARP), 40 CFR part 72 and EPA has found that this 

approach provides a high degree of both data quality and consistency and accountability.

Similar comments were made about the data coming from multiple owners and operators and the 

concerns about the certification of those data upon promulgation of the ARP and the 2009 final 

GHG reporting rule to which we responded, and for which responses are summarized. We have 

attempted to provide maximum flexibility while ensuring accountability. For integrity of the 

program, one representative of the owners and operators must report for important reasons. 

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Doing so ensures the accountability of owners or operators by, inter alia, reducing the likelihood 

of inconsistent submissions by a facility. Interposing another person or party between the facility 

and the Agency would dilute the DR’s responsibility and in effect create multiple DRs for the 

facility. Additionally, leaving the ultimate responsibility of submission with the designated 

representative has the salutary effect of clarifying that the DR should be aware of all submissions 

and should inquire of the persons with personal knowledge of the information in those 

submissions. The DR has the flexibility to delegate duties, such as the preparation of 

submissions, but retains the ultimate responsibility to sign and certify all submissions. (See, 58 

FR 3590, 3598, January 11, 1993.) 

Furthermore, we believe that the commenter has misinterpreted the Part 98 certification 

provisions which simply require the DR to make “appropriate inquiry” and certify to the best of 

his or her knowledge, §98.4(e)(1), however ultimate responsibility rests and must necessarily rest 

on him or her. The DR may provide in contracts, leases, or other agreements with third parties 

that true, accurate, and correct reporting information must be provided to the DR in a timely 

fashion. If the third party fails to provide timely, true, accurate, or correct information to the DR, 

then the DR has recourse contractually, or otherwise, on the third party. See Section II.C of the 

preamble to the final rule for additional discussion responding to this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 25

Comment: EPA Must Amend the Third-Party Dehydrators Reporting Requirements. The 

GHGRP requires that well-pad owners/operators report emissions from dehydrators located on a 

single well-pad including dehydrators owned and operated by third-party companies. Thus, in an 

unexplainable requirement unique in the GHGRP to this specific issue, EPA requires 

owners/operators of the well-pad to obtain information from third-party dehydrator 

owners/operators regarding emissions, inputs to the dehydrator models, and outputs from the 

dehydrator models and report these third-party emissions and other required information, as well 

as maintain such third-party data for record-keeping. Additionally, as part of the reporting 

obligations, the designated representative for the reporting owner/operator is required to certify 

the accuracy of third-party emissions and information data.

API vehemently objects to EPA’s approach to Third-Party Dehydrators for a number of reasons. 

First, under the GHGRP, EPA is requiring the wrong party—the well-pad owners/operators—to 

obtain the emissions information that EPA is requesting. For activities performed by third-party 

service providers, EPA incorrectly takes the position that it should not be burdensome for the 

well-pad owners/operators to seek, obtain, and certify emissions information from third-party 

contractors. EPA simply ignores that well-pad owners lack legal mechanisms and the ability to 

require the third-party gathering company to provide the emissions information to the 

owners/operators in the first place. Additionally, the well-pad owners/operators have no 

mechanism or ability to QA/QC data collected by another company or to certify the information 

provided by a third-party dehydrator owner/operator.

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It is simply not possible or prudent for the owners/operators to “certify”—as EPA requires—that 

the data is correct because the owners/operators do not collect the data. It would be very 

inappropriate, in fact, to certify third-party data as correct in a government run system which 

could subject the companies to enforcement actions and criminal claims under 18 U.S.C. 1001 

and other provisions. Where there is no EPA rule requiring the third parties to report emissions 

from their equipment, but instead the well-pad owners/operators must do so, it is beyond 

inappropriate for owners to, in fact, certify the “accuracy of the emissions and information 

reported” based on third party information that it may or may not be able to obtain. The 

information from the third parties is not first-hand, and where API member companies cannot 

use their QA/QC processes, if the well-pad owners/operators in fact certified the accuracy of the 

emissions and information reported, they could be subjecting themselves to civil or criminal 

sanctions or criminal liability for making inaccurate statements within the jurisdiction of the 

federal government [API also believes there could be a serious Due Process issue with requiring 

an entity to certify information from third parties under the potential penalty of criminal liability. 

Due Process includes liberty preserved from deprivation without due process and encompasses 

freedom from bodily restraint and punishment. See Matthews v.Eldridge, 424 U.S. 319, 335 

(1976)]. It is arbitrary and capricious for EPA to require one party to obtain, report, and certify 

data that relates to the operations of an independent third party.

This is simply an area that the GHGRP gets entirely wrong, and EPA must address. Until EPA 

recently announced that it is proposing to remove all BAMM provisions, reporters have been 

relying on BAMM to ensure appropriate reporting in this area. The difficulties and obstacles—if 

not impossibility—of obtaining reliable and timely data from the intermediary companies cannot 

be overstated. EPA should not impose this data collection requirement on companies that do not 

and cannot collect the data themselves. EPA, on the other hand, can propose that these reporting 

requirements apply to the third-party entities that maintain the information on the emissions 

which could lead to better and more complete data.

Moreover, API also has provided specific language and options to EPA in an effort to reconcile 

these issues and enable EPA to obtain high quality data without creating an impossible, arbitrary 

and capricious burden on the well-pad owners and operators. We have attached proposed 

language that was provided to EPA in September 2013 that would enable EPA to get full and 

accurate information on third-party dehydrators without subjecting owners/operators to the 

impossible reporting burden EPA is imposing here. One of API’s suggestions is for EPA to 

modify the rule to include an approach similar to what is used for small dehydrators where the 

well-pad owners/operators would be required to report the number of dehydrators with annual 

average daily throughput greater than or equal to 0.4 MMCSFD and less than 3.0 MMSCFD. We 

remain willing to work constructively with EPA toward solutions that would enable EPA to 

realize its interests in obtaining data without subjecting industry to an infeasible and 

unacceptable burden.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 12 and 

Section II.C of the preamble to the final rule for the EPA’s response to this comment.

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Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 18

Comment: Third party dehydrators: GPA member companies own and operate dehydrators at 

onshore petroleum and natural gas production facilities. The proposed rule continues to require 

production facility owners/operators to report third party dehydrator emissions. As previously 

discussed with EPA, this requirement is problematic for both the dehydrator owner/operator and 

the production facility owner/operator. GPA therefore supports API’s comments regarding third 

party dehydrators.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 12 and 

Section II.C of the preamble to the final rule for the EPA’s response to this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 95

Comment: Proposed Citation Reference for Dehydrators: §98.236(e)(1)(iii), Proposed Rule 

Text: Dehydrator feed natural gas water content, in pounds per million standard cubic feet.

Proposed Citation Reference for Dehydrators: §98.236(e)(1)(iv), Proposed Rule Text: 

Dehydrator outlet natural gas water content, in pounds per million standard cubic feet.

Proposed Citation Reference for Dehydrators: §98.236(e)(1)(vi),Proposed Rule Text: Dehydrator 

absorbent circulation rate, in gallons per minute.

Proposed Citation Reference for Dehydrators:§98.236(e)(1)(xii), Proposed Rule Text: Pressure 

of the wet natural gas, in pounds per square inch gauge.

Proposed Citation Reference for Dehydrators§98.236(e)(1)(xvii), Proposed Rule Text: Whether 

any dehydrator emissions are vented to the atmosphere without being routed to a flare or 

regenerator firebox/fire tubes.

This information is extremely difficult to collect from owners/operators of third-party 

dehydrators. This issue also applies to some of the current reporting requirements for 

dehydrators, such as the temperature of the wet gas.

Well-pad owners/operators have been utilizing BAMM to overcome these issues and enable 

reporting of 3rd party dehydrators, but EPA is removing this option. API urges EPA to revise 

§98.233(e) to allow the use of a default emission factor for mid-sized dehydrators that are 

owned/operated by third parties.

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Response: At this time, we are not including default emissions factors for glycol dehydrators 

with a natural gas throughput of 0.4 million standard cubic feet or greater. See response to 

comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 12 and Section II.C of the preamble to 

the final rule for additional discussion responding to this comment.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 18

Comment: Williams strongly encourages EPA to adopt the emission factors, 311,950 scfy of 

methane and 13,643 scfy of carbon dioxide, previously submitted by API to the Agency in 

September 2013. These CO2 and CH4 emission factors were developed for mid-size dehydration 

units that fall between 0.4 MMSCFD and 3.0 MMSCFD. Adoption of these emission factors 

would greatly simplify the reporting process for producers, and third-party owner/operators (like 

Williams) who provide the emissions information to producers. Adoption would also allay 

producers’ concerns over certifying emissions based on operational data collected, and 

calculations performed and supplied by the third party owner/ operators. The proposed emissions 

factors were conservative values and resulted from: (1) an extensive review of dehydrator data 

from more than 1,800 affected dehydration units over two years; and (2) the scaling of mid-size 

to small dehydrators, for which emission factors developed by EPA already exist. Should these 

emission factors not be adopted we recommend that BAMM continue to be allowed for these 

units due to the difficulties encountered by producers in obtaining, and subsequently reporting, 

this information.

Response: At this time, we are not including default emissions factors for glycol dehydrators 

with a natural gas throughput of 0.4 million standard cubic feet or greater. See response to 

comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 12 and Section II.C of the preamble to 

the final rule for additional discussion responding to this comment.

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21.0 General Revisions to Reporting Requirements (including addition of 

new reporting elements)

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 24

Comment: EPA Should Not Finalize the Proposed Expansion of Measurements and Reporting 

Requirements in the Proposed Rule. 

The proposed rule, if finalized as proposed, would greatly expand the measurements and 

reporting requirements from the existing GHGRP. First, under the proposed rule, EPA expands 

the definition of well type combinations for completions and workovers with hydraulic fracturing 

to include with and without flaring. This requirement doubles the measurement and reporting 

requirements for Subpart W reporters. Second, the proposed rule expands the definition of well 

type combinations for workovers to include with and without reduced emission workover. This 

provision singlehandedly may quadruple the measurement and reporting requirements. Third, the 

rule expands the requirements to report emissions for stuck dump valves to tanks with a 

throughput that is less than 10 bbls per day.

These proposed new measurements and reporting requirements go beyond the authority under 

CAA Sections 114 and 208. EPA’s use of Section 114 historically has been properly limited to 

issuing Information Collection Requests (ICRs). ICRs have been limited to collecting data from 

specific sources over a discrete period of time usually relying upon existing data or a subset of 

the universe of sources, or both. Section 114, however, is not typically used to justify an 

economy-wide, on-going reporting rule requiring all affected entities to submit data annually 

with new, onerous, and ever-changing monitoring and measurement processes. Furthermore, 

regarding Section 208, as EPA has expressly acknowledged, the rule was proposed in response to 

the 2008 Consolidated Appropriations Act, which provided limited funding, did not grant EPA 

any broad regulatory or enforcement authority, and limited the proposed rule to the reporting of 

greenhouse gas “emissions.”

EPA in this proposed rule goes beyond its limited CAA authority, resulting in a proposal that 

would be arbitrary and capricious if finalized. For example, many of the new elements that EPA 

has inserted into the proposed rule simply do not address actual “emissions.” EPA’s authority is 

limited to addressing actual emissions. In the context of a the greenhouse gas reporting rule,

CAA Section 114 cannot be relied upon to allow EPA to seek information about issues that are 

not directly related to the reporting of emissions. The expanded provisions in the proposed rule, 

however, erroneously request that members report a significant amount of information that 

extends beyond the requirement of an emissions reporting program. For example, these 

expanded reporting requirements include:

• provisions requiring reporting the “Compressor power rating (hp)”; the year the compressor 

was installed, the compressor model name and description, and date of last maintenance 

shutdown for centrifugal and reciprocating compressors;

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• provisions requiring a description of how the owner or operator will avoid the use of missing 

data in the future for each missing data value used in a calculation that led to missing data 

use;

• a provision requiring reporters to describe the unique and unusual circumstances that led to 

missing data use;

• provisions requiring that reporters include information on any equipment or components 

involved and any procedures that were not followed for each missing data value used in a 

calculation; and

• provisions requiring reporters to develop, collate, and report voluminous new items unrelated 

to emissions quantification and reporting in §98.236(aa).

API urges that EPA not adopt these arbitrary and capricious expansions particularly where the 

onerous reporting requirements do not facilitate the reporting of greenhouse gas emissions but 

instead seek general information regarding equipment and/or components or the structure of the 

oil and gas production sector and natural gas supply chain. These elements importantly, are not 

related to the required reporting of emissions data. Because these issues are beyond the scope of 

CAA Sections 114 and 208, EPA lacks authority and API members should not have to bear the 

burden of measurements and reporting requirements that are not tethered to actual emissions as 

required under the CAA.

Response: The EPA disagrees with the commenter that the proposed elements are beyond the 

authority of the EPA under CAA Section 114. However, we have reviewed the data reporting 

requirements and have made revisions to address several of the commenter’s concerns. For 

example, we significantly revised and limited reporting associated with the use of missing data 

procedures. We have removed certain reporting requirements, such as model name and 

description for compressors. Also, the final rule revisions clarify that emissions due to gas-liquid 

separator liquid dump valves not closing properly do not need to be calculated or reported for 

tanks with throughput less than 10 bbl/day. We are retaining the proposed delineation between 

reduced emission completions/workovers and the general reporting requirements in §98.236(aa) 

with minor revisions. See Section II.E.2 of the preamble to the final rule for further information 

regarding the final reporting requirements.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 14

Comment: EPA is seeking information that is not related to a reporting program. The 

information that the proposed rule would require extends beyond the requirements of a reporting 

program by seeking information that does not address emissions but seeks ancillary information 

regarding, among others, compressor ratings, dates that compressors were maintained, reporting 

about how owners/operators will avoid using missing data in the future, and reporting a 

description of the unique or unusual circumstance that led to missing data use. This overreach is 

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particularly egregious in the reporting requirements at §98.236(aa) where it appears that EPA is 

attempting to use the GHGRP as a vehicle to construct a very detailed and comprehensive profile 

of the oil and gas production sector and the entire natural gas supply chain. The majority of the 

data/information elements required to be reported under §98.236(aa) are not related to emission 

quantification and reporting and where they are related, they are required to be reported in the 

sections detailing reporting elements for each source type and hence redundant in §98.236(aa). A 

detailed discussion of these reporting elements and API’s objections can be found below in the 

technical comments.

Response: The EPA has determined that the data elements §98.236(aa) are useful for the 

verification of existing data. For example, production, capacity, or operational information may 

be used to normalize the data collected and improve our characterization of the emissions 

sources. Therefore, the EPA is finalizing these reporting requirements as proposed, with minor 

clarifications. See Section II.E.2 of the preamble to the final rule for further information 

regarding the final reporting requirements.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 71

Comment: EPA should reconsider new reporting requirements. Numerous data elements have 

been arbitrarily added, are not needed to calculate GHG emissions, and will add unnecessary 

burden for reporters.

The Proposed Rule significantly increases the number of data elements to report under §98.236. 

Although the preamble includes confidentiality determinations, and a docket memo tabulates the 

changes, EPA has not explained or justified the need for these data elements. As discussed in 

Comment 9, the new reporting requirements increase costs, and EPA should justify its decision 

for each data element added to §98.236.

If INGAA understood EPA’s objective for adding the data elements, it is possible that specific 

feedback on various data elements could be provided. A partial list of data elements added for 

T&S sources that should be reconsidered and justified if included follows:

• For transmission storage tank vent stack, whether scrubber dump leakage is occurring for the 

underground storage vent – §98.236(k)(l)(iii) ; see Comment 18 regarding the need for 

clarification;

• Average time surveyed components were found leaking and operational – §98.236(q)(2)(iii);

• Average upstream pipeline pressure, psig – §98.236(aa)(4)(iv);

• Average downstream pipeline pressure, psig – §98.236(aa)(4)(v);

• Quantity of gas injected into storage – §98.236(aa)(5)(i);

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• Quantity of gas withdrawn from storage – §98.236(aa)(5)(ii);

• Number of compressors – §98.236(aa)(4)(ii);

• Total compressor power rating for all compressors combined, HP – §98.236(aa)(4)(iii);

• Total storage capacity for underground natural gas storage facilities – §98.236(aa)(5)(iii).

Response: The EPA has determined that the data elements in §98.236(aa) are useful for the 

verification of existing data. These data also improve our characterization of the emissions 

sources. Therefore, the EPA is finalizing these reporting requirements as proposed, with some 

clarifications. See Section II.E.2 of the preamble to the final rule for further information 

regarding the final reporting requirements.

Commenter Name: V. Bruce Thompson

Commenter Affiliation: American Exploration & Production Council (AXPC)

Document Control Number: EPA-HQ-OAR-2011-0512-0085-A2

Comment Excerpt Number: 2

Comment: Additionally, many of the added data elements that are proposed to be gathered and 

reported are not related to the emission calculations and should not be part of this GHG 

emissions reporting rule. For instance, EPA has added many data elements to compressor 

reporting such as engine horsepower, installation date, model name and description, and date of 

last rod packing replacement. While these are clearly not within the scope of emission reporting, 

there are also other data elements that are burdensome to manage and report such as software 

simulation package used and associated inputs. These models are often run outside of the data 

management system and the inputs not available for subsequent reporting without making large 

modifications to the emissions data management system.

AXPC and the Alliance requests that EPA reconsider the addition of data elements to report in 

this rulemaking, particularly those that do not pertain to emission calculations. We also urge 

EPA to reevaluate the man‐hours that will be required to implement the proposed data additions 

and changes to calculation methodologies in determining compliance and implementation dates.

Response: The EPA has evaluated the commenter’s concerns. We have revised the reporting 

requirements based on our review of the comments received and have removed the reporting 

requirements for the year the compressor was installed and the model name and description of 

the compressor. We also revised the proposed “compressor power rating” element to clarify that 

this reporting element is the “power output of the compressor driver”. We also replaced the 

reporting requirement for the date of the last maintenance shutdown with a simple indication of 

whether the compressor had a scheduled depressurized shutdown during the reporting year. See 

Section II.E.2 of the preamble to the final rule for additional response to this comment.

Regarding the additional reporting requirements of inputs to software simulation packages, these 

data elements are being collected to assist in verification of the reported emissions data. 

Reporters should currently maintain inputs of the software as part of existing reporting and 

recordkeeping requirements as required in §98.3(g)(2). Therefore, it is our determination that 

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reporters should have access to and be able to report this information in their reporting year 2015 

submissions. Regarding the impacts of the reporting requirements in the final rule, see Section 

IV.B of the preamble to the final rule.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 84

Comment: Revisions to §98.236(aa): EPA is proposing to require reporting additional specific 

information for each applicable industry segment.

API has serious concerns with the reporting requirements in 98.236 (aa) in terms of the relevance 

of the information for quantifying emissions, the lack of clarity in some item requirements, the 

substantial burden associated with developing this information for reporting.

Response: The EPA has determined that these data elements in §98.236(aa) are useful for the 

verification of existing data and for improving our characterization of the emissions sources. 

Regarding the burden associated with collecting the data reported, see Section IV.B of the 

preamble to the final rule.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 89

Comment: API has no comments regarding items (I) and (J)

(K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic feet per 

barrel.

(L) If an oil sub-basin, report the average API gravity of all wells.

(M) If an oil sub-basin, report average low pressure separator pressure, in pounds per square inch 

gauge.

Items (K) thru (M) are reported under §98.236(j) where they are relevant to calculation and 

reporting of emissions. Requiring reporting of these items as proposed in §98.236(aa)(1)(ii) is 

either not related to emissions quantification and reporting and hence not within the purview of 

the GHGRP or redundant reporting which should be eliminated.

Response: First, the EPA notes that these are not new reporting requirements. These reporting 

requirements were previously housed in §98.236(e), but have been moved to the general sub212
basin reporting section proposed at §98.236(aa). Second, we disagree that these reporting 

elements are completely duplicative. If an oil well recovers all associated gas, then the reporting 

requirement for gas-to-oil ratio proposed at §98.236(m)(4) would not be applicable. Reporting of 

API gravity and separator pressure are only required when Calculation Methods 1 or 2 are used 

and then the values are to be reported separately by calculation method. Finally, it is convenient 

to have this general information provided together with other general sub-basin information. For 

these reasons, we are finalizing these reporting requirements as proposed. 

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 90

Comment: (2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) 

through (aa)(2)(iii) of this section.

(i) The quantity of gas produced from the offshore platform in the calendar year for sales, in 

thousand standard cubic feet.

(ii) The quantity of oil produced from the offshore platform in the calendar year for sales, in 

barrels.

(iii) The quantity of condensate produced from the offshore platform in the calendar year for 

sales, in barrels.

Again, API does not understand the relationship between emission quantification and reporting 

and the data required to be reported in §98.236(aa)(2)(i) thru (ii). This appears to be another 

instance of using the GHGRP as a vehicle to collect data EPA believes it may want that is not 

appropriate for an emission reporting program and overreaches EPA’s authority. Items 

§98.236(aa)(2)(i) thru (ii) should be stricken from the rule.

Should EPA retain these items, API has two issues with proposed changes to the reporting 

requirements for offshore production. First, offshore production facilities in Gulf of Mexico 

Outer Continental Shelf (OCS) waters or State jurisdictional waters in the Gulf of Mexico often

are not set up as a stand-alone production facility, with the entire production process from 

extraction from the seafloor to the custody transfer meter being housed on one discrete structure. 

Instead, shelf facilities can function in a web-like formation, with individual platforms, that are 

not bridge-connected, supporting different phases of the production process. The last step in the

process is for the oil and gas to be transferred to a transportation pipeline, which typically occurs 

on a host facility at the point of custody transfer. The volume of oil and gas transferred to a 

pipeline after final processing is metered for purposes of reporting custody transfer volumes to 

regulatory, internal, and external stakeholders. Because processing of the oil and gas can occur in 

several stages on multiple platform structures connected solely by in-field non-custody transfer 

pipelines, it would be difficult to assign an accurate “sales” or “custody transfer” volume to these 

intermediary facilities that are not equipped with a custody transfer meter. For revenue

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allocation purposes, oil and gas volume allocation is based on well test data and the custody 

transfer metered volumes at the host facility, which typically receives oil and gas from several 

upstream intermediary structures. Therefore, because “sales” or “custody transfer” volumes are 

not required on an individual facility basis, but rather on an individual well basis, for revenue 

allocation reporting purposes, assigning such a volume to a non-metered intermediary structure 

would pose a considerable challenge as it would be a departure from current business practices.

If EPA’s intent in requesting this information is to assess the magnitude of hydrocarbon handled 

at a reporting facility, requiring facilities to continue to report a facility “throughput” volume as 

opposed to a “sales” volume would provide a more accurate and realistic depiction of the volume 

of hydrocarbon handled at an intermediary facility that is not equipped with a custody transfer 

meter. Therefore, we are proposing that EPA leave the facility throughput reporting language as 

it stands in the current rule for facilities located in OCS waters, and not implement the changes 

included in the proposed rule revision. Reporting a “throughput” as opposed to a “sales volume” 

for a facility would also be consistent with the BOEM Gulfwide Offshore Activity Data Systems 

(GOADS) requirements, which requires OCS facilities to report throughput as part of the 

GOADS report. BOEM defines throughput as follows in the User’s Guide for the Gulfwide 

Offshore Activities Data Systems (GOADS): “Throughput – total volume of natural gas or oil 

products handled at the current structure during the calendar year, including production volumes 

and volumes transferred via pipeline from another location.”

Secondly, leaving the facility throughput reporting requirement language as it is in the current 

rule would also address the second issue we are presenting with the proposed change. EPA’s 

proposal requires sales volumes of oil and condensate to be reported separately. However, it is 

not uncommon for OCS facilities to blend all liquid products, including oil and condensate, 

together for custody transfer as a single liquid product stream. It would be difficult to efficiently 

and accurately separate the liquid custody transfer volumes between oil and condensate for those 

facilities where they are blended and transferred as a single product stream without conducting a 

well-specific analysis of well test data across the hundreds of wells feeding into a reporting 

facility. In addition, the definition of condensate included in 40 CFR 98.238 is not consistent 

with the commonly used industry language regarding condensate, which typically includes an 

API gravity cut off. Therefore, there is room for interpretation among reporters as to what is

considered condensate, which can lead to inconsistency in reporting across the offshore industry 

segment. Therefore, we recommend that EPA not alter the facility throughput reporting 

requirements for offshore facilities as is included in the March 10, 2014 proposal. If EPA does 

move forward with the proposed changes to the facility throughput reporting requirements, we 

request that EPA add clarifying language specifying that the volume of blended oil/condensate 

stream may be reported an oil stream, and that separation of blended oil/condensate streams for 

reporting purposes is not required.

Response: The EPA disagrees that the information in §98.236(aa)(2) overreaches our authority 

to gather information. The EPA has determined that these data elements §98.236(aa)(2) are 

useful and necessary for the verification of existing data and for characterizing the emissions 

from the industry segment. However, the EPA recognizes the commenter's concerns regarding 

the structure of offshore production facilities and the capability of a source to quantify sales 

volume versus throughput. We agree with that commenter that, because these operations 

typically operate as independent platforms and sales volumes may not be metered until transfer 

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to a pipeline, it is more appropriate to gather throughput information. Additionally, the EPA 

agrees with the commenter that it could be difficult to separate the liquid custody transfer 

volumes between oil and condensate. As such, we have revised the final reporting requirements 

to clarify that the quantities to be reported are throughput quantities (using wording from the 

BOEM definition) and that a single liquid quantity, which includes both oil and condensate. The 

final rule has been revised to read as follows:

"(2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) and 

(aa)(2)(ii) of this section.

(i) The total quantity of gas handled at the offshore platform in the calendar year, in thousand 

standard cubic feet, including production volumes and volumes transferred via pipeline from 

another location....

(ii) The total quantity of oil and condensate handled at the offshore platform in the calendar year 

for sales, in barrels, including production volumes and volumes transferred via pipeline from 

another location."

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 91

Comment: (3) For natural gas processing, report the quantities specified in paragraphs (aa)(3)(i) 

through (aa)(3)(vii) of this section.

(i) The quantity of produced gas received at the gas processing plant in the calendar year, in 

thousand standard cubic feet.

(ii) The quantity of processed (residue) gas leaving the gas processing plant in the calendar year, 

in thousand standard cubic feet.

(iii) The quantity of NGLs (bulk and fractionated) received at the gas processing plant in the 

calendar year, in barrels.

(iv) The quantity of NGLs (bulk and fractionated) leaving the gas processing plant in the 

calendar year, in barrels.

(v) Average mole fraction of CH4 in produced gas received.

(vi) Average mole fraction of CO2 in produced gas received.

(vii) Indicate whether the facility fractionates NGLs.

Again, API does not understand the relationship between emission quantification and reporting 

and the data required to be reported in §98.236(aa)(3)(i) thru (iv). This appears to be another 

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instance of using the GHGRP as a vehicle to collect data EPA believes it may want that is not 

appropriate for an emission reporting program and overreaches EPA’s authority. Items 

§98.236(aa)(3)(i) thru (iv) should be stricken from the rule.

Also, API would like to point out that items (i), (iii), and (iv) are not designated as CBI under 

Subpart W but are designated as CBI under Subpart NN of the GHGRP. Although the exact text 

differs slightly these are the same items with different CBI treatment under Subpart W and 

Subpart NN. API requests that they be similarly designated as CBI under Subpart W in 

conformance with their designation as CBI under Subpart NN.

Response: The EPA disagrees that the information in §98.236(aa)(3) overreaches our authority 

to gather information. The EPA has determined that these data elements §98.236(aa)(3) are 

useful and necessary for the verification of existing data and for characterizing the emissions 

from the industry segment. Upon further review of the information proposed to be reported under 

§98.236(aa)(3)(i), (iii), and (iv), we have revised our CBI categorizations for these reporting 

elements. In the final rule, we have designated §98.236(aa)(3)(i) to be CBI and we have decided 

not to make a confidentiality determination for the elements in §98.236(aa)(3) (iii) and (iv), See 

Section III.B of the preamble to the final rule for further discussion regarding the final CBI 

determinations.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 17

Comment: In 40 CFR 98.236 (aa)(iii) and (iv), EPA requests natural gas processors to report 

the quantity of bulk and fractionated NGLs entering and leaving their processing plants.

For GHG inventory purposes, Williams believes NGLs are adequately tracked in Subpart NN for 

fractionation facilities receiving and supplying NGLs. Providing NGL information for natural 

gas processing plant under Subpart W, an emitter category, would be of little value to the 

national GHG inventory.

Response: The data reported under subpart NN are the separate quantities of individual 

fractionated NGLs and bulk NGL received and supplied. The data reported under subpart W are 

the aggregated quantities received and supplied of all individual fractionated NGLs and any bulk 

NGL. The EPA has determined that these aggregated values are useful and necessary for report 

verification and characterizing the emissions from the industry segment. See response to 

comment EPA-HQ-OAR-2011-0512-0089-A3, Excerpt 20 of this section for a discussion of 

clarifications to the wording of these data elements in the final rule.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

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Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 92

Comment: API has no objection to reporting of items §98.236(aa)(3)(v) through (vii) since they 

do not impose an undue burden on reporters. However, API would like to point out that where 

compositions are relevant to emissions for a particular source type, they are required to be 

reported in conjunction with that source type and reporting these items here is redundant and 

unnecessary.

Response: The EPA has considered the commenter's concern and is retaining items 

§98.236(aa)(3)(v) through (vii) in this final rule. Natural gas processing facilities may have many 

different configurations. For example, some facilities which only separate NGLs into component 

mixtures may not include acid gas removal vents or dehydrators. As such, not all facilities will 

be reporting the information provided in §98.236(aa)(3)(v) through (vii) with their calculated 

emission estimates. The provisions of §98.236(aa) capture these data for the entire industry 

segment reporting under Subpart W.

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 20

Comment: EPA proposes several new reporting requirements related to gas throughput at a 

processing facility. EPA should replace the term "produced gas" with "natural gas". "Produced 

gas" is not a term that is defined and is not used in the midstream industry to refer to raw/inlet 

gas.

Additionally, EPA has not provided a method for determining the natural gas and NGL 

throughputs it is requesting, and we therefore request that EPA retain the language that is in the 

current rule under 98.236(d) regarding "engineering estimate based on best available data."

EPA proposes two new reporting requirements related to NGLs at processing plants, 

98.236(aa)(3)(iii) and (iv). EPA requests "quantity of NGLs (bulk and fractionated)", which is 

vague. It’s unclear in both of these requirements if EPA is requesting one total volume or 

volumes separated into subgroups (such as y-grade NGL, propane, E/P mix, etc). We propose 

that this be reworded to clearly indicate that only one number is requested per requirement. 

Otherwise, EPA needs to significantly revise this requirement to clarify which NGLs should be 

reported and how. For example, if a butane-gasoline mix stream is a product of the processing 

plant, how would this stream be reported?

98.236(aa)(3) For natural gas processing, report the quantities specified in paragraphs 

(aa)(3)(i) through (aa)(3)(vii) of this section, as determined by engineering estimate based on 

best available data. 

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98.236(aa)(3)(i) The quantity of produced natural gas received at the gas processing plant in 

the calendar year, in thousand standard cubic feet. 

98.236(aa)(3)(ii) The quantity of processed (residue) gas leaving the gas processing plant in the 

calendar year, in thousand standard cubic feet. 

98.236(aa)(3)(iii) The total quantity of all NGLs (bulk and fractionated, combined) received at 

the gas processing plant in the calendar year, in barrels. 

98.236(aa)(3)(iv) The total quantity of all NGLs (bulk and fractionated, combined) leaving the 

gas processing plant in the calendar year, in barrels. 

98.236(aa)(3)(v) Average mole fraction of CH4 in produced natural gas received. 

98.236(aa)(3)(vi) Average mole fraction of CO2 in produced natural gas received. 

Response: The EPA agrees with the commenter that the term "produced gas" may be confusing 

and has revised §98.236(aa)(3) to refer to “natural gas.” While we understand that the 

commenter believes that the text “as determined by engineering estimate based on best available 

data” clarifies how the quantities of natural gas and NGL throughputs are determined, we note 

that the introductory text in §98.236(aa) already specifies that the information in paragraphs 

(a)(1) through (a)(9) are to be reported using “best available data”. Regarding §98.236(aa)(3)(iii) 

and (iv), EPA is clarifying in the final rule that the “cumulative quantity of all NGLs (bulk and 

fractionated)...” are to be reported. By referring to this as a cumulative quantity, we are 

clarifying that §98.236(aa)(3)(iii) is a single value representing the sum total of all NGLs (bulk 

and fractioned, combined) that are received at the gas processing plant in the calendar year. 

Similarly, §98.236(aa)(3)(iii) is a single value representing the sum total of all NGLs (bulk and 

fractioned, combined) that are leaving the gas processing plant in the calendar year. The quantity 

of butane-gasoline mix stream produced by a gas processing plant would be added to the 

quantity of other products leaving the gas processing plant in order to determine the cumulative 

quantity of NGLs leaving the gas processing plant.

22.0 Confidentiality Determinations and Data Category Assignments for 

New or Revised Data Elements

22.1 EPA’s Approach to confidentiality determinations and data category 

assignments for new or revised data elements

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 33

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Comment: EPA has committed to evaluate alternative approaches to calculation and reporting 

where disclosure of information is likely to cause substantial competitive harm. However, it has 

not followed its own process here.

Response: The EPA undertook a complete review of all data elements as part of the 

development of the proposal, including reviewing all new and substantially revised data elements 

that are used as inputs to equations used to calculate the emissions. This review included 

assessing whether the data elements were already publicly available and for those data elements 

that are not already public, whether their disclosure posed a risk of causing substantial 

competitive harm to reporters. We note that many of the revisions to the calculation methods and 

reporting requirements are being made in response to specific recommendations made by 

industry. The proposal gave the industry an opportunity to comment on the proposed changes to 

the calculation methods, identify reporting requirements that are sensitive, and suggest 

alternative calculation and reporting requirements that would avoid disclosure of any inputs to 

emission equations considered to be sensitive. This approach is consistent with the approach we 

have taken with other rulemakings and allows for the appropriate level of review of 

confidentiality concerns by the EPA and industry.

22.2 Comments on proposed confidentiality determinations for data elements 

that are not inputs to emission equations

Commenter Name: Brian Korpics

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2011-0512-0087-A2

Comment Excerpt Number: 2

Comment: We support the Agency’s proposal to publicly disclose all new, existing, and 

substantially revised data reporting elements under Subpart W.14 This action is required by the 

Clean Air Act’s provisions concerning disclosure of data collected under the Reporting Rule and 

is critical to ensure transparency and promote accountability.15 Moreover, public disclosure will 

help promote efforts to refine other emissions estimation programs such as the Annual Inventory 

of U.S. Greenhouse Gas Emissions and Sinks. EPA’s determinations are in accord with past 

determinations on similar types of data.

Footnotes:

14 Id. at 13,405–20.

15 Section 114(c) of the Clean Air Act requires EPA to disclose “emission data” regardless of 

whether that data would otherwise be considered confidential business information. 42 U.S.C. § 

7414(c). Moreover, long-standing EPA regulations have interpreted “emission data” broadly to 

include “[i]nformation necessary to determine the identity, amount, frequency, concentration, or 

other characteristics . . . of any emission which has been emitted,” or information necessary to 

determine the characteristics of any emissions which “under an applicable standard or limitation” 

a source may emit, or even “[a] general description of the location and/or nature of the source.” 

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40 C.F.R. § 2.301(a)(2)(i). EPA is under a duty to disclose data that is publically available and 

not commercially sensitive. See Envtl. Def. Fund et al., Comments Regarding Proposed Deferral 

of Greenhouse Gas Reporting and Call for Information (Docket ID Nos. EPA-HQ-OAR-2010-

0929 and EPA-HQ-2010-0964) (Mar. 7, 2011).

Response: The EPA thanks the commenter for their support. With consideration of the data 

provided by commenters on the proposed rule, the EPA is finalizing the confidentiality 

determinations as proposed for all but 7 of the new and substantially revised data elements that 

were proposed. See Section III.B of the preamble to the final rule for additional information

related to confidentiality determinations.

Commenter Name: Brian Korpics

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2011-0512-0087-A2

Comment Excerpt Number: 3

Comment: The Agency has conducted specific analyses and made individual determinations on 

11 data elements, recognizing that “similar data elements may not always have the same 

confidentiality status.”16 On this basis, EPA correctly concluded that these 11 data elements are 

not confidential business information because the information being reported is already publicly 

available.

16 79 Fed. Reg. at 13,406. The 11 data elements can be found in Table 3 of the proposed rule. Id. 

at 13,419.

Response: The EPA thanks the commenter for their support. With consideration of the data 

provided by commenters on the proposed rule, the EPA is finalizing the confidentiality 

determinations as proposed for all but 4 of the new and substantially revised data elements in 

Table 3 of the preamble to the proposed rule. See responses to comments EPA-HQ-OAR-2011-

0512-0084-A2, Excerpts 139, 140, 141, and 142 and Section III of the preamble to the final rule 

for additional information about the decisions to change the confidentiality determinations for 

the 4 data elements.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 19

Comment: Kinder Morgan supports classifying proposed § 98.236(d)(1)(iv) (Whether any CO2

emissions from the acid gas removal unit are recovered and transferred outside the facility)) as 

CBI. The Agency has not made a prior CBI determination on this specific data element, and is 

proposing to classify it as "Not CBI." However, this specific data element is directly linked to 

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multiple data elements associated with industrial CO2 production plants and importers/exporters 

of CO2 that have been previously determined to be CBI under 40 CFR 98, Subpart PP.5

FOOTNOTE:

5 These multiple data elements generally fall in the category of annual CO2 mass in metric tons 

supplied or exported to a container or downstream location. Since the reporting of this item 

under Subpart W effectively requires the reporter to also report the annual quantity of CO2 in 

metric tons that was recovered and transferred outside the facility, this item should also receive 

the same CBI treatment that was established under Subpart PP for the reporting of the annual 

quantity of CO2 in metric tons. See Confidentiality Determinations for Data Required Under the 

Mandatory Greenhouse Gas Reporting Rule and Amendments to Special Rules Governing 

Certain Information Obtained Under the Clean Air Act, Final Rule, 76 FR 30782 (May 26, 

2011).

Response: The final amendments revise §98.236(d)(1)(iv) to be consistent with 

§98.236(c)(3)(iv) of the current rule. Specifically, the final amendments state that the quantity of 

CO2 emissions from acid gas removal units that are recovered and transferred offsite must be 

reported under subpart PP; the proposed amendments inadvertently removed the requirement to 

report under subpart PP. See Section III.B of the preamble to the final rule for a discussion of the 

EPA’s determination that the requirement to indicate whether CO2 emissions are recovered from 

acid gas removal units and transferred offsite is not CBI.

Commenter Name: Glen Jasek

Commenter Affiliation: Williams Partners, LP

Document Control Number: EPA-HQ-OAR-2011-0512-0091-A2

Comment Excerpt Number: 16

Comment: Proposed EPA Amendment: Among other additional data elements being requested 

for centrifugal and reciprocating compressors in 40 CFR 98.236 (o) and (p), EPA is seeking the 

following information:

• Compressor power rating (hp);

• Year compressor was installed;

• Compressor model name and description;

• Date of last maintenance shutdown that compressor was depressurized.

We view this data to be confidential business information (CBI).

Response: As discussed in the response to comment EPA-HQ-OAR-2011-0512-0085-A2, 

Excerpt 2 of section 21 of this document and Section II.E.2 of the preamble to the final rule, the 

EPA has made several changes to the compressor data elements for the final rule. First, we 

removed the installation year and compressor model name and description data elements from 

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the final rule. Second, the compressor power rating has been replaced with a requirement to 

report the “power output of the compressor driver.” Third, we replaced the reporting 

requirement for the date of the last maintenance shutdown with a simple indication of whether 

the compressor had a scheduled depressurized shutdown during the reporting year.

The EPA has determined that the power output of the compressor driver should not be CBI 

because such information is generally publicly available in operating and construction permits 

and in FERC documents. An indication of whether a scheduled depressurized shutdown of the 

compressor occurred during the reporting year is not already public; however, it provides no 

insight into the length of the shutdown, the reason for the shutdown, or the timing of future 

shutdown events. It also provides no information on emergency shutdowns for malfunctions. 

Furthermore, facilities frequently have backup compressors so that there will be no service 

disruption during maintenance and repair periods. The commenter did not explain why these 

specific data elements were considered sensitive, nor explain how they could be used by 

competitors to harm their company. Since we know of no reasons why these data elements would 

cause competitive harm, the EPA is finalizing the determinations that the two revised data 

elements are not CBI.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 37 and 67

Comment: Confidentiality: EPA fails to understand the competitive nature of the natural gas 

transmission industry when determining whether particular data elements should be considered 

confidential business information (CBI).

EPA’s decision to not designate T&S data as CBI is based, at least in part, on its understanding 

that the transmission industry is inherently less competitive than other industries. EPA’s 

understanding is indicated in text from the preamble that explains the CBI determination for 

many transmission data elements:

"Companies operating in this (natural gas transmission compression sector) sector are subject to 

regulatory oversight by the Federal Energy Regulatory Commission (FERC), state utility 

commissions, and other federal agencies because they operate in an industry that is inherently 

uncompetitive. FERC controls pricing, sets rules for business practices, has the power to 

impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the 

location, construction and operations of companies operating in this sector. The rate charged for 

transporting gas is regulated. Hence the tightly regulated natural gas transmission sector is 

inherently less competitive than other industries."

EPA’s understanding that the natural gas transmission industry is inherently less competitive 

than other industries is not correct. While interstate natural gas pipeline rates are established on a 

cost-of-service basis by the Federal Energy Regulatory Commission (FERC), the natural gas 

pipeline transportation market is quite competitive. In the mid 1980s, FERC began a major 

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restructuring of pipeline companies’ services, with the ultimate goal of enabling consumers to 

purchase gas directly from producers in a competitive market for natural gas. Since the mid 

1990s, when FERC issued Order 636, the unbundling of pipelines’ merchant and transportation 

services has been mandatory. The competitive culture fostered by Order 636 has replaced the 

public utility culture of the pre-restructuring natural gas industry. Pipelines face multiple forms 

of competition which affect service offerings and prices, including: competition with alternative 

fuels, competition between gas supply basins, competition among pipelines, and increased 

competition with firm shippers who can sell their excess capacity on a secondary market. Given 

the competitive alternatives that customers enjoy, a pipeline’s FERC-approved maximum tariff 

rate is not an entitlement to collect such a rate. Rather, a pipeline’s pricing power is disciplined 

by what the market will bear. As a result, a significant portion of interstate pipeline throughput is 

being transported at rates that have been discounted from the FERC-approved maximum tariff 

rates or under agreements where the pipeline and its customer have negotiated an alternative rate 

design and rate level. As a result, small changes in the delivered price of natural gas can affect 

competitiveness so it is imperative for pipelines to manage costs because there is no guarantee of 

cost recovery. If a pipeline’s costs become too high, a customer could take its business to a 

competitor once its contract expires. The natural gas pipeline market is indeed competitive and 

INGAA urges EPA to recognize this.

EPA refers to public information available for natural gas companies subject to the jurisdiction 

of FERC because FERC Forms 2, 2-A, and 3-Q must be submitted. These reports are designed to 

collect financial and operational information, and are considered to be non-confidential public 

use forms. However, these forms do not contain all of the equipment, process, and operating data 

regarding industry operations and practices, and do not include all proposed Subpart W data 

elements. Thus, the confidentiality determinations for these data elements should consider 

whether disclosure of the data is likely to cause substantial harm to a natural gas transmission 

company’s competitive position.

Response: For the reasons discussed in Section III.B of the preamble to the final rule, the EPA 

has decided to change the confidentiality determinations for the data elements in 

§98.236(aa)(4)(i), (iv) and (v) due to concerns that these data elements provide information on 

the quantity of gas transported by a specific pipeline and these data may potentially cause 

competitive harm to some pipeline companies operating in more competitive market areas.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 1 and 20

Comment: Contrary to EPA’s perception, the natural gas industry is a very competitive 

industry. Each company competes with other companies to attract shipper commitments to 

provide natural gas transportation, processing and storage services to meet producer, industrial 

and residential customer needs and demands.

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Kinder Morgan and other natural gas pipeline companies compete against one another and 

cannot automatically pass on regulatory costs to their customers. Even though Kinder Morgan 

operates pipelines subject to regulatory oversight by the Federal Energy Regulatory Commission 

(FERC) and other federal and state agencies, Kinder Morgan operates in markets in which other 

natural gas pipeline companies regularly compete for pipeline business through discounting and 

other competitive market practices. Rate proceedings to establish shipping rates for an interstate 

natural gas pipeline do not occur annually, and typically occur only once every several years. 

Thus, new costs incurred between rate cases – such as increased regulatory costs caused by new 

regulation – cannot be automatically added to the shipping rate and are instead born by the 

pipeline company. Any contention that Kinder Morgan and other interstate natural gas pipeline 

companies "operate in an industry that is inherently uncompetitive" is mistaken.2

EPA’s failure to designate natural gas industry data as CBI is based in part on the faulty 

assumption that the natural gas transmission industry is "inherently uncompetitive" or 

"inherently less competitive than other industries."3 As noted above, the natural gas industry is 

very competitive. The release of specific compressor throughput, gas storage injection and 

withdrawal, LNG import and export volume and other specific operational data could provide 

competitors and gas marketers with market sensitive information that could result in substantial 

harm to a pipeline operator’s competitive position.

FOOTNOTE:

2 See, e.g., Proposed Rule at 13411.

3 See id.

Response: See the response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpts 37 and 

67 of this section and Section III.B of the preamble to the final rule for the EPA’s response to 

this comment.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 2

Comment: As noted in detail in API and INGAA’s comments, EPA’s proposed confidentiality 

determinations conflict with determinations made in prior versions of Subpart W as well as in 

other subparts of Part 98. In several instances, EPA is changing classifications for data that it 

previously deemed CBI without justifying its decision to reclassify the data. Examples include 

the proposed confidentiality determinations for annual quantities of gas transported through a 

compressor station (proposed § 98.236(aa)(4)(i)); gas injected into and withdrawn from 

underground natural gas storage (proposed § 98.236(aa)(5)(i) and (ii)); and LNG imported or 

exported (proposed § 98.236(aa)(6) and (7)). For each of these proposed confidentiality 

determinations, Kinder Morgan supports INGAA’s comments calling for the classification of 

such data as CBI, and notes that EPA had already made a CBI determination that encompasses 

the data element in the current § 98.236(d).4

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Footnotes:

4 "Memorandum-Final Data Category Assignments and Confidentiality Determinations for the 

2012 Final CBI Rule," Lisa Bacanskas, EPA, Climate Change Division, Docket ID No. EPAHQ-OAR-2011-0028-0031 (Aug. 1, 2012), Table 1 at 14.

Response: In the proposal, we indicated that the existing reporting section had been reorganized 

and some of the reporting requirements were removed from the rule. The requirement in 

§98.236(d) of the current rule to report throughput for each industry segment is one of the data 

elements removed from the rule. This data element has been replaced by new reporting 

requirements that are specific to each industry segment. During the development of the proposal, 

the EPA evaluated each of the new data elements, proposed determinations based on this new 

evaluation, and sought comment on our proposed determinations. The EPA now is making final 

determinations taking into consideration all stakeholder comments.

As discussed in detail in Section III.B of the preamble, the EPA has reviewed the subpart W 

determinations with those made for other subparts and identified two subpart NN data elements 

with CBI determinations that are inconsistent with those proposed for subpart W. Those data 

elements are the quantity of gas received at a gas processing plant (reported under 

§98.236(aa)(3)(i)) and the quantity of natural gas withdrawn from storage (reported under 

§98.236(aa)(5)(i)). Review of publicly available data undertaken during the preparation of the 

proposal for this action found that the quantity of natural gas withdrawn from storage is publicly 

available through the EIA website and is therefore not entitled to confidential treatment under 40 

CFR 2.208. As a result, we are finalizing the proposed determination that the quantity of natural 

gas withdrawn from storage and reported under §98.236(aa)(5)(i) is not CBI. The quantity of gas 

received at gas plants also is publicly available from EIA. However, the data are available only 

every third year. Thus, for reasons discussed in Section III.B of the preamble to the final rule, we 

are changing the determination for §98.236(aa)(3)(i) from “not CBI” to “CBI.”

The gas withdrawn from underground natural gas storage (proposed §98.236(aa)(5)(ii)) is 

publicly available from EIA, and the monthly quantities of LNG imported or exported (proposed 

§98.236(aa)(6) and (7)) are publicly available in quarterly reports issued by the Office of Fossil 

Energy in the Department of Energy. Thus, these data elements are not entitled to confidential 

treatment under 40 CFR 2.208.

See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpts 37 and 67 of this 

section and Section III.B of the preamble to the final rule for a discussion of the EPA’s revised 

determination for §98.236(aa)(4)(i).

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 38

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Comment: EPA should more thoroughly review the CBI status of T&S data elements. Several 

data elements should be considered CBI.

The Proposed Rule does not designate any data elements for the T&S segments as CBI. This is 

due, in part, to EPA’s mistaken belief that the T&S segments are not competitive. Because of 

this faulty logic, T&S data CBI determinations discussed in the preamble should be revisited. 

INGAA recommends that EPA consider classifying several data elements as CBI. In some cases, 

EPA has already required reporting, but a non-CBI determination was not documented. The

following data elements are all stand-alone parameters that are not required in any equations or 

methods for estimating GHG emissions, and their purpose is not defined. In each case, the 

parameter divulges important information on production, operations, or key process equipment. 

INGAA recommends EPA re-evaluate its classification as CBI based on a thorough review 

following defined procedures and based on a competitive business environment for T&S data 

elements, including:

• Annual quantity of gas transported through the transmission compressor station, 

§98.236(aa)(4)(i);

• Annual quantity of gas injected and withdrawn into underground natural gas storage, 

§98.236(aa)(5)(i) and (ii);

• Annual quantity of LNG imported and exported for LNG import and export equipment, 

§98.236(aa)(6) and (7);

• Several parameters that have been added to reporting requirements are discussed in Comment 

17, including compressor power rating (hp), year the compressor was installed, compressor 

model name and description, and date of last maintenance. These parameters should also be 

considered for classification as CBI, especially maintenance related data elements.

Response: See response to comment EPA-HQ-OAR-2011-0512-0081-A1, Excerpts 37 and 67 

in this section for information regarding §98.236(aa)(4)(i). 

See response to comment EPA-HQ-OAR-2011-0512-0077-A1, Excerpt 2 of this section and 

Section III.B of the preamble to the final rule for information regarding data elements in 

§98.236(aa)(5)(i), (5)(ii), (6), and (7).

See response to comment EPA-HQ-OAR-2011-0512-0091-A2, Excerpt 16 of this section for the 

response to the comment regarding compressor data elements.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 139

Comment: Proposed Citation Reference: §98.236(aa)(3) and (aa)(3)(i), Proposed Rule Text: (3) 

For natural gas processing, report the quantities specified in paragraphs (aa)(3)(i) through 

226
(aa)(3)(vii) of this section. (i) The quantity of produced gas received at the gas processing plant 

in the calendar year, in thousand standard cubic feet.

Comment: EPA determined this data to be CBI under 40 CFR 98 Subpart NN (98.406(a)(3)) per 

76 FR 30782, 5/26/2011 (Annual volumes of natural gas received for processing). Even though 

the terminology is slightly different between Subpart W and Subpart NN, the “quantity of 

produced gas received at the gas processing plant” vs. “annual volumes of natural gas received 

for processing” are essentially the same data so it should likewise be treated as CBI under 

Subpart W as it was determined under Subpart NN.

Response: For the reasons discussed in the response to comment EPA-HQ-OAR-2011-0512-

0077-A1, Excerpt 2 of this section and Section III.B of the preamble to the final rule, the EPA is 

changing the determination for §98.236(aa)(3)(i) from “not CBI” to “CBI.”

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 141

Comment: Proposed Citation Reference: §98.236(aa)(3)(iii), Proposed Rule Text: The quantity 

of NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in 

barrels

EPA determined this data to be CBI under 40 CFR 98 Subpart NN (98.406(a)(4) and (a)(4)(i)) 

per 76 FR 30782, 5/26/2011 and 78 FR 71904, 11/29/2013 (Annual Quantity (in barrels) of ygrade, o-grade, and other bulk NGLs received). Even though the terminology and the type of 

NGLs being aggregated is slightly different between Subpart NN and Subpart W, it is still 

considered NGLs received at the facility so it should still be retained as CBI under Subpart W as 

it was determined under Subpart NN.

Response: For the reasons discussed in Section III.B of the preamble to the final rule, the EPA 

has decided not to make a confidentiality determination for §98.236(aa)(3)(iii).

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 142

Comment: Proposed Citation Reference: §98.236(aa)(3)(iv), Proposed Rule Text: The quantity 

of NGLs (bulk and fractionated) leaving the gas processing plant in the reporting year (barrels).

EPA determined this data to be CBI under 40 CFR 98 Subpart NN (98.406(a)(4)(ii)) per 78 FR 

71904, 11/29/2013 (Annual Quantity (in barrels) of y-grade, o-grade, and other bulk NGLs 

227
supplied to downstream users that are not fractionated by the reporter). Even though the 

terminology and the type of NGLs being aggregated is slightly different between Subpart NN 

and Subpart W, it is still considered NGLs generated at the facility so it should still be retained 

as CBI under Subpart W as it was determined under Subpart NN.

Response: For the reasons discussed in Section III.B of the preamble to the final rule, the EPA 

has decided not to make a confidentiality determination for §98.236(aa)(3)(iv).

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 1

Comment: 1. Quantity of produced gas received at the gas processing plant: Section 

98.236(aa)(3)(i) requires affected sources to report the quantity of produced gas received at the 

gas processing plant in the calendar year. EPA proposes that this information should not be CBI. 

Yet, EPA determined this data to be CBI under Subpart NN (98.406(a)(3)). Even though the 

terminology is slightly different between Subpart W and Subpart NN, the "quantity of produced 

gas received at the gas processing plant" and "annual volumes ... of natural gas received for 

processing" are essentially the same data. Therefore, this data should be considered CBI under 

Subpart W, as it is under Subpart NN.

2. Quantity of NGLs (bulk and fractionated) received at the gas processing plant: Section 

98.236(aa)(3)(iii) requires affected sources to report the quantity of NGLs (bulk and 

fractionated) received at the gas processing plant in the calendar year. EPA proposes that this 

information should not be CBI. Yet, EPA determined these data to be CBI under Subpart NN 

(98.406(1)(2), (a)(4) and (a)(4)(i)). Even though the terminology and the type of NGLs being 

aggregated are slightly different between Subpart NN and Subpart W, both constitute NGLs 

received at the facility. This information should be retained as CBI under Subpart W, as it is 

under Subpart NN.

3. Quantity of NGLs (bulk and fractionated) leaving the gas processing plant: Section 

98.236(aa)(3)(iv) requires affected sources to report the quantity of NGLs (bulk and fractionated) 

leaving the gas processing plant in the calendar year. EPA proposes that this information should 

not be CBI. Yet, EPA determined these data to be CBI under Subpart NN (98.406(a)(1), (a)(4), 

and (a)(4)(ii)). Even though the terminology and the type of NGLs being aggregated are slightly 

different between Subpart NN and Subpart W, both constitute NGLs leaving the facility. This 

information should be retained as CBI under Subpart W, as it is under Subpart NN.

Response: See response to comment EPA-HQ-OAR-2011-0512-0077-A1, Excerpt 2 of this 

section; responses to comments EPA-HQ-OAR-2011-0512-0084-A2, Excerpts 139, 141, and 142

of this section; and Section III.B of the preamble to the final rule for the EPA’s response to this 

comment.

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Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 140

Comment: Proposed Citation Reference:§98.236(aa)(3)(ii), Proposed Rule Text: The quantity 

of processed (residue) gas leaving the gas processing plant in the calendar year, in thousand 

standard cubic feet.

Although the EPA did not make a prior CBI determination for this data element under Subpart 

NN there is no explanation why this data element needs to be reported under Subpart W and why 

it is designated as not-CBI.

Response: The data element identified by the reporter will be used for verification of annual 

reports. For reasons discussed in section III.B of the preamble to the final rule, the EPA is 

changing the confidentiality determination for §98.236(aa)(3)(ii) from “not CBI” to “CBI”. 

Commenter Name: Jeff Applekamp

Commenter Affiliation: Gas Processors Association (GPA)

Document Control Number: EPA-HQ-OAR-2011-0512-0089-A3

Comment Excerpt Number: 2

Comment: Quantity of processed (residue) gas leaving the gas processing plant: Section 

98.236(aa)(3)(ii) requires affected sources to report the quantity of processed (residue) gas 

leaving the gas processing plant in the calendar year. There is no explanation for why this data 

element needs to be reported under Subpart W and minimal explanation as to why it is 

designated as non-CBI. In Table 3 of the proposed rule, EPA claims that this data is "published 

quarterly on EIA’s Website." But it appears that plant-specific processing capacity information is 

supplied to EIA via Form EIA-757, which, according to the General Instructions on the form, is 

"collected from all processing plants at most once every 3 years." For lack of justification to treat 

this data as non- CBI, it should be retained as CBI.

Response: See the response to the comment EPA-HQ-OAR-2011-0512-0084-A2, excerpt 140 

in this section for the response to the comment regarding reporting the quantity of residue gas 

leaving the natural gas plant (§98.236(aa)(3)(ii)). 

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 3

Comment: Kinder Morgan also supports API’s comments requesting that the following 

proposed new data elements under Subpart W be classified as CBI to be consistent with prior 

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CBI determinations made under Subpart NN: the annual quantities of produced gas received at 

the gas processing plant (proposed § 98.236(aa)(3)(i)(A)); processed (residue) gas leaving the 

gas processing plant (proposed § 98.236(aa)(3)(ii)); NGLs (bulk and fractionated) received at the 

gas processing plant (proposed § 98.236(aa)(3)(iii)); and NGLs (bulk and fractionated) leaving 

the gas processing plant (proposed § 98.236(aa)(3)(iv)).

Response: See the responses to comments EPA-HQ-OAR-2011-0512-0084-A2, Excerpts 139, 

140, 141, and 142 of this section; and Section III.B of the preamble to the final rule for EPA’s 

response to this comment. 

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 16

Comment: Conformance of Confidentiality Determinations amongst GHGRP Subparts. 

API has identified several data reporting elements in §98.236(aa)(3)(i) through (aa)(3)(vii) that 

are proposed as ‘not-CBI’ under Subpart W at the same time that they have been designated as 

‘CBI’ under Subpart NN of the GHGRP. Details regarding these data items are provided below 

in the technical comments. API expects that EPA will afford the same CBI protections to specific 

data elements in all Subparts of the GHGRP. We request EPA conduct a conformity review to 

ensure that data elements receive the same CBI designation in various parts of the GHGRP.

Response: See the responses to comments EPA-HQ-OAR-2011-0512-0084-A2, Excerpts 139, 

140, 141, and 142 of this section; and Section III.B of the preamble to the final rule for a 

discussion of the EPA’s review of the confidentiality determinations for data elements in 

subparts W and NN.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 30

Comment: Conformance of Confidentiality Determinations amongst GHGRP Subparts. As 

discussed above, API has identified several data reporting elements in §98.236 (aa)(3)(i) through 

(aa)(3)(vii) that are proposed as “not-CBI” under Subpart W while at the same time they have 

been designated as “CBI” under Subpart NN of the GHGRP. Details regarding these data items 

are provided below in the technical comments. In order to avoid arbitrary and capricious 

treatment of information, EPA must afford the same CBI protections to specific data elements in 

all Subparts of the GHGRP. Moreover, EPA should conduct a conformity review to ensure that 

data elements are designated CBI in a consistent manner in various parts of the GHGRP.

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Response: See the responses to comments EPA-HQ-OAR-2011-0512-0084-A2, Excerpts 139, 

140, 141, and 142 of this section; and Section III.B of the preamble to the final rule for a 

discussion of the EPA’s review of the confidentiality determinations for data elements in 

subparts W and NN.

Commenter Name: Thomas J. Bach

Commenter Affiliation: Kinder Morgan Energy Partners, L.P

Document Control Number: EPA-HQ-OAR-2011-0512-0077-A1

Comment Excerpt Number: 4

Comment: Kinder Morgan also supports the CBI conformity request proposed by API to 

establish consistency in CBI determinations across all Subparts of the Greenhouse Gas Reporting 

Program (GHGRP).

Response: See the responses to comments EPA-HQ-OAR-2011-0512-0084-A2, Excerpts 139, 

140, 141, and 142 of this section; and Section III.B of the preamble to the final rule for a 

discussion of the EPA’s review of the confidentiality determinations for data elements in 

subparts W and NN.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 135

Comment: Proposed Citation Reference: §98.236(aa)(2) and (aa)(2)(i), Proposed Rule Text:(2) 

For offshore production, report the quantities specified in paragraphs (aa)(2)(i) through 

(aa)(2)(iii) of this section. (i) The quantity of gas produced from the offshore platform in the 

calendar year for sales, in thousand standard cubic feet.

Comment: This is a CBI concern. This information is typically not disclosed for individual 

platforms.

Response: For the reasons discussed in the response to comment EPA-HQ-OAR-2011-0512-

0084-A2, Excerpt 90 in Section 21.0 of this document, the EPA is revising the proposed 

requirement to report the quantity of gas produced with a requirement to report the quantity of 

gas handled at the offshore platform. The finalized data element is consistent with BOEM 

reporting requirements. This quantity is also publicly available from BOEM, which means it is 

not entitled to confidential treatment under 40 CFR 2.208. Thus, as part of this action we are 

finalizing our determination that the revised data element in §98.236(aa)(2)(i) is not CBI.

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Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 136

Comment: Proposed Citation Reference: §98.236(aa)(2)(ii), Proposed Rule Text: The quantity 

of oil produced from the offshore platform in the calendar year for sales, in barrels

This is a CBI concern. This information is typically not disclosed for individual platforms.

Response: For the reasons discussed in the response to comment EPA-HQ-OAR-2011-0512-

0084-A2, Excerpt 90 in Section 21.0 of this document, the EPA is replacing the proposed 

requirements to report the amount of oil produced (proposed §98.236(aa)(2)(ii)) and the amount 

of condensate produced (proposed §98.236(aa)(2)(iii)) with a single requirement to report the 

combined total quantity of oil and condensate handled at the offshore platform (final 

§98.236(aa)(2)(ii)). The finalized data element is consistent with BOEM reporting requirements. 

This quantity is also publicly available from BOEM, which means it is not entitled to 

confidential treatment under 40 CFR 2.208. Thus, as part of this action we are finalizing our 

determination that the data element in §98.236(aa)(2)(ii) is not CBI.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 138

Comment: Proposed Citation Reference: §98.236(aa)(2)(iii), Proposed Rule Text: The quantity 

of condensate produced from the offshore platform in the calendar year for sales, in barrels.

This is a CBI concern. This information is typically not disclosed for individual platforms

Response: For the reasons discussed in the response to comment EPA-HQ-OAR-2011-0512-

0084-A2, Excerpt 90 in Section 21.0 of this document, the EPA is replacing the proposed 

requirements to report the amount of oil produced (proposed §98.236(aa)(2)(ii)) and the amount 

of condensate produced (proposed §98.236(aa)(2)(iii)) with a single requirement to report the 

combined total quantity of oil and condensate handled at the offshore platform (final 

§98.236(aa)(2)(ii)). The finalized data element is consistent with BOEM reporting requirements. 

This quantity is also publicly available from BOEM, which means it is not entitled to 

confidential treatment under 40 CFR 2.208. Thus, as part of this action we are finalizing our 

determination that the data element in §98.236(aa)(2)(ii) is not CBI.

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22.3 Comments on evaluation of inputs to emissions equations for new or 

revised data elements

Commenter Name: V. Bruce Thompson

Commenter Affiliation: American Exploration & Production Council (AXPC)

Document Control Number: EPA-HQ-OAR-2011-0512-0085-A2

Comment Excerpt Number: 3

Comment: AXPC and the Alliance understand that many of the data inputs that were previously 

not reported due to confidential business considerations will now have to be reported for 

previous and current reporting years. However, as noted above, the transition to a new and 

unknown reporting format, along with the additional data gathering and management 

modifications will take time to implement. As proposed, as soon as these changes are made and 

implemented, reporters would have to make additional modification for reporting year 2015 

forward. This short timeframe is unreasonable, particularly considering that the rule is expected 

to be finalized near the end of 2014 and reporters would need to have data gathering systems and 

processes in place starting at the first of the year, 2015. As such, we request that EPA allow for 

additional implementation time and believe that it is reasonable for operators to report 2011‐

2015 inputs in 2016 and 2016 inputs and modified emission calculations in 2017.

Response: We disagree with the commenter's request to delay reporting of data elements that 

are inputs to emission calculation equations and have been deferred from reporting in reporting 

years 2011 through 2013. As discussed in the preamble to a separate rulemaking action (insert 

citation to final inputs rule FR notice) we recognize that a substantial number of inputs must be 

back-reported for these years. To facilitate this process, the EPA has developed a reporting form 

that will be used to collect the back-reported inputs data and a reporting form for the 2014 

reporting year. Both forms have been made available for stakeholder review. This allows

facilities to become familiar with the data entry prior to the March 2015 reporting deadline. In 

light of this, we have determined that there is sufficient time to complete both back-reporting 

inputs data for previous reports and the reports for reporting year 2014. The EPA also notes that 

in the final rule, we are providing a transitional BAMM period for emission sources that are 

subject to new monitoring or measurement requirements as part of these final revisions. See 

Section II.D of the preamble to the final rule for additional discussion regarding BAMM.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 29

Comment: Potential Antitrust Concerns. As API has made clear to EPA in earlier comments 

– including the November 2013 comments submitted to EPA that are attached and incorporated 

herein by reference – if EPA fails to take sufficient action to protect public disclosure of 

confidential inputs data outside the proper definition of “emission data,” significant antitrust 

concerns may arise. As the Federal Trade Commission (FTC) has made clear to EPA, failing to 

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protect confidential “inputs to emissions equations” data elements from disclosure could trigger 

antitrust concerns and violate the principle of aggregation. EPA must avoid imposing a 

requirement to disclose data beyond that which is properly classified as “emission data” because 

such disclosure is inconsistent with statutory requirements and policies promoting competition.

The data elements of concern include cost- and output-related information that is a significant 

determinant of prices including information regarding fuel production and distribution (which 

provides details about inputs, nature and location of sources, and plant operations). The antitrust 

laws generally prohibit competitors from sharing price, output, and other information that may 

facilitate anticompetitive coordination in prices or production and thereby harm consumers. The 

exchange of price information is of particular concern.7 See United States v. Container Corp. of 

America, 393 U.S. 333 (1969); see also Federal Trade Commission (FTC) FTC Guide to the 

Antitrust Laws http://www.ftc.gov/bc/antitrust/factsheets/antitrustlawsguide.pdf. Because the 

Antitrust laws prohibit agreements to restrict output, see United States v. Andreas, 216 F.3d 645, 

666-69 (7th Cir. 2000), a similar set of antitrust concerns apply to information-sharing (tacit or 

explicit) that may facilitate coordinated output decisions.

Thus, any public disclosure of confidential and sensitive business information beyond strictly 

“emission data” would violate well-settled principles that shared data should be “sufficiently 

aggregated” and should “not allow recipients to identify” the competitive information of “any 

particular provider.” Without such safeguards, producers are more likely to learn the specifics of 

individual competitors’ ongoing operations. Such knowledge could impact prices and/or output 

and the risk of causing competitive harm increases because some sensitive aspects of fuel 

production may persist over time.

EPA’s proposed rule fails to address these concerns. As discussed above, EPA must confirm that 

any elements it deems confidential are not “emission data.” Otherwise, such data elements might 

be available for disclosure to the public.8 As the FTC has explained, because numerous 

industries subject to the GHGRP share various market conditions, “making confidential business 

information (CBI) public may lead to collusion that harms consumers through higher prices, 

decreased quality, and decreased innovation.” Comments of the Federal Trade Commission, 

September 30, 2010 at 2. More specifically, the FTC expressly highlighted its concerns about 

EPA’s proposed release of “inputs to emission equations” and other sensitive data elements 

explaining that:

"Three categories of data that the EPA proposes to make public contain potentially sensitive 

competitive business information: “inputs to emission equations,” “unit process ‘static’ 

characteristics that are not inputs to emission equations,” and “unit/process operating 

characteristics that are not inputs to emission equations.” These three categories include data on 

production, throughput, raw material consumption, capacity, and future operations. Public 

disclosure of such facility- and firm-specific sensitive business information may make it easier 

for reporting companies to either tacitly or explicitly coordinate their pricing decisions. This is 

especially true when certain market conditions are present such as transparency, high 

concentration, impediments to entry, homogenous products, and low elasticity of demand. See 

Comments of the FTC (emphasis added; internal footnotes omitted).

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As a result of its concerns, the FTC recommended that EPA treat all “inputs to emission 

equations” data elements as confidential. Id. Because the FTC is the federal agency specifically 

charged with maintaining competition and safeguarding the interests of consumers, we urge EPA 

to be particularly deferential of its advice regarding the serious need to take adequate steps to 

avoid disclosing sensitive data. API continues to urge EPA to follow the FTC’s 

recommendations and provide CBI protection to: (1) all “inputs to emission equations” 

particularly where there is not a sufficient record upon which to determine how EPA excluded 

some inputs as confidential; and (2) information regarding exploratory wells which must be 

protected from disclosure (which is discussed further below in D.4 and D.5).

Footnotes: 

7 The antitrust laws are designed to promote and preserve the competitive private enterprise 

system by encouraging free and open competition and the fairest distribution of high quality 

goods and services at the lowest possible prices. The basic provisions of the antitrust laws are 

found in the Sherman Act, Clayton Act, Robinson-Patman Act, and the Federal Trade 

Commission Act. Distilled, these Acts oblige regulated entities to ensure that they do not discuss 

or exchange information with their competitors on issues such as prices to be charged, division 

or allocation of markets or customers, distribution of products, profit levels, production of 

products or level of production, bases for determining prices, and exchanges of price information 

to certain customers, among other issues. Violations of these Acts can lead to imprisonment, 

fines, court-issued injunctions, treble damage awards, and state penalties. As noted supra, the 

FTC submitted comments in EPA’s CBI rulemaking and took the position that EPA’s proposed 

rule “may allow for the public release of competitively sensitive information” and, in particular, 

pointed to data under three categories that were at high risk and warranted confidential 

protection: “inputs to emission equations,” “unit/process ‘static’ characteristics that are not 

inputs to emission equations,” and “unit/process operating characteristics that are not inputs to 

emission equations.” See FTC Comments at 6. With respect to “inputs to emission equations,” 

the FTC pointed out that “inputs to emission equations” include annual fuel combustion volume, 

production/throughput and raw material consumption (such as petrochemical production), 

characteristics of raw materials, products, and by-products, and facility operating information 

which, if not characterized as “emission data,” would otherwise be CBI.

8 In API’s September 7, 2010 comments, API members expressed concern that some of the 

Suppliers’ reporting requirements could reveal process-specific information and production 

volumes, thus providing competitors with data about sensitive process capabilities and 

operational limits and market capabilities and engagements. For these reasons, API has 

previously stated that petroleum fuel refiners, importers, and exporters should not have to report 

on petroleum feed stock and product volumes or unit-specific GHG emissions and process data 

to EPA unless assured the confidentiality of these data.

Response: Section 114(c) of the Clean Air Act requires EPA to make information publicly 

available unless it is CBI. It precludes “emission data” from being protected as CBI. Therefore, 

“emission data” must be publicly available even if they are CBI. In this rulemaking, EPA 

categorized several data elements as “emission data” based on the definition of the term at 40 

CFR 2.301(a)(2)(i). EPA carefully construed the regulatory definition to include only those data 

elements necessary to determine the emission information specified in 40 CFR 2.301(a)(2)(i)(A) 

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or to distinguish one source of emissions from another as required in 40 CFR 2.301(a)(2)(i)(C). 

For data elements that were used to calculate emissions, we evaluated whether those data 

elements could cause potential harm to reporters if they were reported and disclosed. 

For data elements that do not meet the definition of emissions data, we proposed confidentiality 

determinations based on an evaluation of the criteria from the existing CBI regulations at 40 

CFR 2.208. The criteria do not require EPA to assess potential violation or enforcement under 

antitrust law. However, based on 40 CFR 2.208(e)(1), EPA evaluated whether disclosure of data 

elements that are not emission data would be likely to cause competitive harm to the reporter. 

We also solicited comment on our proposed determinations and on our harm analysis for data 

elements used as inputs to emission calculations. We made final determinations after careful 

evaluation of the comments we received.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 27

Comment: API once again reasserts previous legal and technical comments regarding CBI, 

which API submitted to EPA on November 29, 2013. Thus, API incorporates the November 29, 

2013 comments (including legal objections to EPA’s treatment of CBI) by reference hereto and 

also attaches such comments to this comment package.

Response: See the response to comment EPA-HQ-OAR-2012-0512-0084-A2, Excerpt 29 of 

this section.

22.4 Concerns related to exploratory wells

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 28

Comment: Federal law1 and state codes2 specifically allow companies to designate as 

confidential, data obtained from exploratory wells, particularly wells in new discovery areas, or 

areas that are being explored for development. The original intent of state oil and gas 

commissions and federal officials to allow withholding of select drilling and production 

information from early release to the public was to promote competitive exploration by searching 

for new pockets of oil or gas and experimenting with new tools and techniques.

Requiring release of data to the public regarding operating characteristics of such wells, 

including post-flowback flaring/venting volumes, could cause competitive harm if made publicly 

available too early. Industry makes substantial investments in exploration and development 

projects in new areas. These investments in exploration take a long time to characterize the 

magnitude and potential production characteristics of prospective resources. In some areas, 

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companies may spend hundreds of millions of dollars per exploration project, in addition to the 

hundreds of millions of dollars invested to acquire leases. These costs consist of testing the 

prospective area via drilling, analyzing field and laboratory information and determining whether 

it is a viable commercial play. Releasing data to the public too soon on such wells through the 

GHGRP—despite the fact that they are held confidential by other regulatory bodies—could 

cause substantial competitive harm and lead to a loss of investment value.

Competitive advantage includes the ability to shield sensitive information on a company’s 

operations including oil and gas reserve information on new wells, internally developed 

assessments of geologic prospects, drilling plans and interim results. Competitive harm may 

occur if the public can obtain detailed high resolution operational information on a well-by-well 

basis. The success of a well and of a particular play—especially in exploratory areas—could be 

inferred if detailed data is provided to the public too soon during the exploration and assessment 

period, and where according to state and federal laws the data is not already publicly available. 

An example of such an occurrence might be an exploratory well completed in December of the 

reporting year, reported to EPA by end of March of the following year and then released by EPA 

to the public within a few months during the same year.

Footnotes:

1 43 CFR § 3162.8 Confidentiality (a) Information obtained pursuant to this part and on file 

shall be open for public inspection and copying during regular office hours upon a written 

request, pursuant to rules at 43 CFR part 2, except that: (1) Upon request, information obtained 

from an operating rights owner or operator under this part that constitutes trade secrets and 

commercial or financial information which is privileged or confidential or other information that 

may be withheld under the Freedom of Information Act (5 U.S.C. 552(b)), such as geologic and 

geophysical data and maps, shall not be available for public inspection or made public or 

disclosed without the consent of the operating rights owner or operator, as appropriate, for a 

period of 12 months; (2) Upon expiration of the 12-month period, the operating rights owner or 

operator, as appropriate, may request that the data be held confidential for an additional 12-

month period; and (3) Upon termination of a lease, whether by expiration of its terms or 

otherwise, such information shall be made available to the public. [See at 47 FR 47765, Oct. 27, 

1982. Redesignated and amended at 48 FR 36583 - 36586, Aug. 12, 1983, further amended at 49 

FR 37364, Sept. 21, 1984; 53 FR 17364, May 16, 1988]

2

 Alaska State Code (AS 31.05.035) specifies procedures for “Confidential Reports”. Section (c) 

of the Alaska Code recognizes that: “... information required in (a) of this section that relate to 

an exploratory or stratigraphic test well and those portions of an application for a permit to drill 

an exploratory or stratigraphic test well that the commission determines contain proprietary 

engineering or geotechnical information shall be kept confidential for 24 months following the 

30-day filing period unless the owner of the well gives written permission to release the 

application and reports and information at an earlier date.“(ii) Texas Administrative Code (title 

16 part 1 chapter 3, Oil and Gas) states in section (d) of rule 3.16: “(d) Delayed filing based on 

confidentiality. Each log filed with the commission shall be considered public information and 

shall be available to the public during normal business hours. If the operator of a well desires a 

log to be confidential, on or before the 90th day after the date a drilling operation is completed, 

the operator must submit a written request for a delayed filing of the log. When filing such a 

237
request, the operator must retain the log and may delay filing such log for one year beginning 

from the date the drilling operation was completed. The operator of such well may request an 

additional filing delay of two years, provided the written request is filed prior to the expiration 

date of the initial confidentiality period. If a well is drilled on land submerged in state water, the 

operator may request an additional filing delay of two years so that a possible total delay of five 

years may be obtained.”

Response: For five types of situations described in Section III.B of the preamble to the final 

rule, the EPA has determined that early public disclosure of 12 data elements associated with 

wildcat wells and/or delineation wells could reveal the well productivity, thereby resulting in the 

loss of investment value. Thus, the final rule provides an option to delay reporting of these data 

elements for two reporting years. See Section III.B of the preamble to the final rule for a list of 

the situations under which a reporter may delay reporting for two years, the data elements for 

which a reporter may elect to delay reporting, and other requirements associated with this option.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 34

Comment: API Requested Revisions to CBI Proposal. API requests—consistent with state and 

federal laws in oil producing states—that EPA categorically determine that all information (with 

the exception of well ID and location), associated with exploratory wells, is to be classified as 

CBI for a period of at least 24 months. As addressed above, API’s confidentiality concerns for 

exploratory wells are related to the timing of releasing the information to the public. The 

situation of problematic early disclosure would occur acutely where an exploratory well is the 

sole well in a sub-basin category (including vertical or horizontal) and hence is not reported in 

combination with other wells which might help shield any individual well’s contribution. API 

does not expect more than a handful of such wells in any given year.

API proposes that during such a 24 month period EPA provide CBI protection “across the board” 

for reporting for exploratory wells by allowing use of either one of the following two options:

(i) Companies would report all data to EPA as mandated by Subpart W, but EPA will hold the 

reported data as CBI and not include it in its public data release for at least 24 months. This can 

be accomplished by a flagging system (or a “radio button”) in e-GGRT that could also allow for 

a short informative text on why that particular well information is to be maintained confidential; 

or

(ii) Companies would upload into the e-GGRT system only exploratory wells ID and their 

location information and EPA would set up a deferral system where the remaining data would be 

backfilled by companies after a period of 24 months.

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These approaches are workable in practice because they will not require case-by-case review of 

companies’ information, and they are consistent with the approach taken by states’ oil and gas 

commissions and are protective of companies’ commercial investment interests.

In order to be responsive to EPA’s request, API provides in our technical comments section 

specific information on the data elements that API requests should be designated as CBI either 

for an initial 24 months for exploratory wells or held confidential permanently in accordance 

with prior designations in other subparts of the GHGRP. API maintains that EPA should 

promulgate a final rule that affords CBI protection to the specified data elements in order to 

ensure that EPA’s requirements are in compliance with the law regarding protection of 

confidential business information and avoid risking antitrust ramifications for reporting 

companies.

Response: As discussed in the response to comment EPA-HQ-OAR-2011-0512-0084-A2, 

Excerpt 28 of this section, the EPA has determined that early public disclosure of 12 data 

elements associated with wildcat wells and/or delineation wells could reveal the well 

productivity, thereby resulting in the loss of investment value. The EPA also agrees with the 

commenter that a two year delay of reporting is sufficient to prevent early public disclosure. See 

Section III.B of the preamble to the final rule for additional information about the requirements 

of the option to delay reporting for two years.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 15

Comment: Confidentiality of Information for Exploratory Wells. EPA suggests that there is no 

need to protect the confidentiality of exploratory (or “step out”) wells because, according to 

EPA, the disclosure of data for onshore natural gas production at the sub-basin level “would not 

be likely to reveal any proprietary information about the facility or cost to do business.” With 

respect, EPA is simply wrong. By their very nature, exploratory wells are likely to be the only 

wells in a sub-basin/county combination because they are testing new formations in an existing 

area or new areas for hydrocarbon potential. Early release of information specific to exploratory 

wells may cause irreparable and substantive commercial and competitive harm to reporters. API 

believes that a 24 month period of data confidentiality treatment for public disclosure (not 

necessarily to EPA) would resolve issues regarding the release of information that may reveal 

proprietary and/or highly commercially sensitive information to competitors.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, excerpt 28 of this 

section and response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 34 of this 

section.

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Commenter Name: Carrie B. Crumpton

Commenter Affiliation: CONSOL Energy, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0080-A1

Comment Excerpt Number: 2

Comment: CONSOL requests that the EPA reconsider the requirement to report data for 

exploratory wells on the sub-basin level. This information could be considered confidential 

business information and CONSOL requests that this information continue to be reported on the 

basin level.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 28 of this 

section and response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 34 of this 

section.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 26

Comment: EPA should designate exploratory wells information as CBI and should maintain 

consistency of CBI designations amongst the GHGRP Subparts. API commented previously on 

CBI issues and these issues remain critically important. API has made clear that its major 

remaining concern with data confidentiality under Subpart W is the disclosure of information for

exploratory wells, especially when they are located in stepout areas where no prior reporting 

exists for a given sub-basin. We again provide comment on exploratory wells because this issue 

is of critical importance to the industry in order to avoid the disclosure of sensitive, confidential 

and competitive business information prematurely to the public.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 28 of this 

section and response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 34 of this 

section.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 31

Comment: CBI Designations for Newly Proposed and Revised Data Elements. EPA is 

proposing CBI designations for newly proposed and revised data elements based on the 

categorical determinations it has developed previously for determining whether data elements are 

“CBI” or “not CBI” per the 2011 final rule.9 The proposed expansion of the reporting 

requirements to include more detailed information on a daily or monthly basis, and by sub-basin 

240
at the county level, has heightened the concern for the broad classification of such data elements 

as “not CBI” in all circumstances.

These concerns go beyond the previously discussed “inputs to emission equations” and include 

also data elements assigned to two data categories which EPA determined previously have to be 

assessed on “a case-by-case basis.”10

EPA’s assertion that “disclosure of data for onshore natural gas production at the sub-basin 

level would not be likely to reveal any proprietary information about the facility or cost to do 

business,”11 is not universally correct. This assertion ignores that exploratory wells—by their

very nature—are likely to be the only wells in a sub-basin/county combination because they are 

testing new formations, in an existing area, or new areas for hydrocarbon potential. By requiring 

reporting of all of these new data elements, without allowing at least a 24 month period of data 

confidentiality, EPA is requiring the release of information which will reveal proprietary and 

highly commercially sensitive information to competitors -- even when this same information is 

protected under other federal and state laws and regulations.

Footnotes: 

9 76 FR 30782, May 26, 2011, “Proposed Confidentiality Determinations for Data Required 

Under the Mandatory Greenhouse Gas Reporting Rule and Proposed Amendment to Special 

Rules Governing Certain Information Obtained Under the Clean Air Act.”

10 Alexis McKittrick and Mark De Figueiredo, EPA/CCD, EPA-HQ-OAR-2011-0512-0060, 

February 20, 2014.

11 Alexis McKittrick and Mark De Figueiredo, EPA/CCD, EPA-HQ-OAR-2011-0512-0064, 

February 20, 2014.

Response: See response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 28 of this 

section and response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 34 of this 

section.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 99

Comment: Proposed Citation Reference for Completions and Workovers with Hydraulic 

Fracturing: §98.236(g) and (g)(1), Proposed Rule Text: (g)...If your facility had gas well 

completions or workovers with hydraulic fracturing during the calendar year, then you must 

report information specified in paragraphs (g)(1) through (g)(10) of this section, for each subbasin and well type combination. Report information separately for completions and workovers. 

(1) Subbasin ID.

241
This is a CBI issue for exploratory wells where a new formation type or area is being evaluated. 

This information should remain confidential for a minimum of 24 months.

Response: As discussed in Section III.B of the preamble to the final rule, the EPA disagrees that 

the sub-basin ID should remain confidential for two years. The sub-basin ID (reported under 

§98.236(g)(1), (h)(1)(i), (h)(2)(i), and (m)(1)) and number of wells can be discerned from the 

well IDs, which are publicly available for all wells and provide the location of the well and the 

name of the drilling company. Since the location of the well can be discerned from the well ID, 

the type of formation (reported under §98.236(aa)(1)(ii)(C)) can be determined through publicly 

available information such as U.S. Geological Survey reports. Therefore, the EPA is finalizing as 

proposed the determination that the sub-basin ID is not CBI.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 105

Comment: Proposed Citation Reference for Completions and Workovers without Hydraulic 

Fracturing: §98.236(h), (h)(1), and (h)(1)(i), Proposed Rule Text: (h)...If the facility had gas 

well completions or workovers without hydraulic fracturing, then you must report the 

information specified in paragraphs (h)(1) through (h)(4) of this section, as applicable. (1) For 

each sub-basin with gas well completions without hydraulic fracturing and without flaring, report 

the information specified in paragraphs (h)(1)(i) through (h)(1)(vi) of this section. (i) Sub-basin 

ID

This is a CBI issue for exploratory wells where a new formation type or area is being evaluated. 

This information should remain confidential for a minimum of 24 months.

Response: See the response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 99 of 

this section.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 108

Comment: Proposed Citation Reference for Completions and Workovers without Hydraulic 

Fracturing: §98.236(h)(2) and (h)(2)(i), Proposed Rule Text: (2) For each sub-basin with gas 

well completions without hydraulic fracturing and with flaring, report the information specified 

in paragraphs (h)(2)(i) through (h)(2)(vii) of this section. (i) Sub-basin ID.

This is a CBI issue for exploratory wells. This information should remain confidential for a 

minimum of 24 months.

242
Response: See the response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 99 of 

this section.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 116

Comment: Proposed Citation Reference for Associated Natural Gas Venting and Flaring: 

§98.236(m) and (m)(1), Proposed Rule Text: (m)...If associated gas was vented or flared during 

the calendar year, then you must report the information specified in paragraphs (m)(1) through 

(m)(8) of this section for each sub-basin. (1) Subbasin ID.

Previously reporting for associated gas venting and flaring was at the Basin level. This change 

requires reporting at the sub-basin level, which raises CBI concerns for exploratory wells. 

Associated gas identifies the well as an oil well.

Response: See the response to comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 99 of 

this section.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 100

Comment: Proposed Citation Reference for Completions and Workovers with Hydraulic 

Fracturing: §98.236(g)(2), Proposed Rule Text: Well type.

This is a CBI issue for exploratory wells where a new formation type or area is being evaluated. 

This information should remain confidential for a minimum of 24 months.

Response: As discussed in Section III.B of the preamble to the final rule, the EPA disagrees that 

the well type should remain confidential for two years because the well type can be inferred from 

the formation type. As discussed in the response to comment EPA-HQ-OAR-2011-0512-0084-

A2, Excerpt 132 in this section, the type of formation can be determined through publicly 

available USGS reports based on knowledge of the location of the well, which can be discerned 

from the publicly available well ID. Therefore, the EPA is finalizing as proposed the 

determination that the well type is not CBI.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

243
Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 132

Comment: Proposed Citation Reference: 98.236(aa)(1)(ii)(C), Proposed Rule Text: Formation 

type.

This is a CBI issue for exploratory wells- it discloses the targeted formation.

Response: As discussed in Section III.B of the preamble to the final rule, the EPA disagrees that 

the formation type should be confidential because the type of formation can be determined 

through publicly available USGS reports based on knowledge of the location of the well, which 

can be discerned from the publicly available well ID. Therefore, the EPA is finalizing the 

determination as proposed that the formation type is not CBI.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 102

Comment: Proposed Citation Reference for Completions and Workovers with Hydraulic 

Fracturing: §98.236(g)(5) and §98.236(g)(5)(i), Proposed Rule Text: (5) If you used Equation 

W-10A to calculate annual volumetric total gas emissions, then you must report the information 

specified in paragraphs (g)(5)(i) and (g)(5)(ii) of this section. (i) Cumulative backflow time, in 

hours, for each sub basin (“Tp” in Equation W-10A).

This is a CBI issue for exploratory wells where a new formation type or new area is being 

evaluated. This information should remain confidential for a minimum of 24 months

Response: As discussed in Section III.B of the preamble to the final rule, the EPA has 

determined that early public disclosure of flowback time associated with wildcat wells and/or 

delineation wells could reveal well productivity, thereby resulting in the loss of investment 

value. Therefore, in situations where wildcat wells and/or delineation wells are the only wells in 

a sub-basin that can be used for the measurement of cumulative flowback time for gas well 

completions or workovers with hydraulic fracturing, the final rule provides reporters with the 

option to report this data element two years after the reporting year in which the data was 

collected. See Section III.B of the preamble to the final rule for additional information about the 

requirements of the option to delay reporting of this data element.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 103

244
Comment: Proposed Citation Reference for Completions and Workovers with Hydraulic 

Fracturing: §98.236(g)(6), Proposed Rule Text: If you used Equation W-10B to calculate annual 

volumetric total gas emissions for completions that vent gas to the atmosphere, then you must 

report the vented natural gas volume, in standard cubic feet, for each well in the sub-basin 

(“FVs,p” in Equation W-10B).

This is a CBI issue for exploratory wells. This information should remain confidential for a 

minimum of 24 months.

Response: As discussed in Section III.B of the preamble to the final rule, the EPA disagrees that 

the vented natural gas volume for completions and workovers with hydraulic fracturing should 

remain confidential for two years. This data element meets the definition of emission data in 40 

CFR 2.301(a)(2)(i) because they are actual GHGs emitted by the facility. Under CAA section 

114(c), the EPA must make available emission data, whether or not such data are CBI. For these 

data elements that are assigned to the “Emissions” data category, the commenter did not claim or 

provide any justification for why these data elements do not meet the definition of emission data.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 104

Comment: Proposed Citation Reference for Completions and Workovers with Hydraulic 

Fracturing: §98.236(g)(7), Proposed Rule Text: Annual gas emissions, in standard cubic feet 

(“Es,n” in Equation W-10A or W-10B).

This is a CBI issue for exploratory wells. This information should remain confidential for a 

minimum of 24 months.

Response: As discussed in Section III.B of the preamble to the final rule, the EPA disagrees that 

annual gas emissions should remain confidential for two years. This data element meets the 

definition of emission data in 40 CFR 2.301(a)(2)(i) because they are actual GHGs emitted by 

the facility. Under CAA section 114(c), the EPA must make available emission data, whether or 

not such data are CBI. For these data elements that are assigned to the “Emissions” data 

category, the commenter did not claim or provide any justification for why these data elements 

do not meet the definition of emission data.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 107

245
Comment: Proposed Citation Reference for Completions and Workovers without Hydraulic 

Fracturing: §98.236(h)(1)(iv), Proposed Rule Text: Average daily gas production rate for all 

completions without hydraulic fracturing in the sub-basin without flaring, in standard cubic feet 

per hour (average of all “Vp” used in Equation W-13B).

This is a CBI issue for exploratory wells – it discloses the daily gas flow rate. This information 

should remain confidential for a minimum of 24 months.

Response: As discussed in Section III.B of the preamble to the final rule, the EPA has 

determined that early public disclosure of this data element associated with wildcat wells and/or 

delineation wells could reveal well productivity, thereby resulting in the loss of investment 

value. Therefore, in situations where wildcat wells and/or delineation wells are the only wells in 

a sub-basin that can be used for the measurement of the average daily gas production rate for all 

completions without hydraulic fracturing, the final rule provides reporters with the option to 

report this data element two years after the reporting year in which the data was collected. See 

Section III.B of the preamble to the final rule for additional information about the requirements 

of the option to delay reporting of this data element.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 110

Comment: Proposed Citation Reference for Completions and Workovers without Hydraulic 

Fracturing: §98.236(h)(2)(iv), Proposed Rule Text: Average daily gas production rate for all 

completions without hydraulic fracturing in the sub-basin with flaring, in standard cubic feet per 

hour (the average of all “Vp” from Equation W-13B.

This is a CBI issue for exploratory wells – it discloses the daily gas flow rate. This information 

should remain confidential for a minimum of 24 months.

Response: As discussed in Section III.B of the preamble to the final rule, the EPA has 

determined that early public disclosure of this data element associated with wildcat wells and/or 

delineation wells could reveal well productivity, thereby resulting in the loss of investment 

value. Therefore, in situations where wildcat wells and/or delineation wells are the only wells in 

a sub-basin that can be used for the measurement of the average daily gas production rate for all 

completions without hydraulic fracturing, the final rule provides reporters with the option to 

report this data element two years after the reporting year in which the data was collected. See 

Section III.B of the preamble to the final rule for additional information about the requirements 

of the option to delay reporting of this data element.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

246
Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 111

Comment: Proposed Citation Reference for Onshore Production Storage Tanks: §98.236(j)(2) 

and (j)(2)(i) and (j)(2)(i)(A), Proposed Rule Text: (2) If you used Calculation Method 3 to 

calculate GHG emissions, then you must report the information specified in paragraph (j)(2)(i) 

through (j)(2)(iii) of this paragraph. (i) Report the information specified in paragraphs 

(j)(2)(i)(A) through (j)(2)(i)(F) of this section at the basin level for atmospheric tanks where 

emissions were calculated using Calculation Method 3. (A) The total annual oil throughput that 

is sent to atmospheric tanks in the basin, in barrels. Revised from: “Total volume of oil 

production in barrels per year.”

It is possible that an exploratory well could be evaluating an entirely new sub-basin, in which 

case this information would be CBI.

Response: For the reasons described in Section III.B of the preamble to the final rule, the EPA 

has determined that early public disclosure of this data element associated with wildcat wells 

and/or delineation wells could reveal well productivity, thereby resulting in the loss of 

investment value. Therefore, in situations where wildcat wells and/or delineation wells are the 

only wells in a sub-basin that can be used for the measurement of the total annual oil throughput 

that is sent to atmospheric tanks, the final rule provides reporters with the option to report this 

data element two years after the reporting year in which the data was collected. See Section III.B 

of the preamble to the final rule for additional information about the requirements of the option 

to delay reporting of this data element.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 112

Comment: Proposed Citation Reference for Well Testing: §98.236(l)(1)(iv), Proposed Rule 

Text: If oil well testing is performed where emissions are not vented to a flare, the average flow 

rate in barrels of oil per day for well(s) tested.

This is a CBI issue for exploratory wells- it discloses oil flow rate. This information should 

remain confidential for a minimum of 24 months.

Response: For the reasons described in Section III.B of the preamble to the final rule, the EPA 

has determined that early public disclosure of this data element associated with wildcat wells 

and/or delineation wells could reveal well productivity, thereby resulting in the loss of 

investment value. Therefore, in situations where wildcat wells and/or delineation wells are the 

only wells in a sub-basin that can be used for the measurement of the average daily oil flow rate, 

the final rule provides reporters with the option to report this data element two years after the 

reporting year in which the data was collected. See Section III.B of the preamble to the final rule 

247
for additional information about the requirements of the option to delay reporting of this data 

element.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 113

Comment: Proposed Citation Reference for Well Testing:§98.236(l)(2)(iv), Proposed Rule 

Text: If oil well testing is performed where emissions are vented to a flare, the average flow rate 

in barrels of oil per day for well(s) tested.

This is a CBI issue for exploratory wells- it discloses oil flow rate. This information should 

remain confidential for a minimum of 24 months.

Response: For the reasons described in Section III.B of the preamble to the final rule, the EPA 

has determined that early public disclosure of this data element associated with wildcat wells 

and/or delineation wells could reveal well productivity, thereby resulting in the loss of 

investment value. Therefore, in situations where wildcat wells and/or delineation wells are the 

only wells in a sub-basin that can be used for the measurement of the average daily oil glow rate, 

the final rule provides reporters with the option to report this data element two years after the 

reporting year in which the data was collected. See Section III.B of the preamble to the final rule 

for additional information about the requirements of the option to delay reporting of this data 

element.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 114

Comment: Proposed Citation Reference for Well Testing:§98.236(l)(3)(iii), Proposed Rule 

Text: If gas well testing is performed where emissions are not vented to a flare, the average 

annual production rate in actual cubic feet per day for well(s) tested.

This is a CBI issue for exploratory wells- it discloses gas flow rate. This information should 

remain confidential for a minimum of 24 months.

Response: For the reasons described in Section III.B of the preamble to the final rule, the EPA 

has determined that early public disclosure of this data element associated with wildcat wells 

and/or delineation wells could reveal well productivity, thereby resulting in the loss of 

investment value. Therefore, in situations where wildcat wells and/or delineation wells are the 

only wells in a sub-basin that can be used for the measurement of the average annual gas 

production rate, the final rule provides reporters with the option to report this data element two 

248
years after the reporting year in which the data was collected. See Section III.B of the preamble 

to the final rule for additional information about the requirements of the option to delay reporting 

of this data element.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2Error! Bookmark not 

defined.

Comment Excerpt Number: 115

Comment: Proposed Citation Reference for Well Testing:§98.236(l)(4)(iii), Proposed Rule 

Text: If gas well testing is performed where emissions are not vented to a flare, the average 

annual production rate in actual cubic feet per day for well(s) tested.

This is a CBI issue for exploratory wells- it discloses gas flow rate. This information should 

remain confidential for a minimum of 24 months.

Response: For the reasons described in Section III.B of the preamble to the final rule, the EPA 

has determined that early public disclosure of this data element associated with wildcat wells 

and/or delineation wells could reveal well productivity, thereby resulting in the loss of 

investment value. Therefore, in situations where wildcat wells and/or delineation wells are the 

only wells in a sub-basin that can be used for the measurement of the average annual gas 

production rate, the final rule provides reporters with the option to report this data element two 

years after the reporting year in which the data was collected. See Section III.B of the preamble 

to the final rule for additional information about the requirements of the option to delay reporting 

of this data element.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 117

Comment: Proposed Citation Reference for Associated Natural Gas Venting and Flaring: 

§98.236(m)(2), Proposed Rule Text: For each sub-basin, indicate whether any associated gas was 

vented without flaring.

Previously reporting for associated gas venting and flaring was at the Basin level. This change 

requires reporting at the sub-basin level, which raises CBI concerns for exploratory wells. 

Associated gas identifies the well as an oil well.

Response: If exploratory wells are the only wells in a sub-basin, the commenter is concerned 

that reporting any information related to associated gas emissions (such as whether the emissions 

are vented without flaring) identifies the wells as oil wells. As discussed in the response to 

249
comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt 132 of this section and in Section III.B 

of the preamble to the final rule, the EPA disagrees that the well type should be confidential 

because it can be inferred from the publicly available well ID, location, and type of formation. 

Since the well type is not confidential, EPA also disagrees that information about associated gas 

emissions should be confidential. Thus, the EPA is finalizing the determination as proposed that 

indicating whether any associated gas was vented without flaring is not CBI.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 118

Comment: Proposed Citation Reference for Associated Natural Gas Venting and 

Flaring:§98.236(m)(3), Proposed Rule Text: For each sub-basin, indicate whether any associated 

gas was flared.

Comment: Previously reporting for associated gas venting and flaring was at the Basin level. 

This change requires reporting at the sub-basin level, which raises CBI concerns for exploratory 

wells. Associated gas identifies the well as an oil well.

Response: If exploratory wells are the only wells in a sub-basin, the commenter is concerned 

that reporting any information related to associated gas emissions (such as whether the emissions 

are flared) identifies the wells as oil wells. As discussed in the response to comment EPA-HQOAR-2011-0512-0084-A2, Excerpt 132 of this section and in Section III.B of the preamble to 

the final rule, the EPA disagrees that the well type should be confidential because it can be 

inferred from the publicly available well ID, location, and type of formation. Since the well type 

is not confidential, EPA also disagrees that information about associated gas emissions should be 

confidential. Thus, the EPA is finalizing the determination as proposed that indicating whether 

any associated gas was flared is not CBI.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 119

Comment: Proposed Citation Reference for Associated Natural Gas Venting and 

Flaring:§98.236(m)(5), Proposed Rule Text: Volume of oil produced, in barrels, in the calendar 

year during the time periods in which associated gas was vented or flared (the sum of “Vp,q” 

used in Equation W- 18 of this subpart).

Previously reporting for associated gas venting and flaring was at the Basin level. This change 

requires reporting at the sub-basin level, which raises CBI concerns for exploratory wells. 

Associated gas identifies the well as an oil well.

250
Response: For the reasons described in Section III.B of the preamble to the final rule, the EPA 

has determined that early public disclosure of this data element associated with wildcat wells 

and/or delineation wells could reveal well productivity, thereby resulting in the loss of 

investment value. Therefore, in situations where wildcat wells and/or delineation wells are the 

only wells in a sub-basin that can be used for the measurement of volume of oil produced, the 

final rule provides reporters with the option to report this data element two years after the 

reporting year in which the data was collected. See Section III.B of the preamble to the final rule 

for additional information about the requirements of the option to delay reporting of this data 

element.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 120

Comment: Proposed Citation Reference for Associated Natural Gas Venting and 

Flaring:§98.236(m)(6), Proposed Rule Text: Total volume of associated gas sent to sales, in 

standard cubic feet, in the calendar year during time periods in which associated gas was vented 

or flared (the sum of “SG” values used in Equation W-18 of this subpart).

Previously reporting for associated gas venting and flaring was at the Basin level. This change 

requires reporting at the sub-basin level, which raises CBI concerns for exploratory wells. 

Associated gas identifies the well as an oil well.

Response: For the reasons described in Section III.B of the preamble to the final rule, the EPA 

has determined that early public disclosure of this data element associated with wildcat wells 

and/or delineation wells could reveal well productivity, thereby resulting in the loss of 

investment value. Therefore, in situations where wildcat wells and/or delineation wells are the 

only wells in a sub-basin that can be used for the measurement of total volume of associated gas 

sent to sales, the final rule provides reporters with the option to report this data element two 

years after the reporting year in which the data was collected. See Section III.B of the preamble 

to the final rule for additional information about the requirements of the option to delay reporting 

of this data element.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 134

Comment: Proposed Citation Reference: §98.236(aa)(1)(ii)(G), Proposed Rule Text: For each 

sub-basin category, the number of wells completed during the calendar year.

251
Comment: This is a CBI issue for exploratory wells- it discloses the targeted formation and the 

success in finding hydrocarbon.

Response: For the reasons described in Section III.B of the preamble to the final rule, EPA 

disagrees that public disclosure of the number of wells completed in a sub-basin during the time 

period immediately following annual reporting would cause substantial competitive harm to 

reporters. As we note in the preamble, this data element provides information that is either 

already in the public domain or easily inferred from other publicly available data. For these 

reasons, EPA is finalizing the determination as proposed that this data element is not CBI.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 133

Comment: Proposed Citation Reference: §98.236(aa)(1)(ii)(D), Proposed Rule Text: For each 

sub-basin category, the number of producing wells at the end of the calendar year.

Comment: This is a CBI issue for exploratory wells- it discloses the targeted formation.

Response: For the reasons described in Section III.B of the preamble to the final rule, EPA 

disagrees that public disclosure of the number of producing wells during the time period 

immediately following annual reporting would cause substantial competitive harm to reporters. 

As we note in the preamble, this data element provides information that is either already in the 

public domain or easily inferred from other publicly available data. For these reasons, EPA is 

finalizing the determination as proposed that this data element is not CBI.

23.0 Impacts of the Proposed Amendments

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 68

Comment: For reporting of proposed new data elements, EPA assumed that 3 minutes would be 

required to find, document, and report each new data element:

"The EPA then multiplied the adjusted number of new and revised data elements by 3 minutes 

per data element—the amount time that the EPA estimated an engineer would need to access the 

data element from readily available data [Emphasis added] and submit the value..." (AI page 

8)

This estimate does not consider the level of effort required to determine who collects such data, 

how it is documented (e.g., records in a database or hard files, multiple potential data systems to 

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assess), associated Subpart W recordkeeping, revising data collection systems and templates, etc. 

It appears to assume that some sort of simple company-level database search is conducted for 

each data new element. Estimates of incremental effort should consider the number of hours, 

rather than minutes, per data element, and EPA likely under-estimates implementation costs by 

two or more orders of magnitude. An INGAA member estimated that the company-wide 

implementation of system revisions to identify, collect, document, and report the new 

data elements will be $150,000 or more, with additional ongoing annual costs to fulfill the 

reporting obligation for the new data elements.

• It is inconceivable that data review and oversight costs would exceed the costs to gather the 

data, develop new systems to accommodate the data, quality assure the data, perform 

calculations, report the data, and follow-up on questions that may be asked. EPA estimates its 

costs, and estimates that EPA’s incremental costs for the proposed Subpart W revisions for 

EPA for the first three years will include about $436,000/yr for headquarters oversight and 

implementation, plus $783,000/yr for third party verification for a total of about 

$1,200,000/yr. EPA estimates the incremental cost for Industry/Public will be about 

$543,000 per year for the first three years. Thus, EPA estimates that the Proposed Rule will 

cost EPA more than twice the cost incurred by the 2,000+ reporting facilities for the 

Petroleum and Natural Gas Systems Industry. (ICR Pages 12 – 15).

• EPA estimates the average total (not incremental) annual number of hours for each facility to 

comply with Subpart W is 53.5 (hr/yr).

− "The annual public reporting and recordkeeping burden for this collection of information is 

estimated to average 53.5 hours per response." (ICR page 21)

This is an absurdly low estimate of the level of effort required for rule implementation that 

includes planning and coordination, training, data collection including direct measurements and 

validation, running software simulations, performing calculations, recordkeeping, and reporting.

• EPA acknowledges the definition of ‘burden’ from the Paperwork Reduction Act but it does 

not appear that EPA considered each element when developing the estimated costs for 

Industry.

"Burden means the total time, effort, or financial resources expended by persons to generate, 

maintain, retain, or disclose or provide information to or for a federal agency. This includes the 

time needed to review instructions; develop, acquire, install, and utilize technology and systems 

for the purposes of collecting, validating, and verifying information, processing and 

maintaining information, and disclosing and providing information; adjust the existing ways to 

comply with any previously applicable instructions and requirements; train personnel to 

respond to a collection of information; search data sources; complete and review the collection 

of information; and transmit or otherwise disclose the information."11 (emphasis added)

There are additional examples in the impact assessments. The general theme is consistent: EPA 

significantly under-estimates costs and impacts to the affected community. Implementation 

burden should be assessed when justifying rule requirements; the erroneous estimates fail to 

fulfill that obligation. In considering INGAA’s comments and responses necessary to complete 

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the final rule, EPA should reassess under-estimated industry cost impacts to meet its obligation 

to justify decisions reflected in Subpart W.

Footnote:

11 “Information Collection Request for the Greenhouse Gas Reporting Program,” EPA-HQOAR-2011-0512-0066, at 21 (February 20, 2014) (citing 44 U.S.C. § 3502(2)(1995)). 

Response: See Section IV.B of the preamble to the final rule for discussion related to this 

comment.

Commenter Name: V. Bruce Thompson

Commenter Affiliation: American Exploration & Production Council (AXPC)

Document Control Number: EPA-HQ-OAR-2011-0512-0085-A2

Comment Excerpt Number: 1

Comment: The proposed rule adds large amounts of additional data collection and reporting 

requirements that AXPC and the Alliance believe to be unduly burdensome and difficult to 

implement. Although considered, EPA has vastly underestimated the amount of time that is 

needed in order to modify data collection, management, and reporting systems and processes. 

Data reported for the rule is often compiled from a number of different systems and the addition 

of each data element will require an evaluation of where the data can be pulled from, how it can 

be integrated into current data management systems and processes, and how it can be integrated 

into existing raw data reporting formats. This process will take many man‐hours per data 

element, vastly more that the EPA estimate of three minutes per element.

Response: See Section IV.B of the preamble to the final rule for discussion related to this 

comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 147

Comment: In its February 20, 2014, memo to the docket entitled, Assessment of Impacts of the 

2014 Proposed Revisions to Subpart W [Alexis McKittrick and Mark de Figueiredo, EPA/CCD, 

“Assessment of Impacts of the 2014 Proposed Revisions to Subpart W”, EPA-HQ-OAR-2011-

0512-0063, February 20, 2014], EPA addresses the potential burden to reporters. EPA admits 

that it is proposing that 245 new data elements be reported and that 15 data elements will remain 

but must be substantially revised which will “impose additional burden and costs because, for 

each of the new and revised data elements that would be required to be reported, reporters would 

be required to calculate the data using readily available data, and report the value to the EPA via 

[e-GGRT] as part of the annual report currently required under Part 98.” EPA then calculated the 

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burden associated with the new and revised data elements by adjusting labor hours upward per 

reporter for all industry segments. EPA’s calculations, however, vastly underestimate the labor 

time and the overall burden and there is no discussion explaining how EPA “adjusted” its 

numbers (other than explaining that EPA looked at costs through the lens of labor costs) to get 

the numbers provided in the memo that simply do not account for the actual burdens on the 

reporters particularly with the tremendous expansion of data recording requirements. On page 8 

of the memo, EPA estimated that an engineer would require 3 minutes per data element to access 

each new data element from “readily available data” and submit the value via e-GGRT. The EPA 

fails to realize that in many cases, each data element may not be stored in a central database and 

each engineer compiling the data for submittal to e-GGRT would potentially need to network 

with several different company employees or sources to even access the information. The 

engineer would also have to make determinations regarding each of the data elements to assure 

that the data provided indeed matches the precise requirements that the EPA is requesting. Data 

would also then need to be compiled together by each data element and sub-basin as required 

(e.g. totaled or averaged), reviewed, and inserted into the e-GGRT forms. Each one of these steps 

alone would take more than three minutes per element. In cases where a newly required data 

element is stored at the local level, the time spent compiling the data could stretch by hours, if 

not days. EPA’s assumption that all the newly required data elements could be accessed from a 

central database, by an engineer familiar with the data set and its quality, then pulled, compiled, 

reviewed and input into the e-GGRT forms in three minutes is not a realistic estimate based on 

the quantity and variety of data requested. Even if the data were already available and easily 

accessible in one central database, a significant amount of time would be required to identify 

each piece of information in the database to match up with the EPA’s list of data elements and 

make necessary modifications to reports used to extract and properly aggregate the information 

for each data element in a reportable format. API is ready to continue this discussion on burden 

estimates with EPA.

Response: Regarding the EPA's justification for the additional reporting elements in this 

rulemaking, see Section II.E.2 of the preamble to the final rule. Regarding the EPA’s response to 

the comment on the compliance costs associated with data reporting, see Section IV.B of the 

preamble to the final rule. Also, discussion explaining how the EPA determined the number of 

data elements per industry segment has been added to “Final Assessment of Impacts of the 2014 

Revisions to Subpart W” (see Docket Id. No. EPA-HQ-OAR-2011-0512).

Commenter Name: Ritu Talwar

Commenter Affiliation: Spectra Energy Corp

Document Control Number: EPA-HQ-OAR-2011-0512-0079-A1

Comment Excerpt Number: 3

Comment: New Reporting Elements to Calculate GHG Emissions 

EPA has arbitrarily added new reporting elements that are not needed to calculate GHG 

emissions. We refer you to INGAA’s comments for a comprehensive list of these elements. EPA 

has significantly under-estimated Subpart W compliance costs, including costs associated with 

data compilation and reporting. It is important that EPA understands there are real and 

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substantive costs for implementing systems to collect and report new data that are not needed to 

calculate GHG emissions, and these costs should be adequately considered and weighed against 

the purpose and value of the new data to be collected. EPA should provide the justification for 

adding new reporting elements to this rule-making.

Response: Regarding the EPA's justification for the additional reporting elements in this 

rulemaking, see Section II.E.2 of the preamble to the final rule. Regarding the EPA’s response to 

the comment on the compliance costs associated with data reporting, see Section IV.B of the 

preamble to the final rule.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 58

Comment: EPA has significantly under-estimated Subpart W implementation costs, including 

costs associated with data compilation and reporting. For example, review of proposed new data 

elements by an INGAA member estimated that it would require 1,000 hours per year to track and 

report for their subject T&S facilities. In addition, systems would need to be established to 

reduce human tracking error. The cost of creating or adding data elements could cost an 

additional $100,000 per year to implement and maintain. It is important that EPA understands 

there are real and substantive costs for implementing systems to report new data, and these costs 

should be adequately considered and weighed against the purpose and value of the new data to 

be collected.

Response: Overall, the EPA has determined that the commenters do not take into consideration 

the completion of one-time activities during the first year of data collection, such as planning, 

registration, installing required equipment, and developing a data tracking system. See Section 

IV.B of the preamble to the final rule for EPA's response to this comment.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 13

Comment: Significant Expansion of Reporting Requirements. If EPA adopts the proposed 

rule with respect to certain reporting requirements, the final rule will significantly expand 

reporting requirements for some sources and require additional data collection that was not 

previously required. EPA should not utilize this proposed rule as an opportunity to further 

expand reporting requirements and introduce new burdens on the regulated industry at this stage. 

Additionally, in its rule impact memorandum, in which the agency assesses impacts on reporters, 

EPA vastly underestimates the time and burden of these expanded requirements.

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Response: Regarding the EPA's justification for the additional reporting elements in this 

rulemaking, see Section II.E.2 of the preamble to the final rule. See Section IV of the preamble 

to the final rule for more detailed discussion of the impacts of the final amendments and the 

EPA’s response to this comment.

Commenter Name: Carrie B. Crumpton

Commenter Affiliation: CONSOL Energy, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0080-A1

Comment Excerpt Number: 1

Comment: The rule itself is generally already too expansive with regards to data collection and 

reporting and the proposed rule further expands the data collection and reporting requirements 

for some sources. These requirements will be both burdensome and could lead to a substantial

cost to the industry. CONSOL Energy Inc. (CONSOL) requests that the Environmental 

Protection Agency (EPA) reconsider these additional requirements. CONSOL has invested in a 

robust system to manage data collection and reporting requirements per the original rule and 

continuing changes to implement and reconfigure data management systems become 

burdensome and costly. Examples of these new or expanded requirements include:

• Expanding the reporting requirements for emissions at stuck dump valves to tanks with less 

than 10 bbl/day throughput.

• Expanding the data collection and reporting requirements for well type combinations that 

include completions and workovers to additionally include with/without flaring and 

with/without reduced emission workovers. Potentially doubling measurement and reporting 

requirements.

• Expanding the definition of well type combinations for workovers to include with and 

without reduced emission workover. This potentially quadruples the measurement and 

reporting requirements.

Response: The EPA appreciates the commenter's concern over the complexity and burden of 

the subpart W requirements for calculating and reporting GHG emissions. The EPA has revised 

certain calculation methods and amended certain monitoring and data reporting requirements in 

the final rule as a result of public comments. The EPA has also provided additional flexibility for 

certain monitoring and calculation requirements. For example, it was not the EPA’s intent to 

require reporting of emissions from stuck dump valves to storage tanks with a throughput less 

than 10 barrels per day and therefore the EPA has revised the final rule accordingly, as noted in 

Section II.B.7 of the preamble to the final rule. In many cases, the revisions that are being made 

improve the estimating and reporting of GHG emissions and reduce the burden on those facilities 

required to report GHG emissions.

Regarding the data collection and reporting requirements for gas well completions and 

workovers and the revised definition of well type combinations, the EPA is finalizing these 

provisions as proposed. We disagree with commenters that the requirements will impose a 

significant burden on reporters, because it is unlikely that reporters conduct drilling activities in 

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all the different types of wells for a given sub-basin. See Section II.B.5 of the preamble to the 

final rule for additional information.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 22

Comment: EPA documents assessing costs to conduct compressor measurements and 

implement other Proposed Rule requirements are inadequate. Implementation costs are underestimated by an order of magnitude or more, which suggests the authors lack a fundamental 

understanding of both the type of activities and level of effort required to collect data for Subpart 

W reporting.

The Proposed Rule docket includes two documents that address incremental costs associated 

with the proposed Subpart W revisions:

• EPA-HQ-OAR-2011-0512-0063: Assessment of Impacts of 2014 Proposed Revisions to 

Subpart W (hereafter referred to as "AI"); and

• EPA-HQ-OAR-2011-0512-0066: ICR Supporting Statement (hereafter referred to as "ICR")

In general, the documents greatly over-simplify the impact of the Proposed Rule and underestimate the associated incremental costs. Following is a partial sampling (i.e., not every issue is 

addressed) of EPA estimates of incremental costs associated with proposed Subpart W revisions 

that appear to be severely under-estimated (e.g., by one to two orders of magnitude or more), and 

other information and data associated with the estimates.

• Many of the EPA estimated incremental costs for reporters associated with the proposed 

Subpart W revisions are severely under-estimated. Examples include:

- Regarding incremental management support for Proposed Rule revisions, EPA states:

"None of the proposed amendments require an adjustment to middle and senior management 

labor hours" (AI page 1).

The cost estimates do not include management tasks including review of the proposed rule and 

final revisions, Monitoring Plan revisions, internal communications, coordination with technical 

staff, training, systems updates, associated budgeting and planning, etc.

EPA estimated that for compressor stations with manifolded compressor sources, the cost of 

annual compressor source gas emission measurements would decrease because one measurement 

(at the manifold) would be conducted rather than a measurement at each compressor source.

"This proposed change is a burden reduction for reporters that have more than three compressor 

sources manifolded together" (AI page 3)

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This analysis fails to consider that manifolded vents would require three separate measurements 

(i.e., three separate trips to a compressor station) separated by a minimum of 60 days during the 

calendar year. EPA fails to consider the costs associated with each separate measurement/trip 

including test personnel scheduling and facility coordination, mobilization (equipment 

preparation, travel to and from the facility), on-site set up, daily safety orientation, man-lift 

rental, operations staff support, etc.

Further, the EPA cost analysis assumes an incremental time of 10 minutes for a technician to 

conduct each additional compressor source measurement. That is, to conduct blowdown valve 

leakage measurements on four compressors would require 30 minutes more than conducting 

blowdown valve leakage measurements on a single compressor. This fails to consider the time 

required to move personnel and equipment (likely including a man lift or a ladder) from 

compressor to compressor in the tight confines of a compressor station, and the cautious pace of 

work and work practices (e.g., use of lanyard and/or other fall protection) for safely working at 

elevated locations. Finally, this 10 minute per measurement estimate appears to assume that the 

technician is working alone. Personnel working at elevated locations should never work without 

assistance. This time allotment also fails to consider all of the time associated with logistics and 

mobilization discussed above (AI page 3).

In contrast, compressor source measurement cost estimates provided by INGAA members range 

from about $1,300 to $3,000+ per facility per test (i.e., these incremental costs would be 

incurred at least two times a year). Actual costs would depend on numerous parameters 

including number of manifolded compressor sources and accessibility, test team travel time and 

costs, number of test team members, and number of facilities that can be visited by a test team in 

a single mobilization. Further, these costs are only for the testing contractor and do not include 

facility and company costs including scheduling, coordination, test team support, burden, etc. As 

an alternative, EPA may have assumed that tests would be conducted by staff on site. This fails 

to understand that annual surveys are typically completed by third party contractors.

Even for companies that have increased staff to conduct the Subpart W measurements, there 

would be dedicated teams that move from station to conduct the measurements, similar to 

conducting the measurements using third party contractors. It would be cost prohibitive to equip 

and train personnel at every compressor station to conduct the Subpart W monitoring based on 

the substantial costs associated with equipment acquisition (e.g., infrared cameras, high volume 

samplers, and other meters and equipment required to conduct the Subpart W monitoring), and 

the specialized training that differs from current skill sets and would thus require ongoing 

oversight.

In the preamble, EPA states, "This proposed measurement option would allow the EPA to 

correctly characterize and analyze GHG emissions from all compressors at individual facilities in 

the petroleum and natural gas systems source category while potentially reducing burden to 

industry." This requirement would not reduce burden to industry; instead, it adds two additional 

annual measurement trips in perpetuity.

Response: We have revised the final rule to require only a single annual emissions 

measurement at the common vent for groups of manifolded compressors. The incremental time 

measurements assumed that the level of effort associated with manifolded measurements are 

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similar to the level of effort associated with measurements for individual compressors. See 

Section IV of the preamble to the final rule for more information.

Commenter Name: Lisa Beal

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0081-A1

Comment Excerpt Number: 23

Comment: Regarding incremental costs associated with proposed revised requirements for 

Blowdown Vent Stacks, EPA states:

"The EPA is proposing to add a compressibility term to the blowdown vent stack calculations. It 

is anticipated that reporters handle gas within the proposed compressibility factor default ranges; 

therefore, it is unlikely that adding this compressibility factor term into the blowdown vent stack 

calculations would increase burden to reporters. Therefore, the EPA did not estimate the 

potential burden impact to reporters for this change." (AI page 6)

Processing, transmission, and storage facilities all handle gas with compressibility outside the 

proposed compressibility factor default range of less than 5 atmospheres (73.5 psi). Operating 

pressures commonly exceed 74 psi, for segments required to complete blowdown vent reporting. 

This is another example of EPA’s fundamental lack of understanding of natural gas system 

operations for the two primary segments (processing, transmission) that are required to report 

blow downs. EPA’s estimate of the Proposed Rule implementation costs (i.e., zero) is obviously 

grossly underestimated. Further, this statement directly conflicts with information and data 

considered by EPA in the Technical Support Document.

"The natural gas processing and transmission compression segments covered by subpart W can 

operate systems at pressures higher than 25 atmospheres."

"Natural gas transmission compressor station components and main line pressures are in the 

range of 500 to 1000 psi (34 to 68 atmospheres). See page 6-32, American Petroleum Institute 

(August 2009), Compendium of Greenhouse Gas Emission Methodologies for the Oil and 

Natural Gas Industry."

Indeed, because of this pressure limitation of less than 5 atmospheres, and because of typical 

operating pressures at these facilities, reporters will almost always have to calculate the 

compressibility factor. Even if the factor at actual conditions is greater than 0.98 (where EPA 

proposes to allow the reporter to use the default factor of 1), the reporter must still undergo the 

burden of determining whether the factor is above 0.98.

Response: We have revised the final rule to allow reporters the option to use a default 

compressibility factor of 1 or use a site-specific factor based on actual temperature and pressure 

conditions. See Section II.B.6 of the preamble to the final rule for additional discussion 

regarding the optional use of compressibility factors. Because the final rule does not mandate the 

use of a site-specific compressibility factor, we have determined that adding this optional 

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compressibility factor term into the blowdown vent stack calculations will not increase burden to 

reporters.

Commenter Name: Gary W. Smith

Commenter Affiliation:

Document Control Number: EPA-HQ-OAR-2011-0512-0072

Comment Excerpt Number: 2

Comment: The basis for monitoring these gasses is predominately conditioned on non-scientific 

modeling provided by a UN agency which is hostile to the Constitution and the principles on 

which this nation was founded. The imposition of these changes provides no improvement to the 

individual nor the nation's character and processes, is as worthless as the onerous regulatory 

conditions imposed by other ill-planned controls, the most predominant example being SarbanesOxley.

In a time of negligible economic growth, the added cost burdens both the industry and the citizen 

with no gain to the industry on which human survival is critical. At the rate of destruction of the 

energy grid sustaining industries with no successful replacement in development, the EPA is 

dooming citizens during planet cycles when the northern hemisphere is coldest, looting their 

treasure to obtain sustaining warmth, and in general, wrecking havoc. It is as if EPA regulatory 

demands wish to fulfill the tasks assigned to one of the four horsemen of the apocalypse.

While I am not a person of scientific stature, reasoned behavior by Government is not 

demonstrated in this regulatory update. The following list of scientists do not concur with 

'Climate Change', a driver of this regulatory development, as do I, and, have provided credible 

research into the folly and unscientific nature of any such type of destructive regulatory 

management as imposed in 40 CFR Part 98: Craig D. Idso (USA), Robert M. Carter (Australia), 

S. Fred Singer (USA), Timothy Ball (Canada), Robert M. Carter (Australia), Don Easterbrook 

(USA), Craig D. Idso (USA), Sherwood Idso (USA), Madhav Khandekar (Canada), William 

Kininmonth (Australia), Willem de Lange (New Zealand), Sebastian Lüning (Germany), 

Anthony Lupo (USA), Cliff Ollier (Australia), Willie Soon (USA), J. Scott Armstrong (USA), 

Joseph D’Aleo (USA), Don Easterbrook (USA), Kesten Green (Australia), Ross McKitrick 

(Canada), Cliff Ollier (Australia), Tom Segalstad (Norway), Dr. Roy Spencer (USA), Habibullo 

Abdussamatov (Russia), Joe Bastardi (USA), Franco Battaglia (Italy), David Bowen (UK), Roy 

Clark (USA), Vincent Courtillot (France), Christopher Essex (Canada), David Evans (Australia), 

Sören Floderus (Denmark), Stewart Franks, (Australia), Eigil Friis-Christensen (Denmark), Fred 

Goldberg (Sweden), Larry Gould (USA), William Gray (USA), Richard Gray (New Zealand), 

Howard Hayden (USA), Martin Hovland (Norway), Olavi Kärner (Estonia), James O’Brien 

(USA), Garth Paltridge (Australia), Donald Rapp (USA), Carl Ribbing (Sweden), Nicola 

Scafetta (USA), John Shade (UK), Gary Sharp, (USA), Jan-Erik Solheim (Norway), Antón 

Uriarte Cantolla (Spain), Gerd Weber (Germany). This is but a short-list.

Response: The EPA thanks the commenter for their input. We have determined that the final 

amendments to subpart W do not significantly increase the burden of data collection. In general, 

these revisions provide greater flexibility for reporters and increase the clarity and congruency of 

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the calculation and reporting requirements. See Section IV of the preamble to the final rule for 

more detailed discussion of the impacts of the final amendments.

24.0 Out of Scope Comments: General Comments Outside of the Scope of 

the Amendments

The EPA received the following comments, which do not specifically address the proposed rule 

and are beyond the scope of this rulemaking. Therefore, the EPA is not responding to these 

comments in this document. 

Commenter Name: Brian Korpics

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2011-0512-0087-A2

Comment Excerpt Number: 10

Comment: We respectfully urge the Agency to strengthen Subpart W in other important ways 

identified in the March 2013 petition. As noted, it has been over a year since this petition was 

submitted to EPA, we have had no response from the Agency on several time sensitive requests 

set out in the petition, and we believe the Agency’s failure to respond is unreasonable. 

Accordingly, we respectfully urge EPA to take immediate action in response to the March 2013 

petition.

Specifically, we requested that the Agency require reporting from facilities and pipelines in the 

gathering and boosting segments, as well as from transmission pipeline blowdown events. We 

also asked that reporters include American Petroleum Institute well identification numbers with 

all data submissions. Finally, we respectfully urged EPA to promote Advanced Innovative 

Monitoring Methods (“AIMM”) to further the use of real-time continuous methane emissions 

monitoring. We believe this is an essential element of a well-designed GHG emissions inventory 

and reporting program for the oil and gas sector. Promoting AIMM could be readily effectuated 

by incorporating into the final Subpart W revisions a mechanism for any member of the public to 

request improvements to the oil and gas emissions reporting program based on new monitoring 

technologies and a commitment by the Agency to promptly act on such requests. We also 

recommend that EPA incorporate final revisions into this rule that set out a commitment by the 

Agency to conduct regular reviews to assess whether new oil and gas monitoring technologies 

are available that could be incorporated into the program.

Response: The EPA thanks the commenter for their input. The commenter's suggestion for 

further revisions to subpart W, including reporting from facilities in the gathering and boosting 

segments and from transmission pipeline blowdown events, collecting API well ID numbers for 

all data, and requiring the use of the commenter described advanced innovative monitoring 

methods, these comments are beyond the scope of this rulemaking. However, the EPA may 

consider the commenter’s suggestions in a future rulemaking.

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Commenter Name: Brian Korpics

Commenter Affiliation: Environmental Defense Fund

Document Control Number: EPA-HQ-OAR-2011-0512-0087-A2

Comment Excerpt Number: 9

Comment: EPA has proposed to revise the definition of sub-basin category found in 40 C.F.R. 

§ 98.238 in order to clarify that “tight gas reservoir rock” generally refers to tight reservoir rock 

formations that produce gas—not those formations that only produce oil. The rule also updates 

the regulation so that all wells that produce hydrocarbon liquids (with or without gas) but do not 

meet the definition of “gas well” contained in the regulation would be categorized as part of the 

oil formation. These changes clarify the differences between oil and gas wells, but now expressly 

exclude emissions data from wells co-producing hydrocarbon liquids and natural gas that do not 

meet the definition of “gas well.”

This proposed clarification to the definition of “gas well” underscores the need for EPA to 

require reporting of completion emissions from oil wells that co-produce natural gas. We 

previously urged the Agency to remedy this issue in our March 2013 petition,24 and recent 

studies have shown that co-producing wells are significant sources of GHG emissions.25

Moreover, on April 15th, EPA released a white paper titled Hydraulically Fractured Oil Well 

Completions and Associated Gas during Ongoing Production.26 This paper summarizes available 

methane and VOC emissions data from hydraulically fractured oil wells and notes that additional 

information could be helpful in characterizing emissions from these sources. The paper further 

notes that effective approaches are available to mitigate these emissions, and requests comment

from both a peer review panel and the public on a variety of emissions-related issues at 

hydraulically fractured oil wells. Subpart W could provide helpful information on this important 

source of emissions. Therefore, we respectfully reiterate our request that EPA undertake a 

rulemaking to clarify that oil wells venting GHG emissions during well completions or 

workovers with hydraulic fracturing must also report emissions under Subpart W.

Footnotes:

24 Clean Air Task Force et al., Petition for Rulemaking and Guidance Ensuring Comprehensive 

Coverage of Methane Sources Under Subpart W of the Greenhouse Gas Reporting Rule—

Petroleum and Natural Gas Systems (Mar. 19, 2013), available at 

http://www2.epa.gov/sites/production/files/documents/ ghgrp_petition_0.pdf.

25 See, e.g., EDF, Co-Producing Wells as a Major Source of Methane Emissions: A Review of 

Recent Analyses (March 2014), available at 

http://blogs.edf.org/energyexchange/files/2014/03/EDF-Co-producing-Wells-Whitepaper.pdf.

26 EPA, Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and 

Associated Gas during Ongoing Production 44 (Apr. 2014), available at 

http://www.epa.gov/airquality/oilandgas/pdfs/ 20140415completions.pdf.

Response: The EPA thanks the commenter for their input. The commenter’s suggestion for 

further revisions to subpart W to address GHG emissions from oil wells venting during well 

completions and workovers with hydraulic fracturing are beyond the scope of this rulemaking. 

However, the EPA may consider the commenter’s suggestions in a future rulemaking.

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Commenter Name: D. E. Ortman

Commenter Affiliation:

Document Control Number: EPA-HQ-OAR-2011-0512-0070

Comment Excerpt Number: 1

Comment: Despite the millions of dollars spent by America’s National Gas Alliance and the 

America Petroleum Institute to convince the American people and Congress that national gas and 

petroleum is “safe,” recent events, including the 12 felony counts filed against Pacific Gas and 

Electric involving safety violations linked to a 2010 natural gas pipeline explosion that killed 

eight people in the San Francisco Bay area; ExxonMobil’s March 2013 burst pipeline, which 

spewed thick Canadian tar sands oil through Mayflower, AR; a February 2014, train derailment 

in Pennsylvania carrying crude oil from Canada, spilling an estimated 3,000 to 4,000 gallons of 

oil; the March 2014 collision of a barge carrying 924,000 gallons of thick, tarry fuel oil with 

another ship in the Houston ship channel; a March 2014 fire at a Williams Northwest Pipeline 

natural gas storage facility in Plymouth, Washington, injuring four workers and leading to the 

evacuation of about 200 people from nearby homes; the March 2014 BP refinery oil spill on 

Lake Michigan in Indiana; and an April 2014 natural gas line explosion near the Williams 

Energy Oak Grove plant construction site in Marshall County, West Virginia, are just the tip in 

an extremely long list of petroleum and natural gas explosions, spills, and disasters all across the 

country.

Although all of these petroleum spills and collisions and natural gas explosions and disasters 

release greenhouse gases, they do not appear to be captured by your revised reporting rule. 

Therefore, unless covered elsewhere, EPA should amend its proposed rule to require reporting of 

petroleum and natural gas emissions of each metric ton released of each GHG from all such 

petroleum spills and collisions and natural gas explosions and disasters.

Response: The EPA thanks the commenter for their input. The commenter’s suggestion for 

further revisions to subpart W to address GHG emissions from spills, collisions, explosions, and 

disasters are beyond the scope of this rulemaking. 

Commenter Name: Anonymous Commenter

Commenter Affiliation:

Document Control Number: EPA-HQ-OAR-2011-0512-0071

Comment Excerpt Number: 1

Comment: For the last 2 centuries there has been no evidence that GHG's have any significant 

influence over climate. The primary GHG is water vapor but acts more as a climate control 

element to moderate and transport heat generated from the sun. Water acts as a moderator and 

heat distribution element, as well as a supply of water vapor, the later which cycles continuously 

in and out of the climate control system.

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All other alleged GHGs are not of sufficient quantity to effect anything on a measurable scale. 

CO2 is more of an indicator of warming then a cause or contributor.

Therefore the EPA has no business of trying to be a GHG climate cop as it can't regulate the 

climate on any level!

Response: The EPA thanks the commenter for their input. The impact of water vapor on climate 

change is beyond the scope of this rulemaking.

Commenter Name: Carrie B. Crumpton

Commenter Affiliation: CONSOL Energy, Inc.

Document Control Number: EPA-HQ-OAR-2011-0512-0080-A1

Comment Excerpt Number: 3

Comment: CONSOL requests that EPA clearly define the difference between workover 

activities and maintenance activities within the language of the rule. This would help to ensure 

clarity in the classification of well-site activities and consistency within the industry as a whole.

Response: The EPA did not propose to revise the definition of “well workovers”. As such, this 

comment is beyond the scope of this rulemaking. We are not amending the definition of “well 

workovers” in this final rule.

Commenter Name: Karin Ritter

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0084-A2

Comment Excerpt Number: 2

Comment: API recommends that language be incorporated into the rule language that will 

clearly differentiate between workover activities and maintenance activities as provided in API’s 

proposed definition for well workover.

Response: The EPA did not propose to revise the definition of “well workovers”. As such, this 

comment is beyond the scope of this rulemaking. We are not amending the definition of “well 

workovers” in this final rule.

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