` 

Response to Public Comments on 

Greenhouse Gas Reporting Rule: 

2015 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems 
` 

September 2015 

Response to Public Comments on the Greenhouse 

Gas Reporting Rule: 2015 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. 
iii 

FOREWORD 

This document provides the EPA’s responses to public comments on the 2015 Revisions and 

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

Notice of Proposed Rulemaking in the Federal Register on December 9, 2014 (79 FR 73148). 

The proposed amendments were designed to add calculation methods and reporting requirements 

for greenhouse gas emissions from gathering and boosting facilities, completions and workovers 

of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines 

between compressor stations, and to add well identification reporting requirements to improve 

the EPA’s ability to verify reported data and enhance transparency. In conjunction with this 

action, we proposed confidentiality determinations for the new data elements contained in these 

amendments. 

During the 77-day public comment period, the EPA received comment letters from industry 

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

the December 9, 2014 proposal. This document provides the 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 and the document control number (DCN) 

assigned to the comment letter are provided. Where possible, the EPA separated comments on 

specific topics into their respective data categories. Within the data categories, similar comment 

excerpts from multiple commenters were combined into a group of comments with a single 

response. 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 referred the reader to the response to another similar 

comment. 

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

In some cases, the EPA provided responses to specific comments or groups of similar comments 

in the preamble to the final rulemaking. Rather than repeating those responses in this document, 

the EPA has referenced the preamble 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, the 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 to the List of 

Commenters. 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-HQ-OAR-2014-0831. 

 
iv 

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. 
v 

Table of Contents 

Page 

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

Table of Contents ............................................................................................................... v

List of Commenters ......................................................................................................... vii

Acronyms and Abbreviations .......................................................................................... ix

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

2.0 Oil Wells with Hydraulic Fracturing ......................................................................... 5

2.1 Applicability and Reporting Requirements ........................................................................ 5

2.2 Reporting Thresholds .......................................................................................................... 9

2.3 Monitoring and Calculation Methods ............................................................................... 12

3.0 Onshore Petroleum and Natural Gas Gathering and Boosting Industry 

Segment ................................................................................................................. 18

3.1 Definitions and Applicability ............................................................................................ 19

3.1.1 Description of Industry Segment ............................................................................. 19

3.1.2 Definition of Facility................................................................................................ 41

3.1.3 Other Definitions ..................................................................................................... 56

3.1.4 Applicability and Emissions to Report .................................................................... 58

3.2 Monitoring and Calculation Methods ............................................................................... 68

3.2.1 Pneumatic Device Venting ...................................................................................... 70

3.2.3 Storage Tank Vented Emissions .............................................................................. 70

3.2.4 Compressor Venting ................................................................................................ 84

3.2.5 Equipment Leaks ..................................................................................................... 86

3.2.6 Gathering Pipeline Equipment Leaks ...................................................................... 93

3.2.7 Fuel Combustion Equipment ................................................................................... 96

3.3 Reporting Requirements ................................................................................................... 98

4.0 Natural Gas Transmission Lines Between Compressor Stations ....................... 103

4.1 Applicability and Definitions .......................................................................................... 103

4.2 Data Reporting Requirements ......................................................................................... 116
vi 

4.3 Blowdown Reporting Categories .................................................................................... 125

4.4 Supportive Comments ..................................................................................................... 128

5.0 Well Identification Numbers .................................................................................. 131

6.0 Compliance Date and Best Available Monitoring Methods ................................ 138

7.0 Disclosure Concerns Related to Exploratory Wells ............................................. 152

8.0 Confidentiality Determinations and Data Category Assignments for New 

Data Elements ..................................................................................................... 156

9.0 Impacts of the Proposed Amendments .................................................................. 159

10.0 Advanced Innovative Monitoring Methods ........................................................ 190

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

Amendments ....................................................................................................... 203

 
vii 

List of Commentersa

Document Control Number Commenter Name Commenter Affiliation 

EPA-HQ-OAR-2014-0831-0055-A Public Hearing: Thomas 

Bach 

Public Hearing: Kinder Morgan, 

Representing Interstate Natural 

Gas Association of America 

EPA-HQ-OAR-2014-0831-0055-B Public Hearing: Karin Ritter Public Hearing: American 

Petroleum Institute 

EPA-HQ-OAR-2014-0831-0057 Anonymous None 

EPA-HQ-OAR-2014-0831-0060b T. Cole None 

EPA-HQ-OAR-2014-0831-0061-A2 Kerry Kelly Waste Management 

EPA-HQ-OAR-2014-0831-0125-A1 Kathleen Sgamma Western Energy Alliance and 

American Exploration & 

Production Council (AXPC) 

EPA-HQ-OAR-2014-0831-0130-A1 Thure Cannon Texas Pipeline Association 

(TPA)c

EPA-HQ-OAR-2014-0831-0131-A1 Anonymous None 

EPA-HQ-OAR-2014-0831-0132-A1 Mark F. Sutton Gas Processors Association 

(GPA) 

EPA-HQ-OAR-2014-0831-0133-A1 Pamela F. Faggert Dominion Resources Services, 

Inc.d

EPA-HQ-OAR-2014-0831-0134-A1 Gretchen C. Kern Pioneer Natural Resources USA, 

Inc. 

EPA-HQ-OAR-2014-0831-0135-A1 Kelly L. Guertin DTE Energy 

EPA-HQ-OAR-2014-0831-0136-A2 Pamela Lacey American Gas Association 

(AGA)e

EPA-HQ-OAR-2014-0831-0137-A2 Karin Ritter American Petroleum Institute 

(API)f

EPA-HQ-OAR-2014-0831-0139-A2 Environmental Defense 

Fund, Sierra Club, Clean 

Air Task Force, and Natural 

Resources Defense Council 

Environmental Defense Fund, 

Sierra Club, Clean Air Task 

Force, and Natural Resources 

Defense Council 

EPA-HQ-OAR-2014-0831-0140-A1 Theresa Pugh Interstate Natural Gas 

Association of America 

(INGAA)g

EPA-HQ-OAR-2014-0831-0141-A1 C. William Giraud Concho Resources Inc. 

EPA-HQ-OAR-2014-0831-0142-A1 Thomas Bach Kinder Morgan, Inc. 

EPA-HQ-OAR-2014-0831-0143-A1 Douglas Jordan Southwestern Energy 

a

 This list of commenters only includes comments on the proposed amendments to 40 CFR part 98, subpart W of the 

Greenhouse Gas Reporting Program (GHGRP). Several comments requesting regulation of methane emissions are 

not included, as the GHGRP is specific to mandatory reporting of methane emissions. 

b

 Comment letter not uploaded to the docket; comments are not included in this document. 

c

 The comments by TPA were also supported by the Gas Processors Association (Docket ID No. EPA-HQ-OAR2014-0831-0132-A1). 

d

 Comment letter also submitted as EPA-HQ-OAR-2014-0831-0138-A2; all comments excerpted under Commenter 

Number EPA-HQ-OAR-2014-0831-0133 in this document. 

e

 The comments by AGA were also supported by DTE Energy (Docket ID No. EPA-HQ-OAR-2014-0831-0135-

A1). 
viii 

f

 The comments by API with respect to the use of well identification numbers were also supported by Kinder 

Morgan (Docket ID No. EPA-HQ-OAR-2014-0831-0142-A1). The comments by API were also generally 

supported by the Gas Processors Association (Docket ID No. EPA-HQ-OAR-2014-0831-0132-A1), except GPA 

stated that it did not agree with or support the basin reporting and thresholds approach in the proposed rule. 

g

 The comments by INGAA were also supported by the Gas Processors Association (Docket ID No. EPA-HQ-OAR2014-0831-0132-A1) and DTE Energy (Docket ID No. EPA-HQ-OAR-2014-0831-0135-A1). The comments by 

INGAA with respect to clarifying the definition of “blowdown” in the context of pipeline blowdown reporting of 

natural gas transmission lines between compressor stations, advanced innovative monitoring methods, and 

BAMM were also supported by Kinder Morgan (Docket ID No. EPA-HQ-OAR-2014-0831-0142-A1). 

 
ix 

Acronyms and Abbreviations 

AAPG American Association of Petroleum Geologists 

AGA American Gas Association 

AGR acid gas removal 

API American Petroleum Institute 

ARP Acid Rain Program 

AXPC American Exploration & Production Council 

BAMM best available monitoring methods 

bbl barrels 

bpd barrels per day 

Btu British thermal units 

CAA Clean Air Act 

CBI confidential business information 

CEMS continuous emissions monitors 

CFR Code of Federal Regulations 

CH4 methane 

COC Code of Conduct 

CO2 carbon dioxide 

CO2e carbon dioxide equivalent 

CRDS cavity ring-down spectroscopy 

DIAL differential absorption lidar 

DOT Department of Transportation 

DR designated representative 

Dth dekatherms 

EIA Energy Information Administration 

EPA U.S. Environmental Protection Agency 

ESD emergency shut-down 

FAQ Frequently Asked Questions 

FERC Federal Energy Regulatory Commission 

FR Federal Register 
x 

FTIR Fourier Transform Infrared 

GHG greenhouse gas 

GHGRP Greenhouse Gas Reporting Program 

GHGRR Greenhouse Gas Reporting Rule 

GOR gas to oil ratio 

GPA Gas Processors Association 

GRI Gas Research Institute 

HARC Houston Advanced Research Center 

HP horsepower 

INGAA Interstate Natural Gas Association of America 

mcf thousand cubic feet 

MMscf million standard cubic feet 

MMT million metric tons 

MSW municipal solid waste 

mt metric tons 

N2O nitrous oxide 

NESHAP National Emission Standards for Hazardous Air Pollutants 

NGL natural gas liquids 

NGSA Natural Gas Policy Act 

NSPS new source performance standards 

OMB Office of Management and Budget 

ONGGB Onshore Natural Gas Gathering and Boosting 

PHMSA Pipeline and Hazardous Materials Safety Administration 

PSD Prevention of Significant Deterioration 

PRA Paperwork Reduction Act 

psi pound per square inch 

psia pound per square inch actual 

QA/QC quality assurance/quality control 

REC reduced emissions completion 

scf standard cubic feet 

SO2 sulfur dioxide 
xi 

STB stock tank barrel 

TCEQ Texas Commission on Environmental Quality 

TDL tunable diode laser 

TPA Texas Pipeline Association 

TSD Technical Support Document 

U.S. United States 
1 

1.0 General Comments 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Comment Number: EPA-HQ-OAR-2014-0831-0057 

Page(s): 1 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Comment Number: EPA-HQ-OAR-2014-0831-0131 

Page(s): 1 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 1-2 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 15 

Comment 1: Commenter 0057: I am making this comment as a private citizen in that I support 

what I consider reasonable regulations to protect our air and water. I simply fail to believe that 

most Corporations will act in the public interest without government regulations which keep 

them honest. I therefore support the proposed EPA guidelines regulating methane. 

Commenter 0131: I strongly support the proposal from the Environmental Protection Agency to 

establish reporting guidelines of greenhouse gas emissions for petroleum and natural gas 

systems. Due to the impact of greenhouse gas (GHG) emissions on environmental and public 

health sustainability, it appears that the regulations are long overdue. In 2013, GHG emissions 

from petroleum and natural gas systems produced 224 million metric tons of CO2e, second only 

to power plants in the United States (U.S. Environmental Protection Agency, 2014). The 

emission of greenhouse gases into the environment creates an increase in the earth’s temperature 

contributing to global warming and air pollution. The effects of air pollution negatively impact 

human health by contributing to cardiac, respiratory, and pulmonary systems diseases (Friis, 

2012). 

In accordance with the Environmental Protection Agency rule proposal, I further support the 

need to establish comprehensive methane emission reporting guidelines, as they have been 

previously overlooked. In relation to other greenhouse gases, methane is a significant contributor 

to global warming and air pollution. Methane’s global warming potential is twenty times greater 

than that of carbon dioxide, and methane emissions have increased by 13.6 percent from 1990-
2 

2010 (U.S. Environmental Protection Agency, 2012). Methane becomes potentially explosive 

when mixed with air, which can cause lower and upper exposure levels between five to fifteen 

percent (Agency for Toxic Substances and Disease Registry, 2010). Due to the volatility of 

methane, failure to calculate and record emissions could create occupational safety hazards and 

public health risks particularly when natural gas systems occur within community settings. 

It is important to understand that the emission of these greenhouse gasses can take a serious toll 

on our society. By not recording these emissions, it is difficult to gauge the effect it is having on 

environmental and public health. The data collected could be used to strengthen the President’s 

Climate Action Plan to reduce methane emissions that occur during anthropogenic practices. 

Furthermore, the data could be used to enforce the need for a conservation approach to reducing 

greenhouse gas emissions. 

References 

Agency for Toxic Substances and Disease Registry. (2010, May 13). Public health assessments 

and consultations. Retrieved February 19, 2015, from http://www.atsdr.cdc.gov/hac/pha/ 

pha.asp?docid=1372&pg=1 

Friis, R. H. (2012). Essentials of environmental health (2nd ed.). Sudbury, MA: Jones & Bartlett 

Learning. 

U.S. Environmental Protection Agency. (2012, April 15.). Inventory of U.S. greenhouse gas 

Emissions and sinks: 1990-2010. Retrieved February 19, 2012 from 

http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2012-MainText-pdf. 

U.S. Environmental Protection Agency. (2014, August 18). Facility level information on 

greenhouse gases tool. Retrieved February 19, 2015, from http://ghgdata.epa.gov/ghgp/main.do. 

Commenter 0139: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and Natural 

Resources Defense Council appreciate the opportunity to provide these comments on EPA’s 

proposed 2015 revisions and confidentiality determinations for the petroleum and natural gas 

systems component of the Greenhouse Gas Reporting Program (“Subpart W”).1

 We strongly 

support rigorous, timely, and transparent emissions reporting for the oil and natural gas sector. 

We urge the agency to promptly finalize strong reporting requirements for the three emissions 

sources covered by this proposed rule, none of which are currently required to monitor, report, 

and disclose their emissions. 

Rigorous reporting of greenhouse gas emissions from gathering and boosting systems, 

transmission pipeline blowdowns, and completions and workovers of oil wells with hydraulic 

fracturing will deepen understanding of emissions from these important sources,2

 which is 

especially important in light of the increasing growth of production in tight-oil formations, like 

the Bakken and Eagle Ford, the already significant national network of gathering and boosting 

infrastructure, and the potential expansion of this infrastructure. Rigorous reporting will likewise 
3 

help to enhance public transparency for communities in close proximity to this development 

while promoting accountability among operators. 

Furthermore, transparent, accurate emissions data are important to protect public health and the 

environment. As EPA summarized in the 2012 New Source Performance Standards for the Oil 

and Natural Gas Sector, 

[t]he data submitted under [Subpart W] will provide important information on the 

location and magnitude of GHG emissions from petroleum and natural gas 

systems and will allow petroleum and natural gas facilities to track their own 

emissions, compare them to similar facilities and aid in identifying . . . 

opportunities to reduce emissions in the future . . . .3

Gathering rigorous and transparent emissions information from these segments is also consistent 

with commitments the Obama Administration has made in its Strategy to Reduce Methane 

Emissions (which directs EPA to “address potential gaps in coverage” of regulatory requirements 

and to “ensure high quality data reporting”4) and in its recently-announced steps to reduce 

methane emissions (which commit to strengthen the Reporting Program to “require reporting in 

all segments of the industry” and to consider deploying advanced technologies to “improve the 

overall accuracy and transparency of reported data”5). 

Section 114 of the Clean Air Act provides EPA with clear authority to require monitoring and 

reporting of emissions data from sources in the petroleum and natural gas sector. Commenters 

strongly support EPA's proposed actions to improve Subpart W, and we incorporate by reference 

into the administrative docket for this rulemaking all studies, analyses, and other documents 

cited in these comments. 

Footnotes: 

1

 Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems, 79 Fed. Reg. 73,148 (Dec. 9, 2014). 

2

 EPA estimates that the oil and gas sector is the largest industrial source of U.S. methane 

emissions. Expanding reporting to the segments included in EPA’s proposal will improve 

understanding of the sector’s overall emissions. Recent top-down studies, conducted with aircraft 

overflight readings, show that emissions from the oil and gas sector may be greater than 

estimates based on official inventories. See, e.g., A.R. Brandt et al., 2014, Methane Leaks from 

North American Natural Gas Systems, 343 SCIENCE 33-35 (2014) (suggesting emissions from 

the oil and natural gas sector may be greater than published inventories); G. Pétron, A new look 

at methane and nonmethane hydrocarbon emissions from oil and natural gas operations in the 

Colorado Denver-Julesberg Basin, 119 J. GEOPHYS. RES. ATMOS. 6836 (2014) (estimating 

emissions from oil and gas sources in the most densely drilled area in the Denver-Julesburg 

Basin in Weld County, CO may be 3 times higher than estimated based on Reporting Program 

data). 

3

 77 Fed. Reg. 49,490, 49,513-14 (Aug. 16, 2012). 
4 

4

 The White House, Climate Action Plan: Strategy to Reduce Methane Emissions, at 13 (Mar. 

2014), available at 

http://www.whitehouse.gov/sites/default/files/strategy_to_reduce_methane_emissions_2014-03-

28_final.pdf. 

5

 The White House, Fact Sheet, Administration Takes Steps Forward on Climate Action Plan by 

Announcing Actions to Cut Methane Emissions (Jan. 14, 2015), available at 

http://www.whitehouse.gov/the-pressoffice/ 2015/01/14/fact-sheet-administration-takes-stepsforward-climate-action-plan-anno-1 (emphasis added) [hereinafter Methane Announcement Fact 

Sheet]. 

Commenter 0139: Emissions reporting requirements for the sources included in EPA’s proposed 

rule will help create transparency for individuals living in close proximity to oil and gas 

development, protect public health and the environment, and create accountability among 

companies reporting emissions. We strongly support the agency’s proposed actions and 

respectfully urge it to pursue the additional improvements we have described above to further 

enhance the rigor and transparency of Reporting Program data. 

Response 1: The EPA thanks the commenters 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. 

 
5 

2.0 Oil Wells with Hydraulic Fracturing 

2.1 Applicability and Reporting Requirements 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 14 

Comment 1: Commenters also support EPA’s proposal to extend reporting requirements to 

completions and workovers of oil wells with hydraulic fracturing. Methane emissions from coproducing wells can be substantial and the agency’s efforts to gather data from this significant 

emissions source are important. 

Response 1: The EPA thanks the commenter for their support. The EPA is finalizing the 

reporting requirements for completions and workovers of oil wells with hydraulic fracturing with 

minor revisions. See Section II.A of the preamble to the final rule for more information. 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 2 

Commenter Name: C. William Giraud 

Commenter Affiliation: Concho Resources Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0141 

Page(s): 6 

Comment 2: Commenter 0125: We have concerns with the inclusion of “workovers with 

hydraulic fracturing.” It is our understanding that the EPA is interpreting a workover as 

equivalent to a recompletion. A workover is an operation that affects the well itself and typically 

does not involve hydraulic fracturing. Workovers are performed during major maintenance or 

remedial treatments on a well, such as removing or replacing production tubing, or cleaning out 

accumulations of substances that may inhibit production. In contrast, a recompletion consists of a 

process in which hydrocarbon-bearing formations are “re-stimulated” by means such as refracturing prior producing formations or hydraulic fracturing different formations from the same 

wellbore. 

Commenter 0141: EPA should delete from the proposed Subpart W Revisions the category for 

“workovers with hydraulic fracturing.” EPA appears to mistakenly consider a “workover” to be 

the equivalent of a “recompletion.” The two activities, however, are quite different. Workovers 

typically do not involve hydraulic fracturing. Instead, workovers are operations on the well itself 

and generally involve major maintenance or remedial treatments on an oil and/or gas well, like 
6 

removing or replacing production tubing, or cleaning out accumulations of substances that may 

inhibit production in the tubing. Recompletions, on the other hand, involve “re-stimulation” of 

the hydrocarbon-bearing formations through, among other things, re-fracturing prior producing 

formations or hydraulic fracturing of different formations from the same wellbore. 

Response 2: For the purposes of 40 CFR part 98, a “well workover” is defined in 40 CFR 98.6 

of subpart A as follows: 

Well workover means the process(es) of performing one or more of a variety of 

remedial operations on producing petroleum and natural gas wells to try to 

increase production. This process also includes high-rate flowback of injected gas, 

water, oil, and proppant used to re-fracture and prop-open new fractures in 

existing low permeability gas reservoirs, steps that may vent large quantities of 

produced gas to the atmosphere. 

For well workovers with hydraulic fracturing, the definition includes the characteristics of both 

workovers and recompletions as described by the commenters. This definition and the definition 

of “well completions” were reviewed in 2014 (79 FR 70352; November 25, 2014), and the only 

change was to remove the term “re-fracture” in the definition of “well completions,” to clarify 

that re-fracturing is a well workover but not a well completion. Therefore, it is consistent with 

our stated intent to include “recompletions” in the existing subpart A definition of “well 

workover.” We also note that GHG emissions reporting is not required for oil well workovers 

(including “recompletions”) that do not involve hydraulic fracturing. 

Commenter Name: Public Hearing: Karin Ritter 

Commenter Affiliation: Public Hearing: American Petroleum Institute 

Comment Number: EPA-HQ-OAR-2014-0831-0055-B 

Page(s): 25-26 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 2 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 4-5 

Comment 3: Commenter 0055-B: EPA is proposing to add provisions for the reporting of 

greenhouse gas emissions from oil well completions and work-overs with hydraulic fracturing, 

which are consistent with the current requirements for gas well completions and workovers with 

hydraulic fracturing. The proposed provision applies expanded measurement requirements to oil 

well completions with hydraulic fracturing that use flaring and reduced emission completions, or 

RECs. API notes that EPA assumes that operators know in advance whether a completion or 
7 

workover will require flaring. In reality, it is not possible to determine whether a well will clean 

up quickly with no need to flare or vent prior to beginning the actual flowback. Therefore, flaring 

versus venting cannot be the deciding criteria for planning which wells to measure or collect 

information to enable the calculation of the flow-back volume. 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 impossibility for operators. API is 

requesting that upon promulgation, EPA establish only two categories for reporting emissions 

from completions and workovers with hydraulic fracturing, namely venting without REC and 

vented with REC and flaring. 

Commenter 0137: Expanding the well type categories that require measurement for oil well 

completions and workovers with hydraulic fracturing – EPA has expanded the number of 

measurements or calculations required for each sub-basin and well type combinations for 

completions OR workovers to include with and without flaring, and with and without REC. 

There are up to 80 possible combinations each requiring separate measurements or calculations. 

API objects to expanding the number of measurements and has demonstrated that two categories 

(with and without REC) with 20 possible measurement combinations are sufficient to represent 

all completions and workovers. 

Commenter 0137: Where Equation W-10A is used, EPA has expanded the number of 

measurements or calculations required for each sub-basin (the four gas formation types in 

addition to oil formations) and well type (horizontal or vertical) combinations for completions 

OR workovers to include with and without flaring, and with and without REC. There are now 40 

possible combinations for completions and 40 possible combinations for workovers that each 

requires separate measurements or calculations. API objects to expanding the number of 

measurements. 

EPA assumes that operators know in advance whether a completion or workover will require 

flaring. In reality, it is not possible to determine whether a well will clean-up quickly with no 

need to flare or vent prior to beginning the actual flowback. Therefore, flaring versus venting 

cannot be a criterion for planning which wells to measure or collect information to enable 

calculating the flowback volume. 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. 

It appears that EPA is constructing the reporting rule to align with the emission categories used 

in the national GHG inventory. This is not necessary as there is sufficient information to inform 

the inventory without further expanding the reporting rule. Ambiguity in the current eGGRT data 

is resolved with definitions for reduced emission completions and reduced emission workovers 

in the November 2014 final rule. 

Some reporters voluntarily reported emissions data for oil well completions and workovers with 

hydraulic fracturing in their 2011 through 2013 GHGRP data. API sorted the GHGRP data to 

examine those data sets reporting emissions data for oil formations where either Equations 10-B 

or 10-A were used with measured emissions. This approach excludes data sets which relied on 
8 

estimating emissions using the choke flow equation. This voluntarily reported data resulted in 

149 data sets providing emissions data for 1675 completions and 226 workovers for the years 

2011 through 2013 combined. This is a substantial amount of information. Even with some 

ambiguities in the reported data, there is sufficient information to develop emission factors. 

Table 1 compares the resulting emission factors for oil wells with hydraulic fracturing using the 

4 data categories proposed by EPA for the national inventory for gas well completions and 

workovers, to the two data categories suggested by API. Although there appear to be some data 

outliers, in general the emission data currently available shows that vented workovers and 

completions without REC have a distinctly higher emission rate than completions and workovers 

flared without REC, flared with REC, and vented with REC. It is also clear that using only the 

two proposed categories for deriving emission factors maximizes the use of the available data 

sets as compared to the number of data sets that could be used if one needs to subdivide the data 

into the four categories specified by the EPA. API objects to the expansion of the well type 

parameters. Additional granularity in the measurement requirements is not supported by the data 

currently available, as demonstrated by review of the data for gas well completions and 

workovers, and the reported data for oil well completions and workovers. Industry should not be 

further burdened by additional measurement and reporting requirements that end up with 

redundant information and do not contribute to improved characterization of GHG emissions 

from completions and workovers. 

Table 1. Analysis of GHGRP Data for Oil Well Completions and Workovers with 

Hydraulic Fracturing 

Emission 

Factor 

Category 

All Years 2013 2012 2011 

tonnes 

CH4/ 

event 

# 

events 

tonnes 

CH4/ 

event 

# 

events 

tonnes 

CH4/ 

event 

# 

events 

tonnes 

CH4/ 

event 

# 

events 

EPA 

Emission 

Factor 

Approach 

Vented w/out 

REC 

22.2 349 0.0 11 15.7 214 35.5 124 

Flared w/out 

REC 

3.39 213 0.2 35 7.8 71 1.5 107 

Vented with 

REC 

3.94 168 8.0 10 4.0 112 2.9 46 

Flared with 

REC 

13.31 15 - 0 4.2 8 23.7 7 

API 

Emission 

Factor 

Approach* 

Vented w/out 

REC 22.2 349 0.01 11 15.7 214 35.5 124 

Flared + REC 2.97 689 0.6 153 4.5 298 2.6 238 

*Note, the API derived emission factors are not a simple combination of EPA's 3 categories above. API’s analysis 

results in fewer “ambiguous” data sets, thus 689 events are used for deriving the emission factor for the ‘Flared + 

REC’ category as compared with the total of 396 events that could be categorized as either ‘Flared w/o REC’, 

‘Vented w/REC’, or ‘Flared w/REC’. 

Response 3: In the final rule, the EPA is maintaining the requirement to measure emissions 

separately per sub-basin and well type combination instead of aggregations of these distinct 
9 

operational practices. The disaggregated data will improve data quality for emissions from well 

completions and workovers with hydraulic fracturing. The EPA expects that operational 

practices will generally be the same in a given sub-basin and considers it unlikely that a reporter 

would conduct drilling activities for a given sub-basin in all the different well type combinations 

of vertical or horizontal, with flaring or without flaring, and REC/workover or no 

REC/workover. For example, oil well hydraulic fracturing focused on horizontal drilling in a 

shale gas formation in a county using reduced emissions completions and flaring would 

constitute one category. Therefore, we disagree with the commenters that the new requirements 

will impose a significant additional burden on reporters. 

2.2 Reporting Thresholds 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 8 

Comment 1: API believes that it is important to establish a GOR threshold where oil wells with 

a GOR that is equal or lower than the specified threshold would not be subject to the monitoring 

and reporting requirements. Based on member experience, oil wells with GOR values less than 

300 do not have sufficient gas to operate a separator. In some cases, the separators are operated 

by using pumps to move the fluid out of the vessels or by adding make-up gas to the system to 

ensure the necessary gas pressure. Based on operational experience, API recommends that EPA 

establish a GOR threshold of 300. For completions or workovers at wells with GOR below this 

threshold, emissions should not need to be reported. 

Response 1: The final monitoring and reporting requirements do not apply to completions and 

workovers of oil wells with hydraulic fracturing that have a GOR of less than 300 scf/STB. See 

Section II.A of the preamble to the final rule for more information. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 8 

Comment 2: In order for a well to flow back, the reservoir pressure has to be greater than the 

hydraulic pressure of the fluid column in the well. Therefore, API proposes a simplified 

approach where a reservoir pressure that is lower than the vertical pressure gradient of 0.4645 

psi/ft should be excluded from the monitoring and GHG reporting requirements. Note, the 

pressure gradient of 0.4645 psi/ft is taken from Gas STAR Lessons Learned on Reduced 

Emissions Completions for Hydraulically Fractured Natural Gas Wells.2

Footnotes: 
10 

2

 USEPA; Lessons Learned from Natural Gas STAR Partners; Reduced Emissions Completions 

for Hydraulically Fractured Natural Gas Wells; 2011. 

http://www.epa.gov/gasstar/documents/reduced_emissions completions.pdf 

Response 2: The final rule does not include a minimum well or reservoir pressure threshold for 

completions and workovers of oil wells with hydraulic fracturing. See Section II.A.2 of the 

preamble to the final rule for more information. 

Commenter Name: Gretchen C. Kern 

Commenter Affiliation: Pioneer Natural Resources USA, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0134 

Page(s): 4-5 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 14 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 4-5 

Comment 3: Commenter 0134: EPA should include a threshold below which oil wells with low 

GOR and low pressure are exempt from reporting emissions during completions with hydraulic 

fracturing 

Pioneer operates wells in certain fields and operations that have a very low GOR and pressure. 

The flowback of these wells primarily consists of water with little to no gas present. Pioneer 

recently began this drilling program and thus, does not have comprehensive data to provide to 

EPA at this time in support of specific threshold levels. The work involved in measuring the 

flowback and reporting of these minimal to nil emissions would outweigh any contribution of 

these emissions to the overall source category totals since these emissions are so insignificant. It 

seems reasonable that a threshold should be determined so that specific low pressure and low 

GOR are excluded from the rule and operators do not have to expend their time and resources 

including these minimal, if any, emissions in their GHG reporting. Rather, efforts expended on 

these types of wells should be redirected to the larger source categories that have more 

significant emissions in furtherance of EPA’s intent to understand the majority of GHG 

emissions associated with our operations. Therefore, Pioneer requests that EPA include 

thresholds in the final rule under which low pressure and low GOR oil wells are exempt from 

reporting under the proposed Gathering and Boosting segment of Subpart W.
11 

Commenter 0139: EPA invites comment on whether to establish gas-to-oil ratio or minimum 

well pressure thresholds below which wells would not be subject to the monitoring and reporting 

requirements for emissions from well completions and workovers.62 We urge EPA to require 

monitoring and reporting for all such wells. If however, the agency choses to establish such a 

threshold, it should ensure that the rules include all significant emissions sources and that 

sources are able to clearly determine whether they are required to report. 

Footnotes: 

62 79 Fed. Reg. at 73,152. 

Commenter 0142: EPA specifically seeks comments on whether EPA should establish a 

minimum GOR threshold such that oil wells with a very low GOR would not be subject to 

monitoring and reporting requirements for GHG emissions from completions and work overs 

with hydraulic fracturing or whether EPA should establish a minimum well pressure such that oil 

wells operating below a certain pressure would not be subject to monitoring and reporting 

requirements. See 79 Fed. Reg. at 73,152. Kinder Morgan agrees with and supports the use of a 

GOR threshold to determine whether direct measurement of gas flow is achievable. Oil wells in 

mature fields often have low GOR and there is often not enough gas flow to measure the flow. 

As a result, EPA should establish a GOR threshold below which the gas flow is too minimal to 

operate a separator, thus making direct measurement unachievable. In addition to the GOR 

threshold, Kinder Morgan supports establishment of minimum thresholds using minimum 

reservoir pressures which, in many cases, will be a more effective measurement than establishing 

a minimum GOR threshold. Kinder Morgan supports establishment of a minimum reservoir 

pressure such that wells operating below a certain pressure would not be subject to the reporting 

and monitoring requirements. The pressure limit would be dependent on the depth of the well in 

relation to the reservoir pressure, which would need to be greater than the vertical lift of 0.433 

psi/ft of the fluid column. A hydraulically structured well completion or work over will have a 

mixed column of water, muds, and other drilling fluids that will need to be raised from the 

completion depths. The pressure needed to simply clear the well varies based on the density of 

the materials in the column and the depth of the well. Kinder Morgan proposes EPA include the 

following language as a subpart to 40 C.F.R. 98.233(c)(6) and (8): 

Proposed New 40 C.F.R. 98.233(c)(23): With respect to oil wells in the source 

types listed in 98.233(c)(6) and (8) above, operators only need to monitor and 

report emissions if (1) the pressure of the reservoir during oil well completions 

and work overs is greater than the pressure gradient of 0.433 psi/ft and (2) the 

Gas-to-Oil ratio (GOR) is great enough to operate a separator. 

Thus, Kinder Morgan would support establishing a minimum reservoir pressure threshold and a 

GOR threshold whereby such oil wells would not be subject to monitoring and reporting 

requirements for GHG emissions from completions and work overs with hydraulic fracturing if 

the oil well does not meet both of the thresholds. 

Response 3: The final monitoring and reporting requirements do not apply to completions and 

workovers of oil wells with hydraulic fracturing that have a GOR of less than 300 scf/STB, but 
12 

the final rule does not include a minimum well or reservoir pressure threshold for completions 

and workovers of oil wells with hydraulic fracturing. See Section II.A of the preamble to the 

final rule for the EPA’s response to comments regarding GOR and pressure thresholds. 

2.3 Monitoring and Calculation Methods 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 5 

Comment 1: A high pressure oil reservoir should flow back similar to a gas well completion 

with hydraulic fracturing. However, a low pressure oil well completion may need injection of an 

inert gas, such as N2, to compensate for the lack of reservoir energy. The current equation 

accounts for the nitrogen injected during hydraulic fracturing for energized fracking through the 

term EnFs,p. API recommends the following change to the definition of EnFs,p to account for the 

N2 injected to kick-off flowback: 

EnFs,p = Volume of N2 or other non-GHG gas injected gas in cubic feet at 

standard conditions that was injected into the reservoir well, p, during an 

energized fracture job or during flowback for each well, p, as determined by using 

an appropriate meter according to methods described in section 98.234(b), or by 

using receipts of gas purchases that are used for the energized fracture job or 

injection during flowback. Convert to standard conditions using paragraph (t) of 

this section. If the fracture process did not inject gas into the reservoir or if the 

injected gas is CO2 then EnFs,p is 0. 

Response 1: The EPA agrees that the term “EnFs,p” should include injection of nitrogen gas 

during flowback as well as during energized fracking. The term “EnFs,p” is defined as follows in 

the final rule: 

Volume of N2 injected gas in cubic feet at standard conditions that was injected 

into the reservoir during an energized fracture job or during flowback for each 

well, p, as determined by using an appropriate meter according to methods 

described in § 98.234(b), or by using receipts of gas purchases that are used for 

the energized fracture job or injection during flowback. Convert to standard 

conditions using paragraph (t) of this section. If the fracture process did not inject 

gas into the reservoir or if the injected gas is CO2 then EnFs,p is 0. 
13 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 9-10 

Comment 2: The rule needs to make provision for situations where wells have multi-phase flow 

routed to a central production facility without individual well separation and production 

measurement. Although relevant for gas wells this type of arrangement is more common for oil 

wells. In such cases, some of the parameters necessary for utilizing equations W-10A are not 

available as specified. 

FRMs and FRMi (Eq W-10A) – The term PRs,p (average 30 day production rate in scf/hr) is not 

available where individual well production of oil or gas is not measured on a continuous basis. In 

these cases, the rule should allow for using flow rates determined during individual well 

production tests that are the closest in time to the first 30 days of production following hydraulic 

fracturing. If more than one individual well production test for a particular well is conducted in 

the first 30 days of production following hydraulic fracturing then the average of all individual 

well production tests should be used for the term PRs,p in the calculation of FRMs and FRMi. 

Response 2: The EPA agrees with the suggestions made by the commenter, and these suggested 

changes are incorporated in the final amendments for completions and workovers of oil wells 

with hydraulic fracturing. Note that the operational practices for a “representative” well must be 

considered when determining if the well is considered representative for purposes of Equation 

W-10A. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 10 

Comment 3: The units for the term FVs,p in Equation 10-B are incorrect. This term should be 

expressed as a volume not as a flow rate. Corrections are provided below. 

FVs,p = Flow vVolume of gas vented or flared gas for each well, p, in standard 

cubic feet per hour measured using a recording flow meter (digital or analog) on 

the vent line, as described in 98.233(g), to measure gas flowback during the 

separation period of the completion or workover according to methods set forth in 

section 98.234(b).

Response 3: The EPA agrees with the commenter that the term should be expressed as a volume 

and not as a flow rate. This change is incorporated in the final rule. 
14 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 9 

Comment 4: The rule needs to make provision for oil well completions and workovers 

following hydraulic fracturing where there is no flowback to open tanks/pits and/or no flaring or 

venting once separation begins. 

Equation W-10A: 

If the term Tp,s is zero and the term Tp,i is zero then determination of the terms FRMs, PRs,p, 

EnFs,p, and FRMi should not be required. Reporting in this case should be restricted to the 

number of completions or workovers with hydraulic fracturing having zero emissions. 

If the term Tp,i is zero and the term Tp,s is greater than zero, then determination of the term 

FRMi should not be required. No change in reporting is needed to accommodate this change. 

If the term Tp,s is zero and the term Tp,i is greater than zero then determination of the term 

ENFs,p should not be required. No change in reporting is needed to accommodate this change. 

Equation W-10B: 

If the term FVs,p is zero (no venting or flaring after separation begins), then determination of the 

term EnFs,p should not be required. No change in reporting is needed to accommodate this 

change. 

If the term FVs,p is zero and the term Tp,i is greater than zero, then determination of the term 

FRp,i is not possible as specified. In this case the term FRp,i should be based on the first 

determination of gas flowrate to production. No change in reporting is needed to accommodate 

this change. 

If the term Tp,i is zero then determination of the term FRp,i should not be required. No change to 

the reporting is needed to accommodate this change. 

Response 4: The EPA agrees with the suggestions made by the commenter. These suggested 

clarifications will be incorporated into e-GGRT for reporting of emissions from completions and 

workovers of oil wells with hydraulic fracturing. However, if any of the Equation W-10A terms 

identified by the commenter cannot be determined for one well, then for purposes of Equation 

W-10A, that well cannot be considered “representative” of wells for which determination of that 

term is possible (i.e., the operational practices for the “representative” well must be similar to the 

wells in the sub-basin for which the well is considered representative). For example, if the term 

Tp,i is zero and the reporter cannot determine FRMi for a particular well, then this well cannot be 

considered “representative” of wells for which the term Tp,i is greater than zero. 
15 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 10 

Comment 5: Flowback is not a steady-state process and there are numerous scenarios where the 

well will start and stop flowing produced fluids or require a temporary shut-in to address surface 

or downhole problems. These periods should be not be included in any emission representations. 

Tp,i = Cumulative amount of time of flowback to open tanks/pits, from when gas 

is first detected until sufficient quantities of gas are present to enable separation, 

for the completion or workover, in hours, for each well, p, in a sub-basin and well 

type combination during the reporting year. This may include non-contiguous 

periods of routing to open tanks/pits but does not include periods when the well 

ceases to produce fluids to the surface.

Response 5: The EPA agrees with the suggestion made by the commenter. This change is 

incorporated in the final amendments for completions and workovers of oil wells with hydraulic 

fracturing. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 7 

Commenter Name: C. William Giraud 

Commenter Affiliation: Concho Resources Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0141 

Page(s): 6 

Comment 6: Commenter 0137: API and its members concur that the proposed placement of the 

flow meter is appropriate; downstream of separation and upstream of a vent or flare. However, 

for oil wells with a very low GOR there may not be sufficient gas to operate a separator and 

hence measurement would not be possible. 

Commenter 0141: The Location of the Flow Meter Used to Measure the Gas Flow Rate on a Gas 

Well is an Appropriate Location for the Oil Well Flow Meter. 

In the December 19 notice, EPA states that it is proposing to require Calculation Method 1 for 

calculating inputs to Equations W-12A and W-12B for oil wells. Calculation method 1 relies on 

direct measurement of gas flow rate during flowback to develop calculation inputs. EPA is 

proposing that subpart W would include the same requirements for the location of the flow meter 

used to measure the gas flow rate for an oil well as for the flow meter on a gas well. 79 Fed. Reg. 

at 73,152. 40 C.F.R. 98.233(g)(1)(i) currently directs that, for gas wells completed with hydraulic 

fracturing, a “recording flow meter (digital or analog) shall be installed on the vent line, ahead of 
16 

a flare or vent” to measure the flowback rate. While Concho believes that EPA should either not 

adopt the Subpart W Revisions or should significantly revise the proposed regulations, if the 

agency proceeds with the proposed draft, then Concho believes that it is appropriate to impose 

the same requirement for the location of a flow meter on an oil well as on a gas well. 

Response 6: The EPA thanks the commenters for their support. These revisions are finalized as 

proposed. 

Regarding the comment that it may not be possible to measure wells with a low GOR, we note 

that the EPA is finalizing a GOR threshold for reporting of emissions from completions and 

workovers of oil wells with hydraulic fracturing. Oil wells with a GOR below that threshold 

would not need to be reported. See Section II.A of the preamble to the final rule for more 

information. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 7 

Comment 7: The rule is proposing to add a new Equation W-12C to calculate, rather than 

measure, the value of PRs,p (the average gas production flow rate during the first 30 days of 

production after the completion or workover), which is used as an input to Equation W-10A. In 

the proposed Equation W-12C, the value of PRs,p would be calculated by multiplying the GOR 

of the well by the measured oil production rate during the first 30 days of production after the 

completion or workover to calculate average gas production flow rate. 

Calculating the gas production based on GOR is less accurate. If metered gas data are available 

for the first 30-days of production, API suggests that the measured rates should be used over 

GOR data. 

Response 7: The EPA agrees that for instances where metered gas data are available for the first 

30-days of production, then the measured rates should be used rather than GOR data. The final 

rule specifies that Equation W-12C is an option for calculating the average gas production flow 

rate during the first 30 days of production after the completion or workover only if the flow rate 

is not metered and measured flow rates are not available. 
17 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 7-8 

Comment 8: API agrees that the choke flow calculation provided in Calculation Method 2 is not 

appropriate for the multi-phase flow associated with either gas well or oil well completions and 

workovers. 

API is not aware of any valid choke flow equation that is applicable to multiphase flow that 

occurs during flowback. As previously discussed with EPA, API is working on developing a 

Gilbert-type correlation that can be applied to gas and oil wells where two-phase flow is present 

through a choke orifice. The general approach applies data from a subset of wells to regress the 

equation coefficients, and then these coefficients are used in conjunction with the Gilbert-type 

correlation as a predictive tool for other wells in the basin. API will share results from this work 

with EPA when available. 

Response 8: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed. 

 
18 

3.0 Onshore Petroleum and Natural Gas Gathering and Boosting Industry 

Segment 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 7 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 3 

Comment 1: Commenter 0133: We acknowledge the need to collect and quantify emissions 

from the Gathering and Boosting segment to achieve more complete coverage of the petroleum 

and natural gas systems sector. The proposal is a good first step towards that objective. Although 

this new segment requires substantial new inventory and emissions tracking obligations for 

gathering pipelines, separators, compressors, acid gas removal units, dehydrators, pneumatic 

devices and pumps, storage vessels, engines, boilers, heaters, and flares, we are in general 

agreement that using methodologies already existing in the rule provide consistency and reduces 

the reporting burden. 

Commenter 0139: We strongly support EPA’s proposal to require reporting from the gathering 

and boosting segment, which contains significant sources of emissions, and for which additional 

information concerning the number and extent of emissions sources will be helpful in further 

characterizing those emissions. 

Analysis conducted by ICF International in March 2014 estimates that annual process emissions 

from the gathering and boosting segment are approximately 0.8 million metric tons (MMT) of 

methane, or 20 MMT of CO2e (using a 100-year GWP of 25).6

 Building on the ICF analysis, 

EPA calculates that total annual process and combustion emissions from the segment amount to 

approximately 43.5 MMT CO2e.7

 These emissions not only constitute significant greenhouse gas 

pollution, but also represent a loss of large quantities of valuable gas. For instance, analysis 

conducted by Clearstone Engineering found that gathering segment compressor stations lost an 

average of 97 metric tons of gas per year per facility, amounting to thousands of dollars in lost 

gas value from leaking components.8

 In addition, in a recently-released study in the Journal of 

Environmental Science and Technology (“ES&T Study”), researchers measured 114 gathering 

facilities, finding emissions ranging from 0.6 to 600 standard cubic feet of methane leaking per 

minute (scf/m).9

 On average, the methane emitted from just one such gathering facility is 

approximately 12,000 metric tons of CO2e, greater than the average 2013 methane emissions 

from a natural gas transmission facility reporting under Subpart W (which themselves are 

significant). 

Footnotes: 
19 

6

 ICF International, Economic Analysis of Methane Emission Reduction Opportunities in the 

U.S. Onshore Oil and Natural Gas Industries, at 3-3 (Mar. 2014), available at 

http://www.edf.org/energy/icf-methane-cost-curve-report [hereinafter ICF Cost Curve Report]. 

This figure is a conservative estimate, as it is based on a dated 100-year global warming potential 

for methane of 25. We urge EPA to use the latest, most scientifically rigorous figures for the 

global warming potential of methane. The Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change (IPCC) concluded that methane is a much more potent driver of 

climate change than previously understood – with a global warming potential as much as 34 

times greater than carbon dioxide over a 100-year time frame, and as much as 86 times greater 

than carbon dioxide over a 20-year time frame. Myhre, G. et al., Anthropogenic and Natural 

Radiative Forcing, in CLIMATE CHANGE 2013: THE PHYSICAL SCIENCE BASIS, 

CONTRIBUTION OF WORKING GROUP I TO FIFTH ASSESSMENT REPORT OF THE 

IPCC, 714 tbl. 8.7 (2013), available at http://www.ipcc.ch/report/ar5/wg1/. 

7

 EPA, Greenhouse Gas Reporting Rule: Technical Support for 2015 Revisions and 

Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule, Doc. 

EPA-HQ-OAR-2014-0831-0018, at 7 (Nov. 13, 2014) [hereinafter Proposal TSD]. 

8

 Clearstone Engineering, Cost-Effective Directed Inspection and Maintenance Control 

Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations and 

Well Sites, at 28 (2006); see also EDF, Oil and Natural Gas Sector: Compressors, Peer Review 

Responses of Environmental Defense Fund, at 5 (June 16, 2014) (indicating that average 

emissions from gathering segment compressors are larger than existing EPA estimates). 

9

 Mitchell, Austin L., et al., Measurements of Methane Emissions from Natural Gas Gathering 

Facilities and Processing Plants: Measurement Results, 49 ENVTL. SCI. & TECH., at A (2015) 

[hereinafter ES&T Study]. 

Response 1: The EPA thanks the commenters for their support for reporting emissions from the 

Onshore Petroleum and Natural Gas Gathering and Boosting segment. 

3.1 Definitions and Applicability 

3.1.1 Description of Industry Segment 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 3 

Comment 1: GPA commends EPA for defining gathering and boosting as its own industry 

segment. 

Gathering and boosting is a unique operation with a unique purpose. Historical treatment of this 

industry segment – either including it with production or processing – has led to confusion with 
20 

understanding industry data. We encourage EPA to continue to distinguish gathering and 

boosting as its own industry segment in other programs, rules, inventories, etc. 

Response 1: The EPA thanks the commenter for their support. The requirements for gathering 

and boosting facilities are being finalized as a separate industry segment from Onshore 

Petroleum and Natural Gas Production and Onshore Natural Gas Processing, as proposed. 

Commenter Name: Public Hearing: Karin Ritter 

Commenter Affiliation: Public Hearing: American Petroleum Institute 

Comment Number: EPA-HQ-OAR-2014-0831-0055-B 

Page(s): 24 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 10 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 11 

Comment 2: Commenter 0055-B: API appreciates the fact that EPA is citing API 

Recommended Practice 80 as a guide to the definition of the new reporting segment of onshore 

petroleum and natural gas gathering and boosting. API also supports the statement that this new 

reporting segment would not include equipment and pipelines that are reported under any other 

industry segment defined in Subpart W. 

Commenter 0137: API appreciates the fact that the EPA is citing API Recommended Practice 80 

as a guide to the definition of the new reporting segment of Onshore Petroleum and Natural Gas 

Gathering and Boosting. 

Commenter 0137: API supports the statement that this new reporting segment would not include 

equipment and pipelines that are reported under any other industry segment defined in Subpart 

W. 

Response 2: The EPA thanks the commenters for their support. The definition of facility for the 

Onshore Petroleum and Natural Gas Gathering and Boosting segment, which specifies that the 

facility does not include equipment and pipelines that are part of any other industry segment, is 

finalized as proposed. In addition, similar language is included in the finalized 40 CFR 

98.230(a)(9); see Response 10 in this section for more information. 
21 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 3 

Commenter Name: Gretchen C. Kern 

Commenter Affiliation: Pioneer Natural Resources USA, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0134 

Page(s): 2-3 

Comment 3: Commenter 0132: The proposed source category definition includes the phrase, 

“Gathering and boosting equipment includes, but is not limited to . . . .”1 The listed equipment is 

the only equipment in the Onshore Petroleum and Natural Gas Production segment that could be 

subject to reporting requirements. Accordingly, the phrase “but is not limited to” introduces 

unnecessary imprecision and uncertainty. 

Footnotes: 

1

 Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems, 79 Fed. Reg. 73,148, 73,175 (Dec. 9, 2014) (Proposed 

Rule). 

Commenter 0134: Pioneer agrees with GPA that the “but is not limited to” language should be 

struck from the definition of the “Onshore Petroleum and Natural Gas Gathering and Boosting’’ 

proposed source category in 98.230. 

EPA has listed the equipment to be included in this source category: 

98.230(a)(9) ... “Gathering and boosting equipment includes, but is not limited 

to, gathering pipelines, separators, compressors, acid gas removal units, 

dehydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters 

and flares.”3

Including “but is not limited to” leaves the rule open to interpretation and complicates 

compliance because EPA has not definitively limited the equipment that the operator must 

include in their reporting. In the preamble, pages 73154-73155, EPA explains that they are 

proposing to use current methods in Subpart W for monitoring and calculating emissions for the 

gathering and boosting segment. EPA states, “Subpart W already contains monitoring and 

calculation methods for all emission sources that would be included in the Onshore Petroleum 

and Natural Gas Gathering and Boosting segment, with the exception of gathering pipelines, in 

either the Onshore Petroleum and Natural Gas Production segment or the Onshore Natural Gas 

Processing segment.”4

 The equipment listed in this definition is comprehensive and consistent 

with reporting requirements under the existing industry segments in Subpart W. Therefore, 

leaving this definition open-ended serves no purpose other than creating confusion. 

Footnotes 
22 

3 ld. 

4

 79 Fed. Reg. 73,154 (Preamble discussion of Onshore Petroleum and Natural Gas Gathering 

and Boosting segment) 

Response 3: The Onshore Petroleum and Natural Gas Gathering and Boosting segment is 

intended to include all equipment and sources of emissions that could exist in this sector that 

would not otherwise be included in the Onshore Natural Gas Processing, Onshore Natural Gas 

Transmission Compression, or Onshore Petroleum and Natural Gas Production segments within 

Subpart W, as defined in 40 CFR 98.230. The inclusion of the phrase “but is not limited to” is 

necessary, given the range of types of facilities and equipment intended to be covered by the 

Onshore Petroleum and Natural Gas Gathering and Boosting segment. Therefore, the EPA does 

not agree that the phrase “but is not limited to” creates unnecessary confusion. 

The EPA also notes that inclusion of the phrase “but is not limited to” in the segment description 

is consistent with other industry segments currently reporting under Subpart W. For example, the 

Onshore Petroleum and Natural Gas Production segment is defined as “...all equipment on a 

single well-pad or associated with a single well-pad (including but not limited to compressors, 

generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and 

processing equipment, and portable non-self-propelled equipment, which includes well drilling 

and completion equipment, workover equipment, and leased, rented or contracted equipment) 

used in the production, extraction, recovery, lifting, stabilization, separation or treating of 

petroleum and/or natural gas (including condensate)” (emphasis added). 
23 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 2 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 3 

Commenter Name: Gretchen C. Kern 

Commenter Affiliation: Pioneer Natural Resources USA, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0134 

Page(s): 2 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 10-11 

Comment 4: Commenter 0125: We have several concerns with the EPA’s proposed definition of 

the Onshore Petroleum and Natural Gas and Boosting segment (hereinafter referred to as the 

“Gathering and Boosting segment”), as outlined below. First, we are concerned that the 

definition, as stated, would unintentionally require collecting and reporting data of petroleum 

gathering pipelines and other associated equipment. The proposal defines [section 98.230(a)(9)] 

onshore natural gas gathering and boosting systems as: 

“...gathering pipelines and other equipment used to collect petroleum and/or 

natural gas from production gas or oil wells and used to compress, dehydrate, 

sweeten, or transport the gas to a natural gas processing facility, a natural gas 

transmission pipeline or to a natural gas distribution pipeline.”

Petroleum gathering pipelines and equipment are not used to compress, dehydrate, sweeten, or 

transport natural gas. Therefore, we request “petroleum and/or” be stricken from the definition. 

Commenter 0132: GPA agrees with API that the word “petroleum” should be struck from 

“Onshore Petroleum and Natural Gas Gathering and Boosting.” 

The proposed source category definition includes “petroleum” in the definition of source 

category. GPA agrees with API that the word “petroleum” is not applicable and should not be 

included in this source type. The types of equipment that EPA lists in the proposed rule are 

synonymous with natural gas gathering and boosting systems and not liquid and petroleum 

gathering systems. 
24 

Commenter 0134: Pioneer agrees with the Associations that the word “petroleum” should be 

struck from the definition of the “Onshore Petroleum and Natural Gas Gathering and Boosting” 

proposed source category in section 98.230. 

As GPA explains, the word “petroleum” used in the definition of this industry segment in section 

98.230 is not applicable to the gathering and boosting segment and should not be included in the 

definition. We believe it was EPA’s intent to apply this segment to gathering and boosting of 

natural gas only and this is evident when reading the first part of the definition in its entirety as 

follows: 

98.230(a)(9) Onshore petroleum and natural gas gathering and boosting means 

gathering pipelines and other equipment used to collect petroleum and/or natural 

gas from onshore production gas or oil wells and used to compress, dehydrate, 

sweeten or transport the gas to a natural gas processing facility, a natural gas 

transmission pipeline or to a natural gas distribution pipeline...1

By specifically including “the gas” in the latter part of the sentence above, it is clear that the 

leaks and resulting fugitive emissions EPA is aiming to quantify in the gathering and boosting 

segment are from gas lines and not oil pipelines. Further, the emission factors EPA is proposing 

to require for the “equipment leaks” reporting under this segment were developed for gas lines 

and it would be imprudent and would result in inaccurate reporting if these same factors where 

applied to oil lines.2

Footnotes: 

1

 79 Fed. Reg. 73,175 (Proposed 40 C.F.R. 98.230(a)(9) 

2

 70 Fed. Reg. 73,155 (Preamble discussion where EPA states, “The emission factors that are 

being proposed...are whole gas emission factors based on the U.S. GHG Inventory) 

Commenter 0137: In order to streamline the demarcation of boundaries and reporting obligations 

between the Production and Gathering/Boosting segments and to ensure consistency between the 

new segment and the emissions sources already covered, API offers three refinements: 

API requests renaming this segment “Onshore Natural Gas Gathering and Boosting”. Removing 

“petroleum” from the segment name, as marked in the definition below, provides a clear 

demarcation between the production segment and the gathering and boosting segment. This 

revision does not exclude any emission sources and is consistent with emission sources 

associated with compressing, dehydrating, sweetening, or transporting the gas to a natural gas 

processing facility, a natural gas transmission pipeline or to a natural gas distribution pipeline, as 

specified in the source category definition. 

Section 98.230 Definition of the source category 

(a)(9) Onshore petroleum and natural gas gathering and boosting. Onshore petroleum and natural 

gas gathering and boosting means gathering pipelines and other equipment used to collect 
25 

petroleum and/or natural gas (including associated gas) from onshore production gas or oil wells 

and used to compress, dehydrate, sweeten, or transport the gas to a natural gas processing 

facility, a natural gas transmission pipeline or to a natural gas distribution pipeline. Gathering 

and boosting equipment includes, but is not limited to gathering pipelines, separators, 

compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, storage vessels, 

engines, boilers, heaters, and flares. 

Response 4: The EPA is finalizing the segment name as proposed and not removing “Petroleum 

and” from the segment name. See Section II.B.1 of the preamble to the final rule for more 

information. 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 3-4 

Comment 5: The bounds of the gathering and boosting segment lack clear distinction and create 

overlap into the existing Onshore Petroleum and Natural Gas Production segment. Confusion as 

to who needs to report, and under which reporting segment, will persist if the revisions to 

Subpart W are finalized as proposed. Therefore, we request that EPA incorporate, by reference, 

the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety 

Administration (PHMSA) federally defined boundaries of the production vs. gathering and 

boosting vs. transmission segments to ensure state/federal transparency and consistency. 

We are concerned that the regulated community may be required to report emissions from 

operations that are not specific to one particular segment. Data may be mistakenly excluded 

within a particular segment when reporting responsibility among several potential entities is 

unclear. Or, emissions will be double-counted (and over reported) by reporting entities. 

Regardless, a lack of clarity will create an inaccurate catalog of information. 

For instance, there may be gathering and boosting equipment located on a single well pad or 

associated with a single well pad. Emissions from such equipment would need to be reported, or 

at minimum analyzed for emissions estimates. The gathering and boosting equipment at a 

production facility may be under common ownership of the upstream production operator in 

some situations; however, it is more common that this equipment is owned and/or operated by a 

midstream operator. To further explain, one Alliance member company has noted that certain 

gathering and boosting equipment operated by the upstream production company is actually 

owned by a separate and distinct midstream entity. Under the rule as proposed, it appears that 

this equipment would fall under both the production and gathering and boosting reporting 

segments. Thus, emissions potentially could be double counted. 

An additional problem may arise if certain gathering and boosting equipment or systems, 

associated with complex ownership scenarios, represent the “determining factor” of the 

emissions for one of more entities’ 25,000 metric tons of CO2e per year reporting threshold (i.e., 
26 

inclusion of the emissions would require GHG reporting, but exclusion would place the 

facility(s) below reporting threshold(s). If the reporting segment boundaries are unclear, which 

entity includes the subject emissions in their calculations to determine GHG reporting 

applicability? 

These complex ownership/operating scenarios, as well as our general concerns outlined above, 

illustrate the need for clear distinctions between which emissions get calculated and reported 

under which segment. As previously stated above, we request that EPA incorporate, by 

reference, the U.S. Department of Transportation’s Pipeline and Hazardous materials Safety 

Administration (PHMSA) federally defined boundaries of the production vs. gathering and 

boosting vs. transmission segments to ensure state/federal transparency and consistency. 

Response 5: The EPA is finalizing the Onshore Petroleum and Natural Gas Production segment 

description at 40 CFR 98.230(a)(9) as proposed, with a few clarifications and exclusions. See 

Section II.B.1 of the preamble to the final rule for the response to this comment. 

Commenter Name: Public Hearing: Karin Ritter 

Commenter Affiliation: Public Hearing: American Petroleum Institute 

Comment Number: EPA-HQ-OAR-2014-0831-0055-B 

Page(s): 24 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 3 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 2 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 11 

Comment 6: Commenter 0055-B: API requests that multiphase gathering pipelines be excluded 

from the gathering/boosting segment and be retained as part of the production segment. 

Commenter 0125: We believe it was not the intention of EPA to include petroleum gathering 

pipelines since the emissions would be negligible. Moreover, the proposed 2.81 scf/hr/mile 

emission factor is clearly only applicable to gas gathering lines. 
27 

Commenter 0137: Gathering and Boosting Segment – API requests that this new industry 

segment should also exclude petroleum gathering pipelines, which have no fugitive gas 

emissions. 

Commenter 0137: In order to streamline the demarcation of boundaries and reporting obligations 

between the Production and Gathering/Boosting segments and to ensure consistency between the 

new segment and the emissions sources already covered, API offers three refinements: 

API requests that multi-phase flow lines from wells to a centralized production facility where 

initial separation occurs be excluded from the gathering and boosting segment, and remain 

included in the Onshore Petroleum and Natural Gas Production segment. The proposed fugitive 

emission factor for gathering pipelines was developed from data for natural gas distribution 

mains from the 1996 GRI/EPA study, and it is not applicable to gathering pipelines that carry 

primarily liquids. 

Response 6: The Onshore Petroleum and Natural Gas Gathering and Boosting segment is 

finalized to include gathering pipelines that are not in the Onshore Petroleum and Natural Gas 

Production segment (i.e., on or associated with a single well pad), including petroleum and 

multiphase gathering pipelines with a GOR of 300 scf/STB or greater. See Section II.B.1 of the 

preamble to the final rule for the EPA’s rationale for this decision. See Section II.B.5 of the 

preamble to the final rule for additional discussion of the gathering pipeline emission factor. 
28 

Commenter Name: Public Hearing: Karin Ritter 

Commenter Affiliation: Public Hearing: American Petroleum Institute 

Comment Number: EPA-HQ-OAR-2014-0831-0055-B 

Page(s): 24-25 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 2 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 11 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 35-37 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 8 

Comment 7: Commenter 0055-B: API requests that gathering and boosting facility boundaries 

include dehydrators that are located on onshore petroleum and natural gas production well pads 

and operated by a gathering and boosting company. 

Moving these dehydrators into this newly created segment, rather than including them with the 

onshore petroleum and natural gas production segment will eliminate the concern of having 

producers report third-party contractors’ emissions, which the producers cannot certify. 

Comment 0137: Gathering and Boosting Segment – To resolve API’s previous concerns with 

reporting emissions from third party dehydrators, API urges EPA to include reporting emissions 

from dehydrators, which are owned and operated by a third party, under the new Gathering and 

Boosting Segment, even if these dehydrators are located on a production pad. 

Comment 0137: API requests that gathering and boosting facility boundaries include dehydrators 

that are located on Onshore Petroleum and Natural Gas Production well pads and operated by a 

gathering and boosting company. This is illustrated in the attached flow diagrams for Scenarios 

A, B, and C. Moving these dehydrators into this newly created segment rather than including 

them with the Onshore Petroleum and Natural Gas Production segment will eliminate the 

concern of having producers report third-party contractors’ emissions, which the producers 

cannot certify. 
Comment 0137: Scenario A: Central Tank Battery or Booster Station with 3rd Party Dehydrator Onsite 

This diagram illustrates that the flow lines from the wells, which may be multiphase, remain part of the Productio

Party operated dehydrator at the gathering facility is part of the Gathering/Boosting segment. 
30 

Scenario B: Central Tank Battery or Booster Station with 3rd Party Dehydrator Onsite and a Well Pad Located OIn this scenario, the well pad located at the gathering facility is reported under the Production segment. The 3rd P

dehydrator at the gathering facility is part of the Gathering/Boosting segment. 
31 

Scenario C: Well Pad with 3rd Party Dehydrator On-site 

API requests in this scenario that emissions associated with the 3rd Party dehydrator be reported under the Gather

segment. This eliminates issues associated with the production operator obtaining, reporting, and certifying emis

dehydrators that are owned and operated by 3rd parties. 
Commenter 0142: Kinder Morgan understands that API proposes that the onshore natural gas 

gathering and boosting segment include certain third-party equipment located at onshore 

petroleum and natural gas production well pads – and thus, such equipment would be excluded 

from the onshore petroleum and natural gas production segment. Kinder Morgan agrees with this 

approach only to the extent that such third party equipment at onshore petroleum and natural gas 

production well pads are owned and operated by the same exact entity from whom EPA requires 

reporting of emissions in the gathering and boosting segment. 

Response 7: The EPA agrees with Commenter 0137 that the dehydrators in Scenario A and B 

should be included in the Onshore Petroleum and Natural Gas Gathering and Boosting segment, 

because those dehydrators are associated with multiple well pads rather than on or associated 

with a single well pad. However, the EPA does not agree with the commenter that third party 

dehydrators on or associated with a single well pad should be excluded from the Onshore 

Petroleum and Natural Gas Production segment as finalized. The EPA addressed the issue of 

third-party dehydrators in the Onshore Petroleum and Natural Gas Production segment in 

“Response to Public Comments on Greenhouse Gas Reporting Rule: 2014 Revisions and 

Confidentiality Determinations for Petroleum and Natural Gas Systems” (see Docket Item No. 

EPA-HQ-OAR-2011-0512-0102), which states that 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, that the designated representative has responsibility for reporting the 

emissions from the entire facility, and that this reporting paradigm is consistent with other EPA 

programs. At this time, we are not changing our position. If new information on this topic 

becomes available, we reserve the right to consider this suggestion for future amendments to 

subpart W. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 14 

Comment 8: API does not foresee a large potential overlap between production and 

gathering/boosting if EPA allows dehydrators owned by 3rd parties to be included in the 

gathering and boosting segment and EPA excludes multi-phase flow lines from well pads to 

centralized gathering/boosting stations. As detailed above, API requests that the name of the 

segment be changed to Natural Gas Gathering and Boosting. Also, as indicated previously, API 

requests that gathering and boosting facility boundaries include dehydrators that are located on 

onshore well pads and operated by a gathering and boosting company. Moving these dehydrators 

into this newly created segment rather than including them with onshore oil production will 

eliminate the concern of having the producers report contractors’ emissions, which they cannot 

certify. Further, as previously indicated, API requests that mulit-phase flow lines remain I the 

Onshore Petroleum and Natural Gas Production segment, 

Response 8: The EPA appreciates the commenter’s suggestions. See Section II.B of the 

preamble to the final rule for our response to the request to rename the segment and for our 
33 

position on multiphase flow lines. In addition, as stated in Response 7 in this section, the EPA 

addressed the issue of third-party dehydrators in the Onshore Petroleum and Natural Gas 

Production segment in “Response to Public Comments on Greenhouse Gas Reporting Rule: 2014 

Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems” (see 

Docket Item No. EPA-HQ-OAR-2011-0512-0102). At this time, we are not changing our 

position. If new information on this topic becomes available, we reserve the right to consider this 

suggestion for future amendments to subpart W. 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 6-9 

Comment 9: The term “gathering system” is commonly used in the natural gas industry, 

although not always consistently defined. Furthermore, “boosters” or “boosting systems” are 

typically referred to by industry as compressor stations. Kinder Morgan appreciates EPA’s intent 

to provide clarity and consistency with respect to the use of the term “gathering and boosting 

systems” and makes suggested revisions to further clarify the proposed term. EPA proposes to 

define the gathering and boosting segment as: 

Onshore petroleum and natural gas gathering and boosting. Onshore 

petroleum and natural gas gathering and boosting means gathering pipelines and 

other equipment used to collect petroleum and/or natural gas (including associated 

gas) from onshore production gas or oil wells and used to compress, dehydrate, 

sweeten, or transport the gas to a natural gas processing facility, a natural gas 

transmission pipeline, or to a natural gas distribution pipeline. Gathering and 

boosting equipment includes, but is not limited to gathering pipelines, separators, 

compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, 

storage vessels, engines, boilers, heaters, and flares. 

See 79 Fed. Reg. at 73,175 (citing proposed 40 C.F.R. 98.230(a)(9)). 

In its Technical Support Document, EPA identifies the following emissions sources that may be 

present in a gathering and boosting system: 

 Pneumatic devices; 

 Acid gas removal units; 

 Dehydrators; 

 Blowdown vent stacks (including those on gathering pipelines); 

 Storage vessels and separators; 

 Flares; 

 Compressors; 

 Equipment leaks from system components (e.g., valves, connectors, pressure relief 

valves); 

 Gathering pipelines (emissions from pipeline leaks); and 
34 

 Combustion sources (e.g., engines, boilers, heaters). 

See Memorandum from EPA to Docket ID No. EPA-HQ-OAR-2014-0831, “Greenhouse Gas 

Reporting Rule: Technical Support for 2015 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems; Proposed Rule,” at 4 (Nov. 13, 2014) (Technical Support 

Document). 

Kinder Morgan believes additional clarification to the proposed definition is necessary to ensure 

that both operators and EPA unmistakably understand the demarcation between the Processing 

segments and the Gathering and Boosting segment, as well as the equipment and emissions 

sources covered by each. To address this current uncertainty as well as other concerns, Kinder 

Morgan proposes the following revisions to EPA’s proposed definition. 

EPA Proposed section 40 C.F.R. 98.230(a)(9): Onshore petroleum and 

natural gas gathering and boosting. Onshore petroleum and natural gas 

gathering and boosting means gathering pipelines and other equipment used to 

collect petroleum and/or natural gas (including associated gas) from onshore 

production of gas or oil wells and used to compress, dehydrate, sweeten, or 

transport the gas to the inlet (i.e., the fence-line) of a natural gas processing plant 

facility, a natural gas transmission pipeline, or to a natural gas distribution 

pipeline. Gathering and boosting equipment includes, but is not limited to 

gathering pipelines, separators, compressors, acid gas removal units, dehydrators, 

pneumatic devices/pumps, storage vessels, engines, boilers, heaters, non-selfpropelled engines or turbines used to drive compressors or generators, and flares. 

The gathering and boosting segment does not include compression, dehydration, 

and sweetening units located at onshore natural gas processing plants. Gathering 

and boosting equipment shall not include equipment and pipelines that are 

reported under any other industry segment defined in Subpart W (e.g., the onshore 

natural gas transmission pipeline industry segment). 

Kinder Morgan also proposes the following revisions definition to the onshore natural gas 

processing segment to clearly demarcate between gathering and boosting and natural gas 

processing and to align with EPA’s definition of natural gas processing in its New Source 

Performance Standards (“NSPS”) Subpart OOOO. 

Existing 40 C.F.R. 98.230(a)(3): Onshore natural gas processing plant. Natural 

gas processing means the separation of natural gas liquids (NGLs) or nonmethane gases from produced natural gas, or the separation of NGLs into one or 

more component mixtures. Separation includes one or more of the following: 

forced extraction of natural gas liquids, sulfur and carbon dioxide removal, 

fractionation of NGLs, or the capture of CO2 separated from natural gas streams. 

This segment also includes all residue gas compression equipment owned or 

operated by the natural gas processing plant. Onshore natural gas processing plant 

means any process site engaged in the extraction of natural gas liquids from field 

gas, fractionation of mixed natural gas liquids to natural gas products, or both. 

that fractionate gas liquids, and processing plants that do not fractionate gas 
35 

liquids but Only those onshore natural gas processing plants that have an annual 

average throughput of 25 MMscf per day or greater are subject to this Subpart W. 

A Joule-Thompson valve, a dew point depression valve, or an isolated or 

standalone Joule-Thompson skid is not an onshore natural gas processing plant. 

The following facilities shall be included in this definition if, and only if, the 

facilities are located on the same property as an onshore natural gas processing 

plant as previously defined: compressor stations, dehydration units, and 

sweetening units.1 Onshore natural gas processing plant shall not include 

pipelines or equipment that is reported under any other industry segment defined 

in Subpart W. 

Kinder Morgan believes implementation of the above-stated revisions to EPA’s proposed 

definition of the “Gathering and Boosting Segment,” and onshore natural gas processing plant 

achieves the following goals: (1) clarifies the boundaries between the Gathering and Boosting 

segment and the Processing segment to be able to ensure an understanding of what sources and 

equipment are included under each segment; (2) ensures consistency for reporting of emission 

sources associated with compressing, dehydrating, sweetening, or transporting the gas to the inlet 

of a natural gas processing facility, a natural gas transmission pipeline, or a natural gas 

distribution pipeline, as specified in the source category definition; (3) clarifies EPA’s intent not 

to include equipment and pipelines that are reported under any other industry segment; and (4) 

eliminates duplicative reporting requirements. Kinder Morgan also requests that in addition to 

the proposed changes above, EPA discuss in detail in the preamble to any final rule clear 

boundaries between the Processing segment and the Gathering and Boosting segment, as 

described in the above definition. 

In sum, Kinder Morgan believes the above-proposed changes would clarify reporters’ and EPA’s 

understanding of the demarcation of boundaries between the source categories as well as 

associated sources and equipment to allow for streamlined implementation of any final version 

of the Proposed GHG Reporting Rule. 

Footnotes: 

1

 Excerpts from this definition are from the TCEQ definition of natural gas/gasoline processing 

found in 30 TAC 115.10(33). 

2

 The onshore natural gas processing “industry segment includes processing plants that 

fractionate gas liquids, and processing plants that do not fractionate gas liquids but have an 

annual average throughput of 25 MMscf per day or greater.” See 40 C.F.R. 98.230(a)(3). 

Response 9: The EPA agrees that a similar version of the last sentence of the commenter’s 

suggested revisions to 40 CFR 98.230(a)(9) would be a helpful clarification to the definition of 

the industry segment. Therefore, the last sentence of the finalized 40 CFR 98.230(a)(9) reads: 

“Gathering and boosting equipment does not include equipment reported under any other 

industry segment defined in this section.” The second to last sentence of the commenter’s 

suggested revisions to 40 CFR 98.230(a)(9) is redundant with this last sentence; therefore, the 

EPA is not finalizing that suggested change. 
36 

See Section II.B of the preamble to the final rule for the EPA’s response to the commenter’s 

suggested inclusion of the word “petroleum” and removal of the phrase “but not limited to.” 

The EPA is not changing the segment description for the Onshore Natural Gas Processing 

segment in 40 CFR 98.230(a)(3) or finalizing any changes to proposed 40 CFR 98.230(a)(9) 

related to the definition of a natural gas processing facility (e.g., the suggested addition of the 

term “fence-line”). As stated at proposal, the EPA decided not to make any changes to the 

existing segment descriptions to provide consistency for reporters in that segment. This decision 

allows the EPA to ensure that the data gap in subpart W related to gathering and boosting 

systems is addressed while minimizing confusion over changes to other segments. In addition, 

consistent segment descriptions within subpart W will allow the EPA to track emissions trends 

over time to inform future policy decisions. In response to the commenter’s suggested revisions 

to the definition of Onshore Natural Gas Processing to be consistent with the definitions in NSPS 

40 CFR part 60, subpart OOOO, the EPA notes that given this is a reporting rule and does not 

require reductions in air emissions, the EPA has determined that it is appropriate to use 

potentially different nomenclature, as deemed necessary, from existing or contemplated 

regulatory air programs. For all these reasons, no changes are being made to the existing 

definition in this final rulemaking. Instead, the EPA is reiterating the intention for the Onshore 

Petroleum and Natural Gas Gathering and Boosting segment to encompass everything between 

the existing definitions for the Onshore Petroleum and Natural Gas Production and the Onshore 

Natural Gas Processing segments. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 22 

Comment 10: Acid Gas Removal Vents and the Distinction Between Onshore Natural Gas 

Processing and Onshore Petroleum and Natural Gas Gathering and Boosting Industry Segments. 

CO2 and sulfur dioxide (SO2) removal cannot define both a gas processing plant and a gathering 

and boosting facility. 

The definition of a gas processing plant is well established in the context of the Clean Air Act 

(CAA) and it does not incorporate stand-alone gathering and boosting systems. Gathering and 

boosting systems can share some similar equipment as gas processing; however, gas processing 

specifically involves the extraction of natural gas liquids from field gas and/or fractionation of 

mixed natural gas liquids to natural gas products. EPA confused this in the original 2010 Subpart 

W rulemaking by including “sulfur and carbon dioxide removal” as criteria for “separation” and 

therefore criteria for a facility to be considered a gas processing plant. This is not consistent with 

the definitions of gas processing plants currently codified in 40 C.F.R. Part 60 Subpart KKK, 40 

C.F.R. Part 60 Subpart OOOO, and 40 C.F.R. Part 63 Subpart HH, which limits gas processing 

plants to those sites engaged in liquid extraction and/or NGL fractionation only. 
37 

Under the current definition in Subpart W, acid gas removal (AGR) units are stand-alone gas 

processing plants and already subject to the reporting requirements in the onshore natural gas 

processing industry segment. In order to improve consistency between CAA rules and to avoid 

confusing scenarios where a facility with sulfur and carbon dioxide removal could be applicable 

to both industry segments and result in duplicative reporting, GPA proposes modifying the 

“Onshore natural gas processing” definition to exclude sulfur and carbon dioxide removal. This 

would alleviate confusion and potential duplicative reporting and result in only those nonfractionating, non-liquids extraction facilities reporting under the gathering and boosting industry 

segment. 

98.230(a)(3) Onshore natural gas processing. Natural gas processing means the 

separation of natural gas liquids (NGLs) or non-methane gases from produced 

natural gas, or the separation of NGLs into one or more component mixtures. 

Separation includes one or more of the following: forced extraction of natural gas 

liquids, sulfur and carbon dioxide removal, or fractionation of NGLs, or the 

capture of CO2 separated from natural gas streams.

If EPA agrees to modify the onshore natural gas processing definition in section 98.230(a)(3) to 

exclude sulfur and carbon dioxide removal, GPA is supportive of retaining the annual average 

throughput of 25 million standard cubic feet (MMscf) per day or greater applicability threshold 

value for AGRs in the ONGGB industry segment. 

If EPA rejects modifying the onshore natural gas processing definition in section 98.230(a)(3) to 

exclude sulfur and carbon dioxide removal, GPA recommends removing AGRs from the 

ONGGB industry segment since they are already monitored and reported under the Onshore 

Natural Gas Processing industry segment. In addition to the definition of onshore natural gas 

processing in section 98.230(a)(3), AGRs are specifically defined in section 98.238 as a process 

unit that separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid or 

solid absorbents or membrane separators. Therefore, the inclusion of AGRs in the definition of 

ONGGB industry segment is redundant and should be removed to avoid confusion and eliminate 

duplicative reporting. 

Response 10: The EPA is not revising the definition of the Onshore Natural Gas Processing 

segment in 40 CFR 98.230(a)(3) or removing emission sources from the Onshore Natural Gas 

Processing segment. See Section II.B.1 of the preamble to the final rule for more information. 
38 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 24 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 4-5 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 8 

Comment 11: Commenter 0132: GPA recommends incorporating provisions into the final rule 

that addresses the potential for some non-fractionating processing plants with an annual 

throughput of around 25 MMscf per day to be required to report as part of different industry 

segments from year to year. First, GPA is supportive of utilizing the 25 MMscf per day or 

greater applicability threshold value for non-fractionating processing plants in both industry 

segments. This would allow for consistency between the industry segments, ease the reporting 

burden, and still capture necessary GHG data. Second, GPA recommends that non-fractionating 

processing plants always remain subject to only one industry segment for reporting purposes. It 

is not reasonable or logical to require a facility to change applicable industry segments from year 

to year based solely on the annual natural gas throughput of the facility. A facility should be 

defined as and required to report in one or the other, not both segments. This potential industry 

segment overlap would be eliminated by simply revising the definition of “Onshore natural gas 

processing” in section 98.230(a)(3) as proposed by GPA previously. For example, all stand-alone 

AGRs would report under the ONGGB industry segment and AGRs located at a facility that 

extracts or fractionates NGLs would report under the onshore natural gas processing industry 

segment. 

Commenter 0133: EPA specifically requested comments regarding the categorization of 

Gathering and Boosting as a segment separate from the Production segment and the Processing 

segment and whether or not previous concerns about boundary issues were resolved. One 

boundary issue discussed in the preamble was the treatment of nonfractionating processing 

facilities with throughputs less than 25 million standard cubic feet per day (MMscf/day) being 

included in the Gathering and Boosting segment. If throughput exceeds 25 MMscf/day during 

any given year, the facility would discontinue reporting under the Gathering and Boosting 

segment and report under the Processing segment. The facility would continue reporting under 

the Processing segment until/if throughput drops below 15,000 metric tons per year for three 

years, or below 25,000 metric tons per year for five years, as specified in Subpart A. We agree 

that the proposed regulation is clear that the same processing facility should in no way report 

under both segments of the rule in any given year. 

Commenter 0142: Kinder Morgan also respectfully requests that EPA make clear in the 

preamble to any final rule that EPA does not intend to obligate facilities and equipment to 
39 

“switch” segments at any point in time. Instead, as Kinder Morgan has proposed in the revisions, 

any onshore natural gas processing plant that falls below the regulatory threshold in 40 C.F.R. § 

98.230(a)(3)2 would not be required to report under Subpart W, while certain facilities that treat 

natural gas as part of the Gathering and Boosting segment would be required to report as part of 

the Gathering and Boosting segment without regard to such individual throughput thresholds. 

Implementation of a rule that could require operators to consistently monitor thresholds and 

“switch” segments would be unduly burdensome, unnecessary, and a considerable recordkeeping 

problem for both industry and EPA. 

Footnotes: 

2

 The onshore natural gas processing “industry segment includes processing plants that 

fractionate gas liquids, and processing plants that do not fractionate gas liquids but have an 

annual average throughput of 25 MMscf per day or greater.” See 40 C.F.R. § 98.230(a)(3). 

Response 11: The EPA thanks the commenters for their support of the provision that nonfractionating processing plants should not report in more than one industry segment in one 

reporting year. The EPA is not finalizing any specific provisions regarding non-fractionating 

processing plants in the final rule. Non-fractionating processing plants with a throughput of 25 

MMscf per day or greater are part of the Onshore Natural Gas Processing segment, so there is no 

need to add a similar throughput threshold to the Onshore Petroleum and Natural Gas Gathering 

and Boosting segment. As stated at proposal and reiterated in the preamble to the final rule, the 

EPA is changing the segment description or related definitions for the Onshore Natural Gas 

Processing segment. For more information on the EPA’s position on stand-alone acid gas 

removal units, see Section II.B.1 of the preamble to the final rule. 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 3-5 

Comment 12: Gathering pipelines. More accurate and comprehensive data on gathering 

pipelines will help to further improve understanding of emissions from these sources. The 2014 

Greenhouse Gas Inventory estimates that there are over 440,000 miles of gathering pipeline 

currently in the U.S.10 Historically, gathering pipelines were small, low-pressure lines connecting 

production wells with downstream facilities.11 In recent years, an increase in oil and gas 

production has led to the construction of larger, higher-pressure gathering lines.12 To keep apace 

of recent growth in production, the Interstate Natural Gas Association of America estimates that 

16,500 miles per year of new gathering pipelines will be required from 2011 to 2035.13

Gathering pipelines in rural areas have not historically been subject to Department of 

Transportation (“DOT”) safety standards. In fact, DOT’s PHMSA regulations currently cover 

only about 10 percent of the nation’s gathering pipelines,14 and most states do not have separate 
40 

requirements for this infrastructure.15 As a result, companies have not generally been required to 

report the location and characteristics of gathering pipelines installed in rural areas.16 A recent 

Government Accountability Office report recommended that the DOT and PHMSA move 

forward with a rulemaking to address gathering pipeline safety, concluding: “Given the lack of 

PHMSA regulation of rural gathering pipelines, the extent, location, and construction practices 

for rural gathering pipelines is largely unknown by federal, state, and local officials, and 

oversight to verify the construction and monitor operators’ safety practices is lacking.”17

Accordingly, strengthened reporting requirements are essential to provide transparent 

information concerning emissions from existing infrastructure and recently increased pipeline 

mileage.18

Compressors. Compressors in the gathering and boosting segment are also significant sources of 

emissions. According to independent analysis conducted by ICF International, which analyzed 

available data from five states to develop national-level estimates, there are over 13,000 

reciprocating compressors in the gathering and boosting segment. Emissions from compressors, 

including equipment leaks, make these facilities one of the largest sources of methane emissions 

in the oil and gas sector.19 Robust reporting requirements for compressors in the gathering and 

boosting segment are therefore essential to providing a deeper understanding of this significant 

source of emissions. 

Storage Tanks. The ES&T Study also includes information concerning emissions from storage 

tanks at gathering facilities. In particular, the study found substantial venting from liquids 

storage tanks at approximately 20 percent of sampled gathering facilities. Emission rates at these 

facilities were on average four times higher than rates observed at other facilities.20 In addition, 

at some of the sites with substantial tank emissions, the authors found that company 

representatives were able to make adjustments in response to monitoring data that resulted in 

immediate reductions in emissions. 

Footnotes: 

10 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012, Annex 3 tbl. A-125 

(2014). PHMSA has estimated that there are at least approximately 230,000 miles of gas 

gathering lines in the U.S. Pipelines Safety: Safety of Gas Transmission Pipelines, Advance 

Notice of Propose Rulemaking, 76 Fed. Reg. 53,086, 53,101 (Aug. 25, 2011). 

11 U.S. Government Accountability Office, Oil and Gas Transportation: Department of 

Transportation is Taking Actions to Address Rail Safety, but Additional Actions Are Needed to 

Improve Pipeline Safety, at 22 (Aug. 2014) [hereinafter GAO Study]. 

12 Id. 

13 Interstate Natural Gas Association of America, North American Natural Gas Midstream 

Infrastructure Through 2035: A Secure Energy Future, at 14 (June 28, 2011), available at 

http://www.ingaa.org/File.aspx?id=14911. 
41 

14 GAO Study, supra note 11, at 10-11. 

15 Id. at “What GAO Found.” 

16 Id. at 23. 

17 Id. at 26. 

18 Id. at 22. 

19 See ICF Cost Curve Report, supra note 6, at 3-7 tbl.3-2. 

20 ES&T Study, supra note 9, at A. 

Response 12: 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. 

3.1.2 Definition of Facility 

Commenter Name: Thure Cannon 

Commenter Affiliation: Texas Pipeline Association (TPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0130 

Page(s): 1-10 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 4-5 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 5 

Comment 1: Commenter 0130: TPA opposes EPA’s proposal to aggregate sources in the 

Onshore Petroleum and Natural Gas Gathering and Boosting segment on a basin-wide 

basis. 

EPA proposes to add a new industry segment to Subpart W, Onshore Petroleum and Natural Gas 

Gathering and Boosting, to cover the reporting of GHG emissions from equipment used by 

gathering pipeline systems and natural gas processing plants, transmission pipelines, and 
42 

distribution pipelines. EPA proposes to define “facility” with respect to onshore petroleum and 

natural gas gathering and boosting as all gathering pipelines and other equipment located along 

pipelines under common ownership or control by a gathering and boosting system owner or 

operator and that are located in a single hydrocarbon basin. If a person owns or operates more 

than one gathering and boosting system in a basin, all gathering and boosting systems and 

equipment that the person owns or operates in the basin would be considered one facility. 

Under this definition, a single “facility” could encompass thousands of pieces of equipment 

located across vast expanses of land. A “basin,” as defined for these purposes, would mean a 

“geologic province[] as defined by the American Association of Petroleum Geologists” in 

Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin (October 1991).1

 A 

basin so defined can encompass vast areas of land, stretching across scores of counties and 

multiple states. The Permian Basin, for example, stretches from southeast New Mexico and cuts 

across huge areas of west Texas, encompassing 66 different counties. Equally expansive is the 

Gulf Coast Basin, which encompasses the entirety of the Eagle Ford shale play in south Texas 

and stretches from the Texas-Mexico border, all the way across south and southeast Texas, and 

on into the entire southern half of Louisiana, covering 104 counties in all. Under the proposal, 

the term “facility” for the “onshore petroleum and natural gas gathering and boosting segment” 

would be defined as all gathering pipelines and other equipment located along those pipelines 

that are under common ownership or control of a gathering and boosting system owner or 

operator within a single hydrocarbon basin. As a result of this definition, immense numbers of 

far-flung pieces of equipment would be collected together and deemed, per EPA fiat, to 

constitute a single “facility” for purposes of determining the applicability of Subpart W reporting 

requirements. TPA is opposed to EPA’s aggregation of sources of emissions that results in an 

unjustified and expansive definition of “facility” in the gathering and boosting context, for the 

reasons discussed below. 

Basin-wide reporting for production sources does not justify basin-wide reporting in the 

gathering and boosting context; the two industry segments have very different 

characteristics.

TPA acknowledges that EPA adopted a basin-wide definition of “facility” for the onshore 

petroleum and natural gas production segment in its initial Subpart W rules, finalized in 2010.2

However, even assuming that this was appropriate in the production context – and we note that 

numerous industry sources strongly objected to EPA’s proposal at the time – that action does not 

justify applying that same basin-wide approach to the definition of a “facility” in the gathering 

and boosting sector. Production sources are very different from gathering and boosting sources 

for purposes of complying with Subpart W GHG emissions calculations and reporting. 

Production sources are located at well-defined discrete locations. Owners and operators of 

production sites know where the wells are physically located, typically have a permit issued by a 

state oil and gas regulatory agency, such as the Railroad Commission of Texas, that authorizes 

the well-site, and the number of wells that a person owns or operates in a single production basin 

is finite. In contrast, gathering and boosting equipment, when assessed on a basin-wide basis, can 

entail hundreds or thousands of miles of pipelines with multiple sites, including interconnects, 

meter stations, scrubber stations, pigging stations, compressor stations, and gas treating plants, 

composed of tens of thousands of individual components, i.e. a huge number of small emission 
43 

points spread across vast areas of land. Just gathering an accurate equipment count and sorting 

by equipment type in order to apply applicable emission factors is a huge effort by itself. 

An example of how unwieldy and burdensome it would be to apply a basin-wide approach to the 

definition of a gathering and boosting facility is demonstrated by the map of one TPA member’s 

gathering system, which illustrates the geographically dispersed and complicated nature of a 

gathering system in the industry. See Map, attached as Attachment A. This map, which depicts 

only one of the member’s numerous gathering and boosting systems in the Gulf Coast Basin in 

Texas, shows that the many sites and associated components that would be aggregated as a single 

“facility” required to report under the Subpart W gathering and boosting system rules cover 

multiple counties and an extremely complex system of gathering pipelines. Along each of those 

gathering pipelines, can be found a complex set of myriad components. As the map depicts there 

are thousands of miles of pipe laid out in a network of connections to meter stations, pigging 

stations, compressor stations, scrubbers, and interconnects. (Note: only compressor stations are 

noted on the map.) Along this system alone, there are more than 300 sites (meter stations, 

pigging stations, compressor stations, scrubbers, and interconnects) that have over 1,500 

individual components that would need to be evaluated for reporting under the proposed Subpart 

W gathering and boosting system reporting rules. This is simply impractical and illustrates that a 

“basin-wide facility” definition is simply infeasible for the gathering and boosting sector, even if 

EPA has deemed it appropriate in the production sector. 

In addition, the owner or operator of a gathering and boosting system would also have to 

undertake a huge effort simply to determine whether the proposed new reporting rules applied to 

the system in the first place. Every gathering system would have to be evaluated to determine 

whether combined emissions from the multiple components in a single system exceed the 25,000 

tpy CO2e reporting threshold. As an example of the burden that this would cause, one TPA 

member owns or operates eight separate facilities in a single hydrocarbon basin, due to separate 

ownership structures. Within those eight facilities are 275 compressors and 2,179 separate pieces 

of equipment. This company would have to evaluate emissions from the plethora of emission 

points associated with all of this equipment in order to determine aggregate emissions for each of 

the eight ownership units, all just to ascertain whether the reporting threshold was met for each 

system. 

Simply put, a basin-wide definition of “facility” in the gathering and boosting context presents 

difficulties that are unique to that segment of the natural gas industry and that are not shared by 

the production segment. Therefore, the rationale that EPA utilized to adopt a basin-wide 

approach in the production context does not justify the use of that approach for sources in the 

gathering and boosting segment. 

The basin-wide definition for “facility” is contrary to traditional notions of aggregation 

under the federal Clean Air Act.

In addition, under the proposed facility definition there would be a substantial disconnect 

between the concept of a single facility in these Subpart W rules vs. the concept of a single 

source as traditionally understood in the context of other, longstanding Clean Air Act programs, 

such as PSD and Title V. As proposed, a single Subpart W gathering and boosting facility could 
44 

encompass multiple components having no relationship with one another other than the fact that 

they are along a gathering pipeline (not even the same gathering pipeline), located within the 

same hydrocarbon basin, and owned or operated by the same person. In stark contrast is the 

traditional definition of a single source in other Clean Air Act contexts, e.g. the PSD program, 

where a single source is defined as “all of the pollutant-emitting activities which belong to the 

same industrial grouping, are located on one or more contiguous or adjacent properties, and are 

under the control of the same person (or persons under common control) ...”3 EPA’s traditional 

concept of a single source has long been informed by the D.C. Circuit’s direction that a single 

source definition should approximate the common sense notion of a plant and should avoid 

aggregating pollutant-emitting activities that as a group would not fit within the ordinary 

meaning of building, structure, facility, or installation.4

 Yet EPA proposes to cast that concept 

aside completely in these proposed rules, by aggregating into a single facility myriad 

components that, inter alia, do not meet the “contiguous or adjacent” test, do not fit within the 

common sense notion of a plant, and are not even functionally inter-related. 

EPA has repeatedly emphasized that the GHG reporting program is intended to collect data that 

can inform future Clean Air Act permitting and compliance programs.5

 This being so, it would 

make no sense for EPA to structure its data collection efforts in a manner so very different from 

the structure traditionally used in other Clean Air Act programs, such as the PSD program. Clean 

Air Act program implementation and development cannot be informed in any meaningful way if 

the source of the data at issue (“facility” defined in a basin-wide sense) strays so radically from 

the source traditionally used in other Clean Air Act contexts (contiguous or adjacent; common 

sense notion of a single plant). 

Indeed, EPA’s approach to aggregation in the current proposal is directly contrary to EPA 

precedent. Specifically, EPA emphasized the inappropriateness of aggregation along long lengths 

of pipeline in the preamble to the 1980 amendments to the final PSD rules: 

EPA has stated in the past and now confirms that it does not intend “source” to 

encompass activities that would be many miles apart along a long-line operation. 

For instance, EPA would not treat all of the pumping stations along a multistate 

pipeline as one “source.”6

Completely contrary to this common sense approach, however, EPA’s currently proposed basinwide aggregation approach would treat multiple far-flung, non-touching and unrelated sources as 

a single facility for purposes of GHG reporting. Of course the Subpart W reporting context is not 

the same as the stationary source permitting context, but to do so represents a stark departure 

from EPA’s long-standing concept that a single source encompasses the commonsense notion of 

a plant. In fact, Congress also expressed its disapproval of overly broad aggregation when it 

enacted Section 112 of the Clean Air Act: 

[E]missions from any oil or gas exploration or production well (with its associated 

equipment) and emissions from any pipeline compressor or pump station shall not 

be aggregated with emissions from other similar units, whether or not such units 

are in a contiguous area or under common control, to determine whether such 

units or stations are major sources, and in the case of any oil or gas exploration or 
45 

production well (with its associated equipment), such emissions shall not be 

aggregated for any purpose under this section.7

Presumably this is why EPA stated, in the preamble to the proposed initial GHG reporting rules, 

that reporting thresholds would be established “at the facility level”8

 and that: 

For the purposes of this rule, facility means any physical property, plant, building, 

structure, source, or stationary equipment located on one or more contiguous or 

adjacent properties in actual physical contact or separated solely by a public 

roadway or other public right-of-way and under common ownership or common 

control, that emits or may emit any greenhouse gas.9

EPA’s stated intention to establish reporting thresholds at the facility level would not be carried 

out through adoption of a basin-wide definition of a gathering and boosting facility. Such a 

“facility” would be stretched and distorted so much that a gathering and boosting facility would 

be a “facility” in name only – in the EPA definitional sense only – not in the real world manner 

in which a facility has traditionally been defined and understood by the industry. The term 

“facility’’ should comport with real operations, and with the common and traditional 

understanding of what a facility actually is in the real world; and no reasonable or traditionally 

understood concept of the term “facility” in the gathering and boosting industry can encompass 

myriad components stretching over multiple counties and covering hundreds of square miles. An 

agency could inform Starbucks that reporting thresholds for coffee shops would be measured at 

the facility level, but that would be cold comfort if the agency then proceeded to define “facility” 

to consist of every Starbucks shop in the country; this technically speaking would constitute the 

establishment of reporting thresholds “at the facility level” but the concept of “facility” in this 

example would be every coffee shop owned by Starbucks. So it is here: EPA’s current proposed 

definition of a gathering and boosting facility is radically overbroad and appears to have been 

chosen simply because EPA understood that using a true definition of facility would mean that 

many small sources in the gathering and boosting industry segment would not be reported 

because they would fall below the applicability threshold. Circumventing the 25,000 tpy CO2e 

threshold by gerrymandering the boundary lines of the reporting “facility” is inappropriate. 

Defining “facility” on a basin-wide basis undermines the purpose for the applicability 

threshold and subjects myriad inconsequential sources to burdensome reporting 

requirements.

A basin-wide approach to facility definition would require reporting parties to measure and 

report emissions from myriad insignificant sources which, when combined with other small 

sources, would in toto constitute a “facility” whose aggregated emissions exceed the 25,000 tpy 

CO2e reporting threshold. Requiring a company to identify, calculate, and report aggregate 

emissions from individual small sources, e.g. a meter station, is akin to imposing reporting 

requirements on de minimis sources, such as homes, churches, small appliances, water heaters, 

and the like – which EPA expressly stated it wished to avoid in promulgating the initial GHG 

reporting rules. See, e.g., 74 Fed. Reg. 16456 (April 10, 2009) (wherein EPA stated that one of 

the basic goals of the GHG reporting requirements is to “[b]alance the rule coverage to maximize 

the amount of emissions reported while excluding small emitters.” (emphasis added). 10
46 

The basis for establishing a reasonable reporting threshold is to ensure that reporting 

requirements are not imposed on insignificant sources of emissions. See 74 Fed. Reg. 16467 

(April 10, 2009) (EPA states that the 25,000 tpy CO2e threshold is intended to gather useful 

information while minimizing reporting burden and excluding small sources of emissions). This 

is a logical and laudable goal, because requiring reporting from insignificant sources is not costeffective, because little can be learned from reporting by small sources, and because it simply is 

not fair to impose the often-substantial costs associated with the GHG reporting rules on sources 

whose emissions are minimal. However, the laudatory goals achieved by setting a reasonable 

reporting threshold are completely eliminated if the rules are circumvented by establishing a 

definition for “facility” that is so broad that the threshold is eliminated by gerrymandering the 

boundaries of a “facility” beyond reason. Indeed, what EPA is proposing here is circumvention 

in reverse: instead of a source artificially splitting up construction activities into small segments 

to stay under an applicable threshold, here EPA is artificially aggregating multiple small sources 

into a single large facility so that collectively their emissions exceed the applicable threshold. It 

is inappropriate in either case: we see no point in EPA’s establishment of a 25,000 tpy CO2e 

threshold if EPA is then going to define the term “facility” so broadly that the intent of the 

threshold – to “exclude[] small emitters” – is completely undone by the same agency that set the 

threshold in the first place. 

In addition, EPA’s proposed definition would result in inaccurate reporting of emissions under 

Subpart W reporting rules. There can be significantly different kinds of gas, with widely varying 

compositions, in long segments of pipeline such as would be included within EPA’s single 

facility definition. For example, the methane content of natural gas can vary widely in different 

parts of a gathering and boosting system, with substantial differences from one production point 

in a basin as compared to another. The complexity and dissimilarity from area to area within an 

overall basin would lead to great difficulties in developing emissions estimation methods across 

equipment and sources within the overall basin-wide facility. If the reporting “source” is defined 

so broadly as to include all equipment in a basin, then a company will be making calculations 

based on very different gas composition, within the same reporting “facility.” A substantial 

amount of effort is required to make these sorts of calculations, and such calculations would have 

to be performed for huge numbers of components. To be sure, a reporter could choose simply to 

use default values, but emissions data that is the product of default values is of far less value than 

data that is the product of actual measurement and calculation. Indeed, reporting of emissions via 

the use of emission factors would essentially be a report of an equipment count, as the total 

estimated emissions would simply be the product of pieces of equipment multiplied by the 

emissions factor. When emissions data are the product of the use of emission factors, EPA 

should not assume that the information that it is receiving is reflective of actual conditions. Use 

of emission factors can skew the data due to many factors, including variations in gas 

composition within a single basin or from basin to basin; varying leak rates and the type of 

equipment used at specific sites; and differences in operating practices from company to 

company. 

This leads to a broader point: the proposed rules would impose a huge additional burden on 

reporters, while producing a limited amount of new and useful information for EPA’s use. 
47 

Moreover, it should be noted that the proper collection of new and useful information for EPA’s 

use would involve monitoring and measurement, which would dramatically further increase the 

burden on reporters. According to EPA, a fundamental goal of the GHG reporting system is to 

“[o]btain data that is of sufficient quality that it can be used to support a range of future climate 

change policies and regulations.”11 But defining a gathering and boosting facility on a basin-wide 

basis would not help to accomplish this goal. In a single basin as defined by the American 

Association of Petroleum Geologists, there can be substantial differences in gas composition, 

geological features, and operational practices. Yet the Subpart W reports generated under EPA’s 

proposed facility definition would cover emission sources scattered across various parts of the 

basin, thus aggregating disparate information within the same overall facility’s Subpart W 

reports. Such aggregated information, which would not account for varying conditions across 

various parts of the basin – especially different gas compositions within the same “facility” – 

would have limited usefulness in informing future EPA regulatory activities. Given the 

likelihood of significant differences in the conditions under which reported emissions were 

produced, it would be difficult to draw meaningful conclusions from data generated under EPA’s 

proposed concept of “facility’’ in the gathering and boosting context. This fact, combined with 

the fact that EPA already has access to a substantial amount of GHG reporting data from 

reporters in the oil and gas industry, shows that the potential regulatory benefits of these 

proposed new rules would be substantially outweighed by the additional burden that they would 

impose on companies in the natural gas industry. 

EPA has not provided a reasoned justification for its artificially expansive definition for 

“facility”.

It appears that the reason why EPA seeks to cast aside the common – and common sense – 

notion of a “facility” in this context, in favor of a basin-wide approach, is so that calculation and 

reporting under Subpart W would be required of as many sources as possible, including very 

small sources. A facility must report under Subpart W only if combined emissions from all 

sources within that facility exceed 25,000 tpy CO2e. It is obvious that including more pieces of 

equipment within a single “facility” grouping increases the likelihood that this reporting 

threshold will be met, and thus that reporting will be required of all of the sources grouped 

within the expansive concept of “facility”. EPA admits this to be true, as the agency states in the 

preamble to this proposal that it expects the proposed new Onshore Petroleum and Natural Gas 

Gathering and Boosting segment to cover many compressor stations that are not currently 

required to report, because while they do not currently exceed the 25,000 tpy reporting threshold, 

they would exceed the threshold if the basin-wide facility definition is implemented: “[W]hen 

aggregated with the gathering pipelines and other compressor stations that are under common 

ownership and control within a system, the complete system may exceed the reporting threshold 

and would be required to begin reporting.”12

While EPA has made clear its intent to require reporting from additional sources in the gathering 

and boosting industry, what EPA has failed to do is provide a reasoned justification for why it is 

reasonable to aggregate gathering and boosting sources on a basin-wide basis. This is an 

important failure on EPA’s part, given EPA’s assertion that the agency’s statutory authority to 

promulgate the proposed Subpart W revisions is contained in Section 114 of the Clean Air Act,13

which authorizes EPA to collect such information as may be “reasonably require[d].”14
48 

The fact that EPA’s data requests under Section 114 must be reasonable has been implicitly 

acknowledged by EPA, e.g. in the agency’s response to comments regarding the initial Subpart 

W rules. There, EPA defended the Subpart W requirements against industry’s argument that they 

“fail[ed] to meet the standard of reasonableness applicable to requests for information under 

Section 114”15 by emphasizing that, in EPA’s view, the Subpart W provisions were reasonable in 

that they were relevant to EPA’s overall purpose and were neither overly broad nor unreasonably 

disruptive.16 In the present context, however, EPA has not advanced a plausible argument as to 

why basin-wide aggregation is reasonable. Indeed, EPA defends its proposed basin-wide 

approach on the ground that it would reduce the burden on reporters,17 yet it is clear that the 

contrary is true, and that EPA’s proposed basin-wide aggregation approach to defining a 

gathering and boosting facility would mean that GHG reporting would be required from an 

unworkably huge number of widely dispersed and insignificant sources of emissions, given that 

they would all be encompassed within EPA’s broad concept of a gathering and boosting facility. 

Thousands of small sources would be covered and required to report because they would be 

encompassed within a single artificially defined “facility” that, in toto, would exceed the 25,000 

tpy CO2e reporting threshold because the threshold would be measured based on combined 

emissions from a multitude of improperly grouped sources. 

The proposed rules would thus impose costly and complex reporting obligations on entities 

operating countless numbers of components scattered over huge geographic areas.18 In short, 

EPA’s proposal to define a facility in this manner would result in a reporting program that would 

entail enormous costs and that, as noted above, would produce data that would have limited 

utility to regulators. This is the hallmark of unreasonable information collection: burdensome 

and costly reporting requirements resulting in data of limited usefulness. Because the proposed 

definition would not meet the reasonableness limitations placed upon EPA by the Clean Air Act, 

it would exceed EPA’s statutory authority under Section 114 of the Clean Air Act. At the very 

least, EPA should come forward with a reasoned justification for its onerous and costly reporting 

program that incorporates a radically new approach to aggregation in the gathering and boosting 

context and results in data of limited usefulness. 

The definition of “facility” in the gathering and boosting context should be consistent with 

the definition used by EPA in the current GHG reporting rules.

For all of the above reasons, EPA should not finalize its proposed basin-wide approach to facility 

definition in the gathering and boosting reporting rules. We urge EPA to define “facility’’ in this 

context so that the facility does not extend beyond the fenceline, as is currently provided in 

Subpart A of the GHG reporting rules and as applied to compressor stations subject to GHG 

reporting under Subpart C, i.e. the physical boundary of the compressor station. The definition of 

“facility” as stated in Subpart A is as follows: 

Facility means any physical property, plant, building, structure, source, or 

stationary equipment located on one or more contiguous or adjacent properties in 

actual physical contact or separated solely by a public roadway or other public 

right-of-way and under common ownership or common control, that emits or may 

emit any greenhouse gas.19
49 

EPA should apply the same definitions to sources in the gathering and boosting segment and 

each site should be evaluated separately as to whether it exceeds the threshold for reporting. 

Footnotes: 

1 See 40 CFR 98.238. 

2 See 40 CFR 98.238 (“Facility with respect to onshore petroleum and natural gas production for 

purposes of reporting under this subpart and for the corresponding subpart A requirements means 

all petroleum or natural gas equipment on a single well-pad or associated with a single well-pad 

and CO2 EOR operations that are under common ownership or common control including leased, 

rented, or contracted activities by an onshore petroleum and natural gas production owner or 

operator and that are located in a single hydrocarbon basin as defined in section 98.238. Where a 

person or entity owns or operates more than one well in a basin, then all onshore petroleum and 

natural gas production equipment associated with all wells that the person or entity owns or 

operates in the basin would be considered one facility.”). 

3 See, e.g., 40 CFR 52.21(b)(6). 

4

 See Alabama Power Co. v. Costle, 636 F.2d 323, 397 (D.C. Cir. 1979); 45 Fed. Reg. 52,694-95 

(Aug. 7, 1980). 

5 See, e.g., 73 Fed. Reg. 44400 (July 30, 2008) (where EPA stated, with respect to the GHG 

reporting rule, that “[t]he overall purpose of the rule is to obtain comprehensive and accurate 

GHG data relevant to future climate policy decisions, including potential regulation under the 

CAA.”); 74 Fed. Reg. 16454 (April 10, 2009) (where EPA stated that “it is appropriate for EPA 

to gather the information required by this rule [the GHG reporting rules] because such 

information is relevant to EPA’s carrying out a wide variety of CAA provisions.”); see also EPA 

Response to Comments at 950 (EPA-HQ-OAR-2009-0923-3608, Nov. 30, 2010) (stating that 

information gathered though the GHG reporting rule program will inter alia ‘‘be valuable in 

determining how best to administer the PSD and Title V programs”). 

6

 45 Fed. Reg. 52695 (Aug. 7, 1980). The proposed expansive definition of “facility” would be 

contrary to current federal practice and precedent in the permitting context; traditionally, 

multiple pollutant-emitting components are considered to constitute a single stationary source – 

i.e., they are aggregated – if and only if the various facilities are inter alia contiguous or 

adjacent. See, e.g., 40 CFR 52.21(b)(5)-(6); 40 CFR 71.2. The courts have recently confirmed 

that it is inappropriate to aggregate sources unless they are physically adjacent within the normal 

meaning of the term, i.e. they are touching. That is the combined impact of the recent Court of 

Appeals decisions in Summit Petroleum Corp. v. EPA, 690 F.3d 733 (6th Cir. 2012) and National 

Environmental Development Association’s Clean Air Project v. EPA, 752 F.3d 999 (D.C. Cir. 

2014). 

7

 Clean Air Act Section 112(n)(4)(A), 42 USC Section 7412(n)(4)(A). 

8

 74 Fed. Reg. 16467 (April 10, 2009). 
50 

9

 74 Fed. Reg. 16467 n. 49 (April 10, 2009). 

10 See also 74 Fed. Reg. 56272 (Oct. 30, 2009) (in the preamble to adoption of the initial GHG 

reporting rules, EPA explains that it chose a 25,000 tpy CO2e threshold, rather than a lower 

threshold, in order to avoid “changing the focus of the program from large to small emitters and 

imposing reporting costs on tens of thousands of small businesses...”). 

11 74 Fed. Reg. 16456 (April 10, 2009). 

12 79 Fed. Reg. 73156 (Dec. 9, 2014). 

13 42 USC Section 7414; see 79 Fed. Reg. 73151 (Dec. 9, 2014) (“The EPA is proposing these 

rule amendments under its existing CAA authority provided in CAA section 114.”). 

14 42 USC Section 7414(a)(l)(G) (emphasis added). 

15 EPA Response to Comments at 930 (EPA-HQ-OAR-2009-0923-3608, Nov. 30, 2010). 

16 EPA Response to Comments at 932 (EPA-HQ-OAR-2009-0923-3608, Nov. 30, 2010). 

17 See 79 Fed. Reg. 73153-54 (Dec. 9, 2014). 

18 One example of the unreasonably overbroad nature of the proposed rules is that they could 

require reporting of blowdowns from the gathering and boosting industry segment, even though 

blowdowns likely account for less than one percent of overall CO2e emissions in this industry 

segment. It is difficult to see the justification for imposing reporting requirements for such an 

insignificant source of emissions. 

19 40 CFR 98.6. 

Commenter 0132: GPA commends EPA for recognizing that, “gathering and boosting facilities 

are more dispersed than processing facilities and are geographically similar to Onshore 

Petroleum Production industry segment in size and number of sources”;2 however, GPA 

disagrees with EPA regarding basin level reporting requirements for the gathering and boosting 

industry segment. 

In recognition of Option 1-3 of EPA’s Technical Support Document,3 GPA sets forth the 

following alternative to the EPA’s proposal. 

The term “basin” is not common terminology that is used in the gathering and boosting industry 

segment. 

Gathering and boosting sites are operationally different than production sites. Gathering and 

boosting sites have the ability to boost and move gas from multiple different basins within the 

same site whereas production typically maintains operations and moves gas within one basin. It 
51 

is unclear why EPA is trying to place the gathering and boosting industry segment into a 

category that clearly does not fit the sources to be addressed. 

In order to limit confusion throughout the industry, GPA requests that the definition of a facility 

be based on a single county or parish instead of a single basin. 

County- or parish-level information is readily available and is used for permitting purposes. The 

25,000 metric tons (mt) carbon dioxide equivalent (CO2e) reporting threshold will apply to the 

aggregated GHG facility emissions on a county or parish basis. This approach would also be 

consistent with information that is already available within many companies’ environmental 

management systems and will ease the burden associated with reporting. Additionally, this 

approach will provide EPA with the granularity that they desired under Option 1 of Facility 

definitions in the Technical Support Document.4

In addition, GPA requests that EPA define an equipment threshold, at or above which, GHG 

emissions will be determined and rolled up into the newly-defined facility (county or parish) 

total. 

GPA proposes defining the lower facility limit as any site with equal to or greater than 650 

manufacturer rated horsepower (HP) or HP equivalent. A survey of several GPA member 

companies indicates a threshold of 650 HP would reasonably represent 80-85% of member 

company facilities. This is consistent with EPA’s desire in the original Subpart W Fact Sheet5

 to 

collect 85% of industry wide GHG emissions. In other words, emissions from only the 

equipment located within any individual gathering or booster station within a single county or 

parish that has at least 650 HP or HP equivalent will be compiled and applied towards the 25,000 

mt CO2e threshold. In doing this, EPA will significantly decrease the reporting burden placed on 

reporters and small businesses with small facilities. The following suggested language reflects 

[the above] comments. 

Section 98.230 Definition of the source category

(9) Onshore petroleum and natural gas gathering and boosting. Onshore 

petroleum and natural gas gathering and boosting means gathering pipelines and 

other equipment used to collect petroleum and/or natural gas from onshore 

production gas or oil wells and used to compress, dehydrate, sweeten, or 

transport the gas to a natural gas processing facility, a natural gas transmission 

pipeline or to a natural gas distribution pipeline. Gathering and boosting 

equipment includes, but is not limited to gathering pipelines, separators, 

compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, 

storage vessels, engines, boilers, heaters, and flares.

Gathering and boosting equipment includes only equipment that is located at a 

gathering or boosting site, as provided in the definition of facility in Subpart A, 

with combined site manufacturer rated horsepower or horsepower equivalent of 

equal to or greater than 650.1
52 

Section 98.238 Definitions

Facility with respect to natural gas gathering and boosting for purposes of 

reporting under this subpart and for the corresponding subpart A requirements 

means all gathering pipelines and other equipment located along those pipelines 

that are under common ownership or common control by a gathering and 

boosting system owner or operator and that are located in a single hydrocarbon 

basin county or parish as defined in this section.

Where a person owns or operates more than one gathering and boosting system 

in a basin county or parish (for example, separate gathering lines that are not 

connected), then all gathering and boosting equipment that the person owns or 

operates in the basin county or parish would be considered one facility. Any 

gathering and boosting equipment that is associated with a single gathering and 

boosting system, including leased, rented, or contracted activities, is considered 

to be under common control of the owner or operator of the gathering and 

boosting system that contains the pipeline.

The facility does not include equipment and pipelines that are part of any other 

industry segment defined in this subpart nor equipment located at a gathering or 

boosting site (as provided in the definition of facility in Subpart A) with less than 

650 manufacturer rated HP or manufacturer rated HP equivalent.

Footnotes: 

2

 EPA Climate Change Division, Greenhouse Gas Reporting Rule: Technical Support for 2015 

Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed 

Rule at 14 (Nov. 13, 2014), available at 

http://www.regulations.gov/contentStreamer?objectId=09000064819660f0&disposition=attachm

ent&contentType= pdf (Technical Support Document). 

3 Id. at 13-15. 

4 Id. at 13. 

5

 Proposed Rule – Mandatory Reporting of Greenhouse Gases from Petroleum and Natural Gas 

Systems – Subpart W; Fact Sheet: 2010 Proposed Rule – Subpart W, (Apr. 12, 2010) available 

at http://www.epa.gov/ghgreporting/documents/pdf/2010/Subpart-W_factsheet.pdf. 

Commenter 0139: EPA proposes to define a gathering and boosting facility to include all 

gathering pipelines and other equipment under common ownership or control in a single 

hydrocarbon basin.21 As such, an owner or operator of multiple “gathering and boosting 

systems” within a single basin may report all systems as one facility.22 EPA proposes to 

separately define a “gathering and boosting system” as a “single network of pipelines, 

compressors and process equipment” with connection points to natural gas and oil production 

and a downstream endpoint.23 EPA requests comment on two alternative approaches to defining 
53 

gathering and boosting facilities: 1) using the facility approach described at 40 C.F.R. 98.6, 

which would more narrowly define a gathering and boosting facility; or 2) separating gathering 

and boosting stations from pipelines, with the former reporting at a basin level and the latter at a 

national level.24

We support EPA’s primary proposal to use a basin-level approach to reporting in the gathering 

and boosting segment for both stations and pipelines. This approach will facilitate 

straightforward implementation for reporters who can streamline reporting for all gathering and 

boosting pipelines and equipment in one basin and will also clearly integrate with existing 

standards requiring basin-level reporting from the oil and gas production segment. Because 

basin-level reporting incorporates broader geographic areas, it will ensure more representative 

emission coverage of the gathering and boosting segment as compared with other approaches 

EPA considered. 

Footnotes: 

21 79 Fed. Reg. at 73,188 (proposing amendment to 40 C.F.R. 98.238). 

22 Id. at 73,153. 

23 Id. at 73,188. 

24 Id. at 73,154. 

Response 1: The EPA is maintaining its definition of “facility with respect to onshore petroleum 

and natural gas gathering and boosting” in 40 CFR 98.238 as proposed. See Section II.B.2 of the 

preamble to the final rule for more information. 
54 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 3 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 3-4 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 12-13 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 16 

Comment 2: Commenter 0125: As EPA is aware, gathering and boosting systems may cross 

among multiple reporting basins. We are requesting clarification of how emission estimates are 

to be calculated so it ensures that the same emissions are not being counted in multiple reporting 

basins. The bounds of the gathering and boosting segment lack clear distinction and create 

overlap into the existing Onshore Petroleum and Natural Gas Production segment. 

Commenter 0133: The proposed definitions are clear that the “facility” boundary for gathering 

and boosting is the “hydrocarbon basin”. 

As currently proposed, the rule appears to require that, if assets fall within two “basins”, we will 

need to conduct two separate applicability determinations to see if each basin’s emissions exceed 

the annual 25,000 metric tons of CO2 threshold. We request that EPA consider allowing an 

operating company to submit one combined report, regardless of whether or not all assets are in 

one hydrocarbon “basin”, as long as combined emissions exceed the reporting threshold. Gas 

quality data from the basin in which the emission sources are located could be used in the 

emissions calculations in order to ensure that geographic variability is captured. 

Commenter 0137: The rule proposes to define a facility with respect to onshore petroleum and 

natural gas gathering and boosting in 40 CFR 98.238 as all gathering pipelines and other 

equipment located along those pipelines that are under common ownership or common control 

by a gathering and boosting system owner or operator and that are located in a single 

hydrocarbon basin as defined in 40 CFR 98.238. 

API contends that the definition should be modified as indicated below to be consistent with the 

list of applicable equipment included in the source category definition. 
55 

API requests that the gathering and boosting facility boundaries include dehydrators that are 

located on Onshore Petroleum and Natural Gas Production well pads and operated by a gathering 

and boosting company. Moving these dehydrators into this newly created segment rather than 

including them with the Onshore Petroleum and Natural Gas Production segment will eliminate 

the concern of having producers report third-party contractors’ emissions, which the producers 

cannot certify. 

API also offers language to address the situation where boosting and gathering systems extend 

beyond the boundaries of a single AAPG basin. For example, one gathering system spans across 

southwest Wyoming (Green River basin 535) and the adjacent Central Western Overthrust (basin 

507). API recommends that in these situations the emissions should be assigned to the basin 

where the majority of the system infrastructure, and thus emissions, are located. 

Section 98.238 Definitions 

Facility with respect to petroleum and natural gas gathering and boosting for 

purposes of reporting under this subpart and for the corresponding Subpart A 

requirements means all gathering pipelines and other equipment boosting stations 

located along those pipelines that are under common ownership or common 

control by a gathering and boosting system owner or operator and that are 

located in a single hydrocarbon basin as defined in this section. Where a person 

owns or operates more than one gathering and boosting system in a basin (for 

example, separate gathering lines that are not connected), then all gathering and 

boosting equipment that the person owns or operates in the basin would be 

considered one facility. Any gathering and boosting equipment that is associated 

with a single gathering and boosting system, including leased, rented, or 

contracted activities, is considered to be under common control of the owner or 

operator of the gathering and boosting system that contains the pipeline. The 

facility does not include equipment and pipelines that are part of any other 

industry segment defined in this subpart.

The facility boundaries will also encompass any dehydrators that are located on 

Onshore Petroleum and Natural Gas Production well pads and operated by a 

gathering and boosting company; 

For situations where the boosting and gathering system extends beyond the 

geographical limits of a given AAPG basin, the gathering pipelines and boosting 

stations in the system will be assigned to the basin-wide facility where the 

majority of the system infrastructure is located. 

Commenter 0137: EPA does not address how to report emissions for the situation where 

boosting and gathering systems extend beyond the boundaries of a single AAPG basin. As 

indicated previously, API recommends that in these situations the emissions should be assigned 

to the basin where the majority of the system infrastructure, and thus emissions, are located. 
56 

Response 2: Under the final rule provisions, Onshore Petroleum and Natural Gas Gathering and 

Boosting reporters should submit one report per basin (i.e., per “facility with respect to onshore 

petroleum and natural gas gathering and boosting” as it is defined in Subpart W) and the 25,000 

metric tons CO2e per year reporting threshold applies to each basin/facility separately. See 

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

Regarding Commenter 0137’s suggested changes to the Onshore Petroleum and Natural Gas 

Production segment, see Response 7 in Section 3.1.1 of this document for the EPA’s position on 

third-party dehydrators. 

3.1.3 Other Definitions 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 4 

Comment 1: Although we are requesting that one operating entity with assets in more than one 

adjacent hydrocarbon basin be able to combine emissions into one report, we do not want all 

operating entities within a larger parent company to combine emissions into one report. We 

request that the reporting entity be based on operating company, which could be a subsidiary of a 

larger parent company. As stated previously, the EOG Company and DTI are two separate 

operating entities with different Designated Representatives under the EPA Greenhouse Gas 

Reporting Program. In addition, both entities report to the FERC under the subsidiary name 

rather than the parent company name. 

Response 1: The EPA is not finalizing any changes to the proposed definitions as a result of this 

comment. If the “two separate operating entities” each meet the definition of “facility with 

respect to onshore petroleum and natural gas gathering and boosting for purposes of reporting 

under this subpart and for the corresponding subpart A requirements,” then each operating entity 

would report separately under subpart W. 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 9 

Comment 2: EPA requests comments on whether the requirements at 40 C.F.R. § 98.4 regarding 

“authorization and responsibilities of the designated representative” would be appropriate for the 

new gathering and boosting segment. Kinder Morgan believes EPA’s proposal to incorporate the 

requirements of the existing 40 C.F.R. § 98.4 into the new gathering and boosting segment 

would be appropriate. 
57 

Response 2: The EPA thanks the commenter for their support. The requirements are being 

finalized as proposed. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 11-12 

Comment 3: The rule proposes to define a gathering and boosting system owner or operator as 

any person that: (1) holds a contract in which they agree to transport petroleum or natural gas 

from one or more onshore petroleum and natural gas production wells to a natural gas processing 

facility, another gathering and boosting system, a natural gas transmission pipeline, or a 

distribution pipeline; or (2) is responsible for custody of the gas transported. 

The purpose of including the last phrase of the definition is to address ownership scenarios for 

vertically integrated companies for which contracts are not needed to transfer gas from 

production wells to natural gas processing plants. The EPA requests comment on whether this 

phrase addresses that concern. 

API proposes to confine the definition of a gathering and boosting system owner or operator to 

transportation of natural gas rather than petroleum and natural gas. This is consistent with the 

emission sources associated with compressing, dehydrating, sweetening, or transporting the gas 

to a natural gas processing facility, a natural gas transmission pipeline or to a natural gas 

distribution pipeline, as specified in the source category definition. 

API concurs that item (2) covers the scenario of companies that own and operate their own 

gathering systems. 

Response 3: The EPA thanks the commenter for their support. As discussed in Section 3.1.1, the 

EPA’s intent is to cover both petroleum and natural gas gathering and boosting systems in this 

industry segment. To alleviate any confusion, the last phrase of the final definition of “gathering 

and boosting system owner or operator” reads “(2) is responsible for custody of the petroleum or 

natural gas transported.” 
58 

3.1.4 Applicability and Emissions to Report 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 13-14 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 9 

Comment 1: Commenter 0137: API supports the use of consistent 25,000 metric tons of CO2

equivalent threshold for reporting associated with the gathering and boosting segment per the 

API proposed revisions to the source definition and facility definition provided below. 

Section 98.231 Reporting threshold (a) You must report GHG emissions 

under this subpart if your facility contains petroleum and natural gas systems and 

the facility meets the requirements of section 98.2(a)(2), except for the industry 

segments in paragraphs (a)(1) through (a)(4). 

(1) Facilities must report emissions from the onshore petroleum and natural gas 

production industry segment only if emission sources specified in paragraph 

98.232(c) emit 25,000 metric tons of CO2 equivalent or more per year.

(2) Facilities must report emissions from the natural gas distribution industry 

segment only if emission sources specified in paragraph 98.232(i) emit 25,000 

metric tons of CO2 equivalent or more per year.

(3) Facilities must report emissions from the onshore petroleum and natural gas 

gathering and boosting industry segment only if emission sources specified in 

paragraph 98.232(j) emit 25,000 metric tons of CO2 equivalent or more per year.

(4) Facilities must report emissions from the onshore natural gas transmission 

pipeline industry segment only if emission sources specified in paragraph 

98.232(m) emit 25,000 metric tons of CO2 equivalent or more per year

Commenter 0142: Kinder Morgan supports the use of the 25,000 metric tons of CO2 equivalent 

threshold within a single hydrocarbon basin for reporting associated with the gathering and 

boosting segment. See 79 Fed. Reg. at 73,156 (“This would mean that each piece of property (or 

adjacent properties under common ownership or common control) with gathering and boosting 

equipment that exceeded the 25,000 metric tons CO2e annual threshold would be considered its 

own ‘facility.’”). 

Response 1: The EPA thanks the commenters for their support. These revisions are finalized as 

proposed. 
59 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 9-10 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 12 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 2 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 16 

Comment 2: Commenter 0132: EPA should eliminate the Blowdown Vent Stack equipment 

type for the ONGGB industry segment. 

It is unclear if EPA is interested in only pipeline blowdowns or all equipment blowdowns. 

EPA’s Technical Support Document11 focuses on gathering pipeline blowdowns, but the 

proposed rule covers all blowdowns within the proposed facility. By definition, all the 

blowdowns occurring within a basin, including individual equipment blowdowns, would require 

reporting in addition to pipeline blowdowns. GPA notes that the docket material is unclear on 

this point, but we advocate for elimination of the blowdown vent stack category entirely for 

ONGGB for the reasons stated below. 

This requirement is unduly resource intensive, burdensome, and costly. 

The 50 cubic feet physical volume threshold does not alleviate all work for blowdowns smaller 

than 50 cubic feet physical volume. In the preamble, EPA states that, “[t]he EPA expects that the 

exemption for volumes less than 50 cubic feet should alleviate any concerns with the burden of 

calculating emissions from small gathering pipelines.”12 Yet, every single blowdown event must 

still be evaluated to determine if it is over 50 cubic feet physical volume. A prudent operator 

would also keep records of this evaluation. So while some calculation and reporting time is saved 

with a 50 cubic feet threshold, the burdensome task of calculating physical blowdown volume by 

assessing block valve location and measuring all equipment and piping between block valves and 

documenting the results is not alleviated with a physical size threshold. Prudent operators would 

not “eyeball” equipment to assess physical volume and records of applicability evaluations 

would be maintained. 
60 

Gathering and boosting facilities are geographically dispersed and often unmanned. Pipelines are 

never manned. 

As EPA recognizes in the Technical Support Document, ONGGB equipment is, like Onshore 

Production equipment, geographically dispersed and may be visited only intermittently. Many, if 

not the majority, of ONGGB compressor stations are not manned. Pipelines are never manned. 

As such, it is unclear why this equipment type was excluded for Onshore Production, but not for 

ONGGB. It is also unclear why EPA allows certain more “livable” approaches in the proposed 

rule for ONGGB due to the geographically dispersed and unmanned nature of this industry 

segment, but does not make any concessions on blowdowns. EPA’s approach is unjustifiably 

inconsistent. 

Footnotes: 

11 See Technical Support Document at 19. 

12 Proposed Rule at 73,154. 

Commenter 0132: There is little justification for why this burdensome equipment type 

[Blowdown Vent Stacks] is included in the ONGGB industry segment. 

Just because an activity occurs and a calculation methodology exists does not mean it is 

necessary or should be used. In the Technical Support Document, EPA seems to indicate that 

simply because a method exists to calculate blowdown emissions, the method should be 

required. EPA merely provides a description of how blowdown emissions would be calculated. 

EPA fails to provide a sufficient justification for why blowdowns in this segment should be 

reported. 

Blowdown emissions contribute minimally to overall emissions. 

GPA used the EPA’s Facility Level Information on Greenhouse Gases Tool to evaluate 

emissions from over 125 facilities. In the current rule, blowdown vent stack emissions are 

reported in three industry segments: Onshore Natural Gas Processing, Onshore Natural Gas 

Transmission Compression, and LNG Import and Export Equipment. GPA only examined 

facilities that reported blowdown emissions, and at those facilities, the average contribution of 

blowdown emissions was just 1.8% of total facility CO2e emissions. The median contribution 

was just 0.2% of total facility CO2e emissions. GPA notes that this does not even include the 

facilities that reported zero blowdown emissions (which typically occur at Onshore Natural Gas 

Processing plants where all blowdown emissions are routed to flare). When facilities that 

reported zero blowdown emissions are included in the analysis, the contribution to total site 

GHG emissions are expected to drop even further. 

GPA encourages EPA to use all the reported data to determine the contribution of blowdown 

emissions to total facility emissions. We expect that EPA will find that the contribution is 

extremely low, likely less than 1%. The level of effort required to obtain this very insignificant 

piece of information is not justifiable. GPA finds no reason to believe that the ONGGB industry 
61 

segment would experience a significantly higher level of blowdowns than other industry 

segments. However, to be conservative, even if the ONGGB blowdown emissions are several 

times greater than the industry segments which currently report blowdowns, we expect the 

contribution of emissions from blowdowns to still be very low; therefore, this requirement is 

overly burdensome for the emissions data collected. 

Commenter 0137: Gathering and Boosting Segment – API requests that this new industry 

segment should exclude reporting of blowdown vent emissions, consistent with the exclusion of 

this source from the Onshore Petroleum and Natural Gas Production segment. 

Commenter 0137: API notes that blowdown reporting is excluded from the Onshore Petroleum 

and Natural Gas Production segment and requests that blowdown reporting be similarly excluded 

from the Gathering and Boosting segment. EPA’s Technical Support Document (TSD) 

associated with the Proposed Rule indicates that emissions from blowdown vents stacks are 

included in other Subpart W segments where the blowdown vent stacks are at consolidated 

facility sites. This is not the case in the Gathering and Boosting Segment where a facility is 

defined as operations across an entire AAPG basin and according to the TSD: “blowdown vent 

stacks are located at various points along a gathering pipeline at some distance between the 

connection points for the various production fields and compression boosting stations.” 

Response 2: The EPA is finalizing the requirements for blowdowns of equipment in the Onshore 

Petroleum and Natural Gas Gathering and Boosting segment with some clarifications from 

proposal. See Section II.B.3 of the preamble to the final rule for more information. 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 3 

Comment 3: In section 98.230(a)(9), the proposed rule states “gathering and boosting equipment 

includes, but is not limited to gathering pipelines”, and section 98.232(j) states: 

“for an onshore petroleum and natural gas gathering and boosting facility, report 

CO2, CH4, and N2O emissions from the following source types:... (5) Blowdown 

vent stacks”. 

Since this segment includes gathering pipelines, and blowdowns are included as a source type, it 

appears that gathering pipeline blowdowns in the field are to be included. However, it is our 

assessment that the cost and effort to track gathering pipeline blowdown activities at “field” 

locations that are located outside the fence line of typical gathering and boosting facilities (e.g., 

compressor stations, central tank batteries) would be excessive and infrequent. Moreover, the 

majority of blowdowns typically occur at manned or frequently visited facilities where 

information needed for GHG emissions calculations can be readily logged. Therefore, we request 
62 

that blowdown events that occur outside the fence line of gathering and boosting facilities be 

excluded from GHG reporting. 

Response 3: The commenter used the term “outside the fence” to describe a facility boundary 

“of typical gathering and boosting facilities (e.g., compressor stations, central tank batteries).” 

Though this situation may exist in some locations, it is not clear that this approach would define 

a “station boundary” in all cases. Therefore, the commenter’s suggested approach may create 

ambiguity in reporting. Also, the commenter did not make it clear whether blowdowns at this 

“typical facility” are representative of blowdowns on pipelines between stations, which could 

cause a reporting gap for a significant source of emissions. 

However, the EPA is aware that some gathering and boosting systems are geographicallydispersed and part or all of those systems may operate without on-site personnel. Direct 

measurement may only be possible at locations where personnel are present and during planned 

events. For some blowdown vent stacks, particularly those away from centralized facilities such 

as compressor stations, it may prove difficult to measure all required parameters directly. 

Therefore, as described in Section II.B.3 of the preamble to the final rule, the terms in Equation 

W-14A for temperature at actual conditions in the unique physical volume (°F) and absolute 

pressure at actual conditions in the unique physical volume (psia) specify that engineering 

estimates based on best available information may be used for emergency blowdowns at onshore 

petroleum and natural gas gathering and boosting facilities. This clarification specifically 

addresses the unique nature of the Onshore Petroleum and Natural Gas Gathering and Boosting 

segment. 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 7 

Comment 4: We urge EPA to ensure that all major forms of venting and flaring that occur at 

gathering and boosting facilities are included in reporting requirements for this segment. Venting 

and flaring of associated gas may occur outside of well pads, including at central gathering 

points. While these emissions may be included in the reporting for storage tanks or flare stacks, a 

separate category for associated gas venting and flaring in gathering and boosting may be 

appropriate, and EPA should ensure that all such activities are accounted for. 

Response 4: We agree that venting and flaring of associated gas may occur at central gathering 

points, or “central production/gas batteries” as we noted in “Greenhouse Gas Reporting Rule: 

Technical Support for 2015 Revisions and Confidentiality Determinations for Petroleum and 

Natural Gas Systems; Proposed Rule” (Docket Item No. EPA-HQ-OAR-2014-0831-0018). 

These centralized points would be a part of the Onshore Petroleum and Natural Gas Gathering 

and Boosting segment if they are not located on or associated with a single well pad. For safety 
63 

reasons, most unwanted associated gas at a central gathering point will be flared, and any flaring 

of associated gas that occurs at these centralized points would be included in the gathering and 

boosting facility’s flare stack emissions. Similarly, any associated gas emissions from storage 

tanks or equipment leaks would be included in the emissions reported for those emission sources. 

Since virtually all these emissions are accounted for, any other type of unaccounted-for venting 

of associated gas at a central gathering point is expected to be minimal. Therefore, associated gas 

venting would not be a significant source of emissions from a gathering and boosting facility. 

Therefore, we do not find it necessary to include “associated gas venting and flaring” as a 

specific emission source in the Onshore Petroleum and Natural Gas Gathering and Boosting 

segment. We are clarifying with this response that because we are not separating out associated 

gas venting and flaring in the Onshore Petroleum and Natural Gas Gathering and Boosting 

segment, then any flaring of associated gas that occurs at centralized points would be included in 

flare stack emissions (40 CFR 98.233(n)). 

Commenter Name: Gretchen C. Kern 

Commenter Affiliation: Pioneer Natural Resources USA, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0134 

Page(s): 5 

Comment 5: Gathering lines operated on a vacuum should be exempt from reporting under the 

Equipment Leaks source category in the new Gathering and Boosting Segment of Subpart W 

In certain fields and operations operated by Pioneer, approximately 600 miles of gathering lines 

are operating on “a vacuum”. That is the term used where a compressor’s suction and discharge 

pressures are lower than atmospheric pressure. Since air travels from high pressure to low 

pressure, it is absolutely impossible under the laws of physics for any gas at all to be vented from 

gathering lines operating on a vacuum. Not only is it impossible for fugitive emissions to be 

released to the atmosphere, the vacuum creates the direct opposite effect and pulls ambient air 

into these lines through any openings. Therefore, Pioneer strongly urges EPA to include an 

exception in the final rule, exempting gathering lines operating on a vacuum from reporting 

under the Equipment Leaks source category for the proposed Gathering and Boosting segment of 

Subpart W.

Response 5: The EPA agrees with the commenter that gathering lines operated on a vacuum 

should be exempt from reporting emissions from equipment leaks. The final Onshore Petroleum 

and Natural Gas Gathering and Boosting segment description specifies that Gathering pipelines 

operating on a vacuum are not included in the segment. The EPA suggests that operators keep 

records of gathering lines operated on a vacuum. 
64 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 13 

Comment 6: EPA should eliminate the Storage Tank Vented Emissions equipment type for the 

Onshore Petroleum and Natural Gas Gathering and Boosting industry segment. 

Alternatively, EPA should create a new, separate requirement that is inventory-based and does 

not require tank-specific annual data other than equipment counts. Justification for this request is 

as follows: 

 Tank emissions tracking and calculations is very burdensome and is not justified in the 

proposed rule or supporting materials. 

 Annual tank specific data would be required for every single tank in the ONGGB 

industry segment. 

 EPA underestimates that there are eight tanks per reporter. 

 Additional tank specific data would be required for an unknown portion of tanks in the 

ONGGB industry segment. 

 EPA estimates of burden do not account for all tasks and underestimate the burden of 

each task. 

 Combining the requirements for storage tanks in the ONGGB industry segment and the 

Onshore Production industry segment results in confusing terminology and unclear 

requirements. 

 [There are some] ONGGB operating scenarios that are not contemplated by the current 

language. 

 The application of the Onshore Production industry segment throughput threshold is not 

justified for the ONGGB industry segment. 

 If EPA retains this equipment category, the emission calculation methods must be revised 

to be appropriate for the ONGGB industry segment. 

Response 6: The commenter did not provide sufficient rationale explaining why storage tank 

emissions should not be reported or why storage tanks in the Onshore Petroleum and Natural Gas 

Gathering and Boosting are different from the storage tanks in the Onshore Petroleum and 

Natural Gas Production segment. Storage tanks in both segments serve the same purpose: to 

capture fluids for removal. The commenter suggested there are major differences between the 

segments but did not give specific examples where these differences would require that Onshore 

Petroleum and Natural Gas Gathering and Boosting storage tank emissions be calculated using a 

substantially different approach than Onshore Petroleum and Natural Gas Production storage 

tanks. Therefore, Onshore Petroleum and Natural Gas Gathering and Boosting facilities are 

required to report emissions from storage tanks using the same calculation methodologies as for 

Onshore Petroleum and Natural Gas Production storage tanks. 

The commenter identified specific concerns within each of the bullets listed above; those specific 

concerns and the EPA’s responses are detailed in the preamble to the final rule and elsewhere in 

this document as specified below. The EPA has considered and, where appropriate, revised the 

proposed rule to address the comments on the proposed amendments and the additional data 
65 

provided during the public comment period, as discussed in this document and in the preamble to 

the final rule. 

See Response 7 in Section 10.0 of this document for responses to the following comments: 

 Tank emissions tracking and calculations is very burdensome and is not justified in the 

proposed rule or supporting materials. 

 Annual tank specific data would be required for every single tank in the Onshore 

Petroleum and Natural Gas Gathering and Boosting segment. 

 The EPA underestimates that there are eight tanks per reporter. 

 Additional tank specific data would be required for an unknown portion of tanks in the 

Onshore Petroleum and Natural Gas Gathering and Boosting industry segment. 

 The EPA estimates of burden do not account for all tasks and underestimate the burden of 

each task. 

See Section II.B.4 of the preamble to the final rule and Responses 1, 7, and 8 in Section 3.2.3 of 

this document for the responses to the comments related to “confusing terminology and unclear 

requirements.” See Responses 9, 10, and 11 in Section 3.2.3 of this document for responses to 

comments related to Onshore Petroleum and Natural Gas Gathering and Boosting “operating 

scenarios that are not contemplated by the current language.” See Response 2 in Section 3.2.3 of 

this document for responses to comments related to the “application of the Onshore Production 

industry segment throughput threshold” to the Onshore Petroleum and Natural Gas Gathering 

and Boosting segment. See Responses 3, 12, 13, and 14 in Section 3.2.3 of this document for 

responses to comments related to the emission calculation methods for the Onshore Petroleum 

and Natural Gas Gathering and Boosting segment. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 21 

Comment 7: Stuck Dump Valve Tracking and Reporting Should be Removed. 

EPA’s own analysis shows that these emissions estimations are “weak.” This very burdensome 

continuous data collection effort and reporting requirement hinges on emission estimates that 

EPA summarizes by saying, “[p]redicting and evaluating non-flashing effects on emissions (such 

as dump valves or vortexing) has not yet been thoroughly studied or quantified. The methods 

above have significant weaknesses as . . . [t]he sample data set is limited. . . . [and] [o]nly weak 

correlations were observed for the available data.”23

Footnotes: 

23 EPA Climate Change Division, Greenhouse Gas Emissions Reporting from the Petroleum and 

Natural Gas Industry, Background Technical Support Document at 134 (Apr. 12, 2010), 

available at
66 

http://www.regulations.gov/contentStreamer?objectId=0900006480aae5ed&disposition=attachm

ent&contentType=pdf. 

Response 7: The requirements for stuck dump valves do not include “continuous data 

collection” as stated by the commenter. In fact, the commenter’s rationale cited the section of the 

Background Technical Support Document that describes the calculation methodologies for 

estimating storage tank emissions and is not related to stuck dump valves. As noted in 

Mandatory Greenhouse Gas Reporting Rule Subpart W – Petroleum and Natural Gas: EPA’s 

Response to Public Comments for the original Subpart W rule (November 2010, page 1426): 

“...the multiplier is a more cost-effective approach for informing future policy 

than requiring direct measurement. There is no simple way to simulate or 

calculate how much gas could bypass in a stuck-open dump valve or be entrained 

by vortex in the liquid drain from the separator to the storage tank. EPA’s 

information from Natural Gas STAR partners and studies by the Houston 

Advanced Research Center and Texas Counsel on Environmental Quality indicate 

that sticking, leaking or vortexing through dump valves is not an uncommon 

cause of excessive gas emissions from field tanks. The fact that these emissions 

may go un-noticed or undetected for long periods in remote, un-manned 

operations suggests that basing tank emissions solely on separator liquid 

properties could significantly under-estimate those emissions. EPA’s goal with 

inclusion of the adjustment multiplier is to inform policy in two regards: activity 

data on how common this cause of excessive emissions is occurring, and 

adjustment of liquid flashing emissions for this bulk gas bypass. EPA agrees that 

the conclusions in the TCEQ study are incomplete. However, the methodology 

and procedures used to measure the emissions from the storage tanks are 

acceptable making the data suitable for EPA’s analysis. The HARC and TCEQ 

studies are the best-available, public data on crude oil stock tanks... 

“In today’s final rule, EPA does not require reporters to arbitrarily determine 

whether conditions in the tanks are actually at equilibrium conditions. Instead, in 

today’s final rule, reporters are required to report occurrences of dump valves not 

closing during the calendar year. Because the gas that would bypass the separator 

level control valve is an important revenue stream for the operation, EPA 

concluded that production operators will be attentive to sales volumes of oil and 

gas, and recognize when separator dump valves are malfunctioning. Industry 

experts readily agree that this problem exists, more so in some fields.” 

The commenter did not provide sufficient rationale with respect to stuck dump valves to prompt 

the EPA to reconsider this justification. Therefore, stuck dump valve reporting is finalized as 

proposed. 
67 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 8 

Comment 8: The definition of an “atmospheric” storage tank is unclear. Is there a threshold 

pressure over which a tank is considered non atmospheric? And does the presence of a pressure 

relief valve affect atmospheric status under the rule? For example, in Title 25, 129.57, 

Pennsylvania requires that tanks containing at least 2,000 gallons with a Vapor Pressure of 1.5 or 

more have tank vents set at a minimum of 0.7 psi (11.2 oz/in2) for pressure vents and 0.3 psi (4.8 

oz/in2) for vacuum vents. Would such tanks be considered atmospheric? Further clarity on the 

status of tanks with pressure/vacuum vents would help us identify and characterize our tanks. 

Response 8: As stated in 40 CFR 98.233(j), subpart W includes “emissions from atmospheric 

pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore 

petroleum and natural gas production facilities and onshore petroleum and natural gas gathering 

and boosting facilities.” Therefore, the Onshore Petroleum and Natural Gas Gathering and 

Boosting segment should include the same types of storage tanks operated at atmospheric 

pressure as the Onshore Petroleum and Natural Gas Production segment. 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 8 

Comment 9: We are unclear whether or not brine tanks would be considered “produced water” 

under the definition of “Storage Tank” in Section 98.6 in Subpart A of the rule. Section 98.233(j) 

and related preamble text refer only to tanks with oil or hydrocarbon liquid throughput. We 

request clarification about whether brine tanks are an affected source under the new Gathering 

and Boosting segment. 

Response 9: The EPA has clarified previously that for the Onshore Petroleum and Natural Gas 

Production segment, only emissions from atmospheric storage tanks with hydrocarbon liquids 

are required to be reported (see, e.g., Mandatory Greenhouse Gas Reporting Rule Subpart W – 

Petroleum and Natural Gas: EPA’s Response to Public Comments for the original Subpart W 

rule (November 2010) at pages 1237 and 1426). The EPA’s intent is that the same clarification 

applies to Onshore Petroleum and Natural Gas Gathering and Boosting storage tanks as well. 

The language at the beginning of 40 CFR 98.233(j) clearly states: “Calculate CH4, CO2, and N2O 

(when flared) emissions from atmospheric pressure fixed roof storage tanks receiving 

hydrocarbon produced liquids from onshore petroleum and natural gas production facilities and 

onshore petroleum and natural gas gathering and boosting facilities...” Therefore, no further 

clarification regarding brine tanks is necessary. 
68 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 17 

Comment 10: API recognizes that compressors that are reported under Subpart C now will be 

part of an expanded segment under Subpart W that will also capture the smaller compressors and 

engines. In addition, API supports that stationary or portable combustion equipment included in 

the gathering and boosting segment be constrained to those that are integral to the operation of 

the gathering system as included in the language under 98.232(j)(12): natural gas dehydrators, 

natural gas compressors, electrical generators, steam boilers, and process heaters. 

Response 10: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed. 

3.2 Monitoring and Calculation Methods 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 24-25 

Commenter Name: Douglas Jordan 

Commenter Affiliation: Southwestern Energy 

Comment Number: EPA-HQ-OAR-2014-0831-0143 

Page(s): 1-2 

Comment 1: Commenter 0132: EPA should allow the use of manufacturer data, test data, 

measurement and/or monitoring data as an optional alternative to the prescribed emissions 

factors contained in Subpart W and Subpart C for ONGGB. 

GPA supports the use of emissions factors prescribed in Subpart W and Subpart C for the 

ONGGB. As indicated above, a significant majority of companies in the ONGGB segment have 

not been subject to an emissions inventory obligation and therefore may not have component 

counts (e.g., pneumatic devices, pneumatic pumps, fugitive components) nor have major 

“equipment” counts (e.g., separators, tanks, etc.). In addition, the ONGGB has not been subject 

to extensive monitoring of methane emissions from sources such as reciprocal compressor 

engines (seals and rod packing) or centrifugal compressor seals (e.g., wet and dry). Therefore, 

the use of the prescribed emissions factors does ease the reporting burden for the ONGGB and 

should remain in the finalized rule. 

GPA recommends that the rule allow the ONGGB industry segment to report their emissions 

based on data/information that provides the best representation of emissions from their specific 

sources. 
69 

Such data/information may include, but not be limited to: manufacturer data (e.g., pneumatic 

controller gas volume, flare performance specifications, etc.), emissions test data (e.g., engine 

stack test data), and measuring/monitoring data (e.g., storage tank measurements, compressor rod 

packing and seal emissions, equipment leaks). Companies should not be required to test, 

measure, or monitor every source in lieu of using the prescribed emissions factors, but should be 

allowed to use this data as representative of their emissions. 

This is a very common approach in state level “criteria pollutant” emissions inventories in which 

an emissions reporting hierarchy is applied. The reporting hierarchy includes: (1) source-specific 

emissions testing, measurements, monitoring; (2) representative emissions based on testing, 

measurement, and/or monitoring of in-kind sources; (3) manufacturer specifications; (4) 

emissions estimation tools (e.g. EP Tanks, Glycalc); (5) established emissions factors (e.g. AP42); and (6) engineering estimates. 

We believe that by allowing the use of this data, as an optional alternative to the prescribed 

emissions factors, the agency over time will acquire sufficient data to revise the existing 

prescribed emissions factors (many of which are based on studies that are almost two decades 

old). The use of better or more accurate emissions data will also allow companies (and the EPA) 

to more accurately reflect whether reported emissions are increasing or decreasing (since by 

using factors, a decrease or increase is merely reflective of the accuracy or change in “unit” 

counts). 

Commenter 0143: Southwestern Energy’s comments relate specifically to the emissions 

calculations and reporting component of the proposed rule. Southwestern Energy is supportive of 

the use of emissions factors to minimize the burden of reporting entities. However, we 

recommend that the rule allow the reporting entities to report their emissions based on 

data/information that provides the best representation of emissions from their specific sources. 

Such data/information may include, but not be limited to: manufacturer data (e.g., pneumatic 

controller gas volume, flare performance specifications, etc.), emissions test data (e.g., engine 

stack test data), and measuring/monitoring data (e.g., storage tank measurements, compressor rod 

packing and seal emissions, equipment leaks). Companies should not be required to test, 

measure, or monitor every source in lieu of using the prescribed emissions factors, but should be 

allowed to use this data as representative of their emissions. 

This is a very common approach in state level “criteria pollutant” emissions inventories in which 

an emissions reporting hierarchy is applied. The reporting hierarchy includes: (1) source-specific 

emissions testing, measurements, monitoring; (2) representative emissions based on testing, 

measurement, and/or monitoring of in-kind sources; (3) manufacturer specifications; (4) 

emissions estimation tools (e.g. EP Tanks, Glycalc); (5) established emissions factors (e.g. AP42); and (6) engineering estimates. 

We believe that by allowing the use of this data (or emissions reporting hierarchy), as an 

alternative to the prescribed emissions factors, the agency over time will acquire sufficient data 

to revise the existing prescribed emissions factors (many of which are based on studies that are 

almost two decades old). The use of better or more accurate emissions data will also allow 
70 

companies (and the EPA) to more accurately reflect whether reported emissions are increasing or 

decreasing (since by using factors, a decrease or increase is merely reflective of the accuracy or 

change in “unit” or “activity” counts). We believe this emissions reporting hierarchy should also 

be applied to the other sources subject to reporting under Subpart W (but realize that the 

proposed rule revisions only address gathering and booster facilities). 

Response 1: The EPA does not agree to allow reporters to use any data they feel is 

representative of their emissions in this rulemaking, unless it meets the criteria of the BAMM 

provisions being finalized in this rulemaking. See Section II.B.6 of the preamble to the final rule 

for more information. 

3.2.1 Pneumatic Device Venting 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 4 

Comment 1: For natural gas pneumatic devices, pneumatic valves, and pneumatic pumps 

located in the Gathering and Boosting segment, the EPA is proposing that Gathering and 

Boosting reporters use the same methods for calculating emissions as in the Production segment. 

All pneumatic devices must be categorized and counted. For the Gathering and Boosting industry 

segment, reporters have the option in the first two consecutive calendar years to determine 

population counts for each type of natural gas pneumatic device (continuous high bleed, 

continuous low bleed, intermittent bleed and pneumatic pumps) using engineering estimates 

based on best available data. This would provide reporters three years to get a full counting of 

each pneumatic, with annual verifications thereafter. We appreciate the additional years to 

implement a thorough inventory of pneumatic devices and support EPA’s inclusion of this 

provision. 

Response 1: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed. 

3.2.3 Storage Tank Vented Emissions 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 15 

Comment 1: Combining the requirements for storage tanks in the ONGGB industry segment 

and the Onshore Production industry segment results in confusing terminology and unclear 

requirements. 
71 

If EPA does not remove this equipment category entirely for ONGGB, GPA suggests that EPA 

create a new equipment category for storage tank emissions from the ONGGB industry segment 

that contains relevant terminology and avoids confusion with onshore production industry 

segment requirements. The proposed requirement is an expansion of an existing requirement that 

has language specific for the Onshore Production industry segment. Tacking on ONGGB 

requirements to this language creates confusion about the applicable requirements. ONGGB sites 

do not operate the same way that production sites operate. 

Response 1: The EPA has evaluated this request and does not agree that it is necessary to create 

a new equipment category for storage tanks within the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. Storage tanks associated with multiple well pads or otherwise 

just downstream of the Onshore Petroleum and Natural Gas Production segment will operate in 

the same manner as storage tanks in the Onshore Petroleum and Natural Gas Production 

segment. The commenter did not explain why operation of storage tanks further downstream is 

different enough from tanks in the Onshore Petroleum and Natural Gas Production segment to 

warrant a new equipment category with different calculation methodologies. 

The EPA does agree that some wording in 40 CFR 98.233(j) and 40 CFR 98.236(j) prior to these 

amendments was specific to the Onshore Petroleum and Natural Gas Production segment, and 

the EPA is finalizing amendments to address that language and clarify the “confusing 

terminology and unclear requirements” identified by the commenter. For more details on these 

clarifications, see Section II.B.4 of the preamble to the final rule. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 17-18 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 9 

Comment 2: Commenter 0132: Storage Tank Vented Emissions. 

The application of the Onshore Production industry segment throughput threshold is not justified 

for the ONGGB industry segment. 

The proposed rule language, requirements, and thresholds for calculations are based on well 

production separators, which is not relevant for ONGGB operators. 

The 10 barrel per day threshold bears no relevance to ONGGB. 

The EPA’s analysis of an emission factor threshold for the November 30, 2010 final rule is 

specific to the onshore production industry segment and bears no relevance on the ONGGB 
72 

industry segment.20 This threshold was developed such that 20% of emissions from storage tanks 

in the onshore production industry segment were captured with simple emission factor methods. 

Therefore, analysis that EPA performed does not apply at all to the ONGGB industry segment. 

To justify an appropriate threshold for simplified emission factor estimation techniques, EPA 

must perform an analysis to determine appropriate thresholds for storage tanks in the ONGGB 

industry segment. EPA has provided no justification or support for the proposed rule language. 

ONGGB operators do not typically track separator throughput. 

ONGGB operators do not track separator throughput as a normal course of business. ONGGB 

operators track tank throughput, which is typically measured by measuring the volume of batches 

of liquid that are removed from the tank (not a continuous measurement). Additionally, as noted 

previously, not all tanks receive liquids from separators, and there may be multiple separators 

feeding into a single tank. 

Footnotes: 

20 EPA Office of Air and Radiation, Equipment Threshold for Onshore Production Storage Tanks 

(Nov. 30, 2010), 

http://www.regulations.gov/contentStreamer?objectId=0900006480b7d7f0&disposition=attachm

ent&contentType= pdf. 

Commenter 0133: Atmospheric Storage Tanks. 

Finally, calculating emissions for tanks with daily throughputs greater than 10 bpd involves 

using a software model for estimating methane and carbon dioxide emissions. Investing the time 

and resources for collecting the necessary input data (Reid vapor pressure, oil composition, etc.) 

and running software models such as AspenTech HYSIS or API 4697 E&P Tank on each tank 

with throughputs equal to or greater than 10 bpd would be cost prohibitive without significant 

environmental benefit. As an alternative, we request that EPA consider changing the tank 

threshold from 10 bpd to 500 bpd, which is the tank threshold specified in EPA’s National 

Emission Standards for Hazardous Air Pollutants (NESHAP) (40 CFR Part 63, Subpart HH). 

Tanks with greater than or equal to 500 bpd are already identified in facility Title V air permits. 

Response 2: As described in the memorandum Equipment Threshold for Onshore Production 

Storage Tanks for Docket ID No. EPA-HQ-OAR-2009-0923, the 10 bbl/day threshold was 

developed based on the expected emissions for production tanks: “A 10 bbl/day equipment 

threshold on separators and wells flowing directly to tanks satisfies the significant contribution 

criteria for subpart W by requiring the 19% of largest oil throughput separators to report 

approximately 79% of the total estimated production tank emissions using the more rigorous 

tank flashing model methodologies. EPA has determined that the most appropriate threshold for 

onshore production storage tanks would be 10 bbl/day for the purposes of subpart W.” 

For the Onshore Petroleum and Natural Gas Gathering and Boosting segment, emissions from 

tanks with a throughput of 10 bbl/day or more will likely have a similar profile to those in the 

Onshore Petroleum and Natural Gas Production segment, supporting the use of the 10 bbl/day 
73 

threshold. Therefore, much like the Onshore Petroleum and Natural Gas Production segment, 

separators or other equipment sending less than 10 bbl/day of hydrocarbon liquids to storage 

tanks in the Onshore Petroleum and Natural Gas Gathering and Boosting segment will not be a 

significant emissions contributor. 

Although the Onshore Petroleum and Natural Gas Gathering and Boosting segment reporters 

may not keep track of separator throughput to tanks on a continuous basis, they should be aware 

of the tank volumes on removal and the time elapsed from the previous removal of fluids. This 

available information can be used to calculate annual average daily throughput. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 18-19 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 9 

Comment 3: Commenter 0132: Storage Tank Vented Emissions – If EPA retains this equipment 

category, the emission calculation methods must be revised to be appropriate for the ONGGB 

industry segment. 

A simple emission factor should be used for all tanks in the ONGGB industry sector. ... Just one 

GPA member company has over 1,000 atmospheric pressure fixed roof storage tanks. Evaluating 

every single tank to determine if it meets a threshold to perform more complex emissions 

estimates is a huge burden in and of itself. GPA requests that EPA provide a simple emission 

factor method for all tanks, similar to Calculation Method 3 at section 98.233(j)(3). 

If EPA proceeds with requiring more complex emission estimates for some storage tanks, 

ONGGB reporters should be allowed to use of any combination of site specific, representative, 

or best engineering estimates for all equation inputs. 

Calculation Methods 1 and 2 are very prescriptive in how data must be acquired. GPA fails to 

understand this level of prescriptiveness, when for dehydrators (which require similar complex 

analysis and simulations to determine emissions), EPA allows the use of “engineering estimate 

based on best available data” for all calculation parameters.21 GPA also notes that some ONGGB 

owners and operators calculate condensate tank emissions based on a process simulation where 

gas composition and rates are known, and condensate production (through pressure increases) is 

simulated. This type of analysis is performed because pressurized condensate samples can be 

difficult to collect (or impossible to collect for grassroots facilities). GPA notes that condensate 

that is formed in the gathering pipelines and through compression is not like oil that is being 

produced from a producing reservoir/formation. The composition, API gravity and Reid vapor 

pressure of the condensate will depend on the variety of wells that the gas is collected from and 
74 

the operating conditions of the gathering lines and the compressor station. It is not clear if or how 

this emission estimation technique is accounted for in Calculation Methods 1 or 2. 

Footnotes: 

21 40 C.F.R. 98.233(e)(1). 

Commenter 0133: Atmospheric Storage Tanks: To calculate emissions from tanks below the 10 

bpd threshold, we request confirmation that Equation W-15 in 98.233(j)(5) of Subpart W is the 

appropriate methodology. It is unclear from the five methodologies listed in 98.233(j) which 

methodology is appropriate. 

Response 3: The EPA is not providing the ability for all reporters to use Calculation Method 3 

for all atmospheric storage tanks. Similar to the Onshore Petroleum and Natural Gas Production 

segment, emissions from Onshore Petroleum and Natural Gas Gathering and Boosting storage 

tanks are significant enough to require reporting methods that use storage tank-specific 

information rather than an emission factor when the hydrocarbon liquids throughput is greater 

than 10 bpd. See the memorandum Equipment Threshold for Onshore Production Storage Tanks

(Docket Item No. EPA-HQ-OAR-2009-0923-3584) for more information. 

The EPA also disagrees that Calculation Method 1 for storage tanks is more prescriptive than 

dehydrators regarding the acquisition of parameter data. For dehydrators, 40 CFR 98.233(e)(1) 

states that the listed parameters must be determined “by engineering estimate based on best 

available data.” For storage tanks, the language is nearly identical; 40 CFR 98.233(j)(1) states 

that the listed parameters must be determined “by engineering estimate and process knowledge 

based on best available data.” 

In addition, regarding the assertion that pipeline condensate is not like oil and is difficult to 

analyze, the EPA notes that the definition of “condensate” in 40 CFR 98.238 is “hydrocarbon 

and other liquid... separated from natural gas that condenses due to changes in the temperature, 

pressure, or both, and remains liquid at storage conditions.” If the condensate requires pressure 

to remain in liquid phase, it is not a condensate as it pertains to this rule. (Note that the EPA has 

clarified previously that for this subpart, only emissions from atmospheric storage tanks with 

hydrocarbon liquids are required to be reported (see, e.g., Mandatory Greenhouse Gas Reporting 

Rule Subpart W – Petroleum and Natural Gas: EPA’s Response to Public Comments for the 

original Subpart W rule (November 2010) at pages 1237 and 1426).) 

The introductory text in 40 CFR 98.233(j) was proposed to be amended to state, in part, that for 

throughputs less than 10 barrels per day, reporters should use Calculation Method 3 as specified 

in 40 CFR 98.233(j)(3). Equation W-15 is in 40 CFR 98.233(j)(3) (not 40 CFR 98.233(j)(5) as 

suggested by the commenter). Therefore, the EPA has determined that this language is clear and 

is finalizing this provision as proposed. 
75 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 8-9 

Comment 4: Atmospheric Storage Tanks 

In determining whether or not a tank’s throughput is greater than or equal to 10 bpd, EPA 

provided guidance for the Production segment (i.e. on a well pad) in an FAQ (Frequently Asked 

Question) on their website. We request confirmation that the same guidance would apply to 

tanks within the Gathering and Boosting segment. 

Q480. How should the daily oil throughput be determined for onshore 

production storage tanks in 98.233(j)(l) to compare to the threshold of 10 

barrels/day? Is it based on design capacity, maximum daily throughput, or 

annual average actual daily throughput? Is the throughput re-evaluated 

annually? If the throughput decreases below this threshold, are the 

equipment excluded from report under Subpart W?

A480. It is EPA’s intent that the 10 barrels per day of oil throughput referenced in 

98.233(j) be based on annual average daily throughput. On an annual basis, the 

owner/operator must evaluate whether individual well pad produced hydrocarbon 

liquids falls above or below the equipment threshold and use monitoring methods 

appropriately. For less than 10 barrels per day of oil throughput on an annual 

average daily basis, the reporter must determine if 98.233(j)(5) applies. 

Response 4: As stated in the preamble to the proposed amendments, the EPA’s intent is for 

gathering and boosting reporters to use the same methods for calculating emissions as in the 

Onshore Petroleum and Natural Gas Production segment for storage tanks (79 FR 73148; 

December 9, 2014). Therefore, the EPA agrees that guidance provided for the Onshore 

Petroleum and Natural Gas Production segment applies to the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment with a few clarifications. First, the produced hydrocarbon 

liquids throughput for the Onshore Petroleum and Natural Gas Gathering and Boosting segment 

may be determined for an individual separator or other non-separator equipment, as applicable, 

rather than an individual well pad. Second, 40 CFR 98.233(j) has been amended since the answer 

to this FAQ was written, so if the produced hydrocarbon liquids throughout on an annual average 

daily basis is less than 10 barrels per day, the reporter must determine if 40 CFR 98.233(j)(3) 

applies (not 40 CFR 98.233(j)(5)). 
76 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 15 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 16 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 21 

Comment 5: Commenter 0132: Combining the requirements for storage tanks in the ONGGB 

industry segment and the Onshore Production industry segment results in confusing terminology 

and unclear requirements. 

The terms “separator(s),” “gas-liquid separator(s),” “wellhead separator(s),” and “wellhead gasliquid separator(s),” appear throughout sections 98.233(j) and 98.236(j). Do all of these terms 

refer to the same type of equipment? GPA notes that the high pressure separators and low 

pressure separators typically found at production sites are not necessarily the same types of 

separators that are used at ONGGB compressor stations. ONGGB compressor stations typically 

do not have “wellhead separators” because they do not typically have wellheads onsite. Many 

ONGGB compressor stations have a separator vessel at the inlet of the facility to separate liquids 

that condensed in the gas pipeline. The gas proceeds through the compressor train, which 

typically also includes compressor interstage knockout drums, which are separators. In the rule 

language, in each instance where EPA uses the terms “separator(s),” “gas-liquid separator(s),” 

“wellhead separator(s),” and “wellhead gas-liquid separator(s),” is EPA referring the inlet 

separator and/or compressor interstage knockout vessels at ONGGB compressor stations? 

Commenter 0132: Proposed section 98.233(j) says, “[f]or hydrocarbon liquids flowing directly to 

atmospheric storage tanks without passing through a wellhead separator . . . .”16 This language is 

tailored for the onshore production industry segment. How should this language be applied to the 

ONGGB industry segment? ONGGB facility owner/operators will not know whether the 

condensate that condensed in the gathering pipeline was from gas that passed through a wellhead 

separator. It would be impossible for an ONGGB facility owner/operator to acquire this 

information since gas is gathered from multiple production sites, each of which could have a 

different facility configuration. 

Calculation Method 1 in section 98.233(j)(1) says, “. . . using operating conditions in the last 

wellhead gas-liquid separator before liquid transfer to storage tanks.”17 ONGGB facilities do not 

have wellhead gas-liquid separators. The operating conditions at the multitude of upstream 

wellhead gas-liquids separators would have no bearing at all on the conditions of the liquids 

entering ONGGB storage tanks. 
77 

Footnotes: 

16 Proposed Rule at 73,178. 

17 Id. at 73,178-79. 

Commenter 0132: Not all ONGGB tanks receive liquids directly from separators, and no 

ONGGB tanks receive liquids directly from wellhead separators. 

Thus, the requirement to “calculate emissions from occurrences of gas-liquid separator liquid 

dump valves not closing during the calendar year” would simply not be possible or relevant for 

many ONGGB tanks. 

Response 5: The EPA agrees that the language in 40 CFR 98.233(j) and 40 CFR 98.236(j) 

should be clear for all Onshore Petroleum and Natural Gas Production facilities and all Onshore 

Petroleum and Natural Gas Gathering and Boosting facilities to which it applies. See Section 

II.B.4 of the preamble to the final rule for more information. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 15 

Comment 6: Combining the requirements for storage tanks in the ONGGB industry segment 

and the Onshore Production industry segment results in confusing terminology and unclear 

requirements. 

The terms “oil,” “sales oil,” and “stabilized oil” are used throughout sections 98.233(j) and 

98.236(j). ONGGB facilities do not process oil but may handle and process condensate. In the 

proposed rule language, in each instance where EPA uses the term “oil,” what material is EPA 

referring to? Does this include condensate? This terminology should be clarified and made 

applicable to the ONGGB industry segment. 

Response 6: The EPA agrees that the language in 40 CFR 98.233(j) and 40 CFR 98.236(j) 

should be clear for all Onshore Petroleum and Natural Gas Production facilities and all Onshore 

Petroleum and Natural Gas Gathering and Boosting facilities to which it applies. See Section 

II.B.4 of the preamble to the final rule for more information. 
78 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 16 

Comment 7: Combining the requirements for storage tanks in the ONGGB industry segment 

and the Onshore Production industry segment results in confusing terminology and unclear 

requirements. 

Section 98.233(j)(1)(vii)(B) refers to “produced crude oil or condensate.”18 Does this also refer 

to condensate that is generated by liquids condensing in gathering pipelines? Industry would not 

typically consider this to be “produced condensate.” 

Footnotes 

18 Id. at 73,179. 

Response 7: Condensate is defined in 40 CFR 98.238 as “hydrocarbon and other liquid... 

separated from natural gas that condenses due to changes in the temperature, pressure, or both, 

and remains liquid at storage conditions.” If the condensate in the gathering pipelines is liquid at 

storage conditions, then it is considered condensate for purposes of this rule. (Note that the EPA 

has clarified previously that for this subpart, only emissions from atmospheric storage tanks with 

hydrocarbon liquids are required to be reported (see, e.g., Mandatory Greenhouse Gas Reporting 

Rule Subpart W – Petroleum and Natural Gas: EPA’s Response to Public Comments for the 

original Subpart W rule (November 2010) at pages 1237 and 1426).) 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 16 

Comment 8: Combining the requirements for storage tanks in the ONGGB industry segment 

and the Onshore Production industry segment results in confusing terminology and unclear 

requirements. 

Section 98.233(j)(1)(vii)(B) currently says “. . . select the latest available analysis that is 

representative of produced crude oil or condensate from the sub-basin category.”19 [T]he terms 

“basin” and “sub-basin” bear no relevance to the ONGGB industry segment. The composition of 

condensate processed at an ONGGB compressor station may have little relationship to the basin 

or sub-basin the compressor station happens to be in. Thus, mandating use of an analysis from 

the same sub-basin will not necessarily result in selection of the most appropriate representative 

analysis. 

Footnotes 
79 

19 40 C.F.R 98.233(j)(1)(vii)(B). 

Response 8: The EPA agrees with the commenter that the definition of “sub-basin category, for 

onshore natural gas production” is not relevant for Onshore Petroleum and Natural Gas 

Gathering and Boosting facilities and has revised the final rule accordingly. See Section II.B.4 of 

the preamble to the final rule for more information. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 17 

Comment 9: Examples of ONGGB operating scenarios that are not contemplated by the current 

language: 

In Scenario A, a compressor station has atmospheric fixed roof storage tanks that receive 

condensate that has condensed in the gathering line upstream of the facility and/or condensate 

that has condensed in the compression process. For these tanks, condensate typically passes 

through an inlet separator before entering the tanks. In Scenario B, a compressor station has 

atmospheric fixed roof storage tanks that receive condensate that is trucked in from other 

locations around the gathering system(s). How are these Scenario B storage tanks treated under 

these calculation and reporting requirements, since there is not a separator located directly 

upstream of the tanks? 

Response 9: The final rule language in 40 CFR 98.233(j) and 40 CFR 98.236(j), particularly the 

clarifications regarding the term “wellhead separator,” should address the commenter’s Scenario 

A. The reporter will calculate emissions based on data from the gas-liquid separator used prior to 

the condensate entering the tank. 

The final rule specifies that Calculation Method 1 or 2 should be used if hydrocarbon flow to the 

storage tank from non-separator equipment is greater than 10 bbl/day (40 CFR 98.233(j)(1) or 

(2)(iii)). Non-separator equipment is intended to include equipment other than separators 

immediately upstream of storage tanks, such as stabilizers and slug catchers. In Scenario B, if the 

condensate is loaded into the trucks from within the same gathering and boosting system as the 

storage tank, then the truck would be considered non-separator equipment. If the annual average 

daily throughput of the hydrocarbon liquids from the truck is greater than or equal to 10 bbl/day, 

the owner/operator should use Calculation Method 1 or 2. If the annual average daily throughput 

is less than 10 bbl/day, Calculation Method 3 should be used (40 CFR 98.233(j)(3)). 
80 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 17 

Comment 10: Examples of ONGGB operating scenarios that are not contemplated by the 

current language: 

In Scenario C, the liquid from the inlet separator (and possibly compressor interstage separators) 

is routed through a condensate stabilizer. The stabilized liquids are routed to the storage vessel. 

How are these Scenario C storage tanks treated under these calculation and reporting 

requirements, since there is not a separator located directly upstream of the tanks, and the 

separator operating temperature pressure have no bearing on the tank emissions? 

In Scenario D, there are multiple inlet separators that eventually route to the same storage tank. 

How are these Scenario D storage tanks treated under these calculation and reporting 

requirements, since the rule language seems to only contemplate one single separator located 

directly upstream of the tank? 

In Scenario E, a pig is run into a compressor station, and the liquid is routed to a “slug catcher” 

(a holding spot for the liquid that is typically not atmospheric). Liquid from the slug catcher is 

then routed to the atmospheric storage tanks, possibly through a stabilizer or other process to 

depressurize the liquid. How is this scenario handled under the calculation and reporting 

requirements? 

Response 10: The final rule specifies that Calculation Method 1 or 2 should be used if 

hydrocarbon flow to the storage tank from non-separator equipment is greater than 10 bbl/day 

(40 CFR 98.233(j)(1) or (2)(iii)). Non-separator equipment is intended to include equipment 

other than separators immediately upstream of storage tanks, such as stabilizers and slug 

catchers. Therefore, in Scenario C, Calculation Method 1 or 2 should be used unless the annual 

average daily throughput of the hydrocarbon liquids through the condensate stabilizer is less than 

10 bbl/day, in which case Calculation Method 3 should be used. Similarly, in Scenario E, 

Calculation Method 1 or 2 should be used unless the annual average daily throughput of the 

hydrocarbon liquids through the slug catcher is less than 10 bbl/day, in which case Calculation 

Method 3 should be used. 

Emissions are calculated individually for each separator. Therefore, in Scenario D, the 

owner/operator should consider the annual average daily throughput of the hydrocarbon liquids 

through each separator. For each separator with annual average daily throughput of 10 bbl/day or 

greater, the owner/operator should use Calculation Method 1 or 2, and for each separator with 

annual average daily throughput of less than 10 bbl/day, the owner/operator should use 

Calculation Method 3. 
81 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 19 

Comment 11: Storage Tank Vented Emissions 

Calculation Method 3 at section 98.233(j)(3) is not adequate for the ONGGB industry segment. 

Due to the limited comment time, GPA was not able to evaluate the source of the emissions 

factors used in Calculation Method 3. If the factors were developed based on onshore production 

data (which does not apply to the ONGGB industry segment), GPA requests that EPA determine 

appropriate emission factors for storage tanks in the ONGGB industry segment. Regardless of 

the origin of the emission factors, the language in the calculation method is not applicable to the 

ONGGB industry segment. Specifically, the terms “EFi” and “count” are tailored to separators or 

wells. The ONGGB industry segment does not have wells, and separator count and separator 

operation may have little to do with storage tanks in the ONGGB industry segment. 

Response 11: With respect to the comment about “limited comment time,” the length of the 

comment period was as provided by law and assumed sufficient. Additionally, as requested by 

several commenters, the EPA extended the comment period to allow more time to comment (80 

FR 6495 (Feb. 5, 2014)). 

The derivation of the emission factors in Calculation Method 3 is described in the memorandum 

Equipment Threshold for Onshore Production Storage Tanks (Docket Item No. EPA-HQ-OAR2009-0923-3584) and is based upon emission factors in the 2010 U.S. GHG Inventory for crude 

oil tanks in petroleum systems and condensate tanks in natural gas systems.1

 The emission factor 

for methane from condensate tanks was based on data collected from condensate tanks in the 

production stage of natural gas systems; no condensate tank emission factor was provided for the 

processing stage. The CH4 emission factor for crude oil tanks and the CO2 emission factors for 

both types of tanks were on a per barrel basis based on model simulations. The condensate tanks 

simulation runs were for fixed roof tank flash gas for condensate gravities of API 44 degree and 

higher. The crude oil tanks simulation runs were for crude oil of different gravities less than 44 

API degrees. The type of storage tanks and the API gravities that characterize crude oil and 

condensate are the same in both the Onshore Petroleum and Natural Gas Production segment and 

the Onshore Petroleum and Natural Gas Gathering and Boosting segment. However, the 

commenter did not provide information suggesting more relevant emission factors and counts. 

Therefore, the EPA does not agree that different emission factors in Calculation Method 3 are 

needed for the Onshore Petroleum and Natural Gas Gathering and Boosting segment and the 

EPA is not revising the emission factors in the definition of the term “EFi” in Equation W-15. 

The EPA does agree that Calculation Method 3 did not account for flow to storage tanks from 

equipment other than separators or wells. Therefore, the EPA has clarified in the final rule that 

 

1

 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2008. 

April 15, 2010. Available at http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/archive.html. 
82 

the terms “EFi” and “Count” in Equation W-15 also include “non-separator equipment” (e.g., 

stabilizers, slug catchers). 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 20 

Comment 12: GPA notes that not all ONGGB owners and operators use E&P Tanks. 

Many operators use EPA’s TANKS 4.09.d, which is based on AP-42, to estimate tank working 

and breathing losses. Note that this software requires Reid vapor pressure to be known. Most 

operators use ProMAX or HYSYS to estimate flash emissions, which also requires the liquid or 

gas composition to be known. Thus, the proposed requirement necessitates time consuming and 

expensive sampling. 

Response 12: The EPA is not finalizing any revisions to the modeling software method 

(Calculation Method 1) in response to this comment. Subpart W does not require the calculation 

of storage tank working and breathing losses. Subpart W also does not require the use of a 

particular modeling software program for Calculation Method 1. Instead, the EPA allows the use 

of any process simulators that use the Peng-Robinson equation of state and meet the 

requirements under 40 CFR 98.233(j)(1). The commenter noted that many operators already use 

HYSYS, which is a modeling software specifically listed in 40 CFR 98.233(j)(1) as an example. 

In addition, 40 CFR 98.233(j)(1)(vii) provides three options for estimating hydrocarbon liquids 

composition and Reid vapor pressure if these parameters are not already known, and the final 

rule clarifies the applicability of (j)(1)(vii)(B) and (C) to Onshore Petroleum and Natural Gas 

Gathering and Boosting facilities. Therefore, the EPA has already provided flexibility to reduce 

the burden associated with sampling to determine Reid vapor pressures and hydrocarbon liquids 

composition. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 20 

Comment 13: EPA should eliminate reporting of tanks that are routed to flare or vapor recovery. 

As proposed, EPA requires that additional complex calculations must be performed on tanks 

whose emissions are routed to flare or vapor recovery. For tanks that are routed to flare, the flare 

calculations must be applied to the tank emissions, and then these resulting emissions must be 

backed out of the flare equipment emissions. For tanks that are routed to vapor recovery, 

operators must still collect operating data and liquid samples, conduct analyses, perform 

emissions determinations and retain all records only to “adjust the emissions downward.” This 
83 

exercise is a waste of resources for tanks that are controlled by vapor recovery. Even if some of 

the emissions (~ 2%, for a 98% controlled tank) are not captured by vapor recovery, the 

negligible amount of carbon dioxide (CO2) and methane emissions cannot justify the burden. 

Operators are essentially “punished” for controlling their tanks. 

Why would EPA mandate more difficult and resource-wasting reporting requirements for owners 

and operators who are reducing their CO2e emissions? Similar to the requirements for blowdown 

vent stacks and the requirements for centrifugal and reciprocating compressors, emissions that 

are routed to flare should be simply calculated under the flare equipment type, and emissions that 

are routed to vapor recovery should not be calculated (the blowdown vent stack category only 

applies to emissions that are actually vented). This is a dramatically more simple approach with 

the same results – GHG emissions to atmosphere are accounted for. 

Response 13: The approach taken for the Onshore Petroleum and Natural Gas Gathering and 

Boosting segment is the same as required for the Onshore Petroleum and Natural Gas Production 

segment because the storage tanks, vapor recovery systems, and flare systems in both segments 

are similar. Collecting data on emission reductions will make it possible for the EPA to 

understand how much of the total tank emissions nationally are being captured. Therefore, the 

EPA has retained the requirement on all emissions being estimated before making a reduction 

adjustment, and these provisions are finalized as proposed. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 22 

Comment 14: The data used to develop the correction factor CFn in Equation W-16 was 

collected solely from onshore production sites, not ONGGB sites. 

EPA used data from a Texas Commission on Environmental Quality (TCEQ) study to develop 

this correction factor.24 The TCEQ study “gathered process, operational, and measurement data 

from tank batteries servicing gas or oil wells across the state.”25 Tank batteries that service gas or 

oil wells are not in the ONGGB industry segment (see also comment 2.2). Therefore, this dataset 

is irrelevant to ONGGB. If EPA retains this reporting requirement, they must use appropriate 

data to develop a representative emission estimate. Otherwise, this burdensome data collection 

effort will result in useless and uniformed emissions information. 

Footnotes: 

24 Id. At 132. 

25 TCEQ, Air Quality Research and Contract Reports: Emissions Inventory, 

https://www.tceq.texas.gov/airquality/airmod/project/pj_report_ei.html (last visited Feb. 23, 

2015). 
84 

Response 14: The EPA does not agree that the Onshore Petroleum and Natural Gas Gathering 

and Boosting segment will not include any tank batteries that service gas or oil wells. While tank 

batteries servicing gas or oil wells are most commonly found in Onshore Petroleum and Natural 

Gas Production facilities, some of these tank batteries will be in the Onshore Petroleum and 

Natural Gas Gathering and Boosting segment instead. Specifically, any tank battery that is not on 

or associated with a single well pad is not part of a facility in the Onshore Petroleum and Natural 

Gas Production segment and would be evaluated for inclusion in the Onshore Petroleum and 

Natural Gas Gathering and Boosting segment. Therefore, a correction factor that is based on 

“tank batteries servicing gas or oil wells” is expected to be relevant for both the Onshore 

Petroleum and Natural Gas Production segment and the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. 

3.2.4 Compressor Venting 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 2 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 6-7 

Comment 1: Commenter 0139: Our comments respectfully offer several specific 

recommendations to further strengthen the proposed rule: 

 Adopt direct measurement requirements for compressor emissions in the gathering and 

boosting segment. 

Commenter 0139: Commenters urge EPA to strengthen reporting requirements for compressors 

in the gathering and boosting segment. EPA proposes to adopt the same requirements for that 

segment as apply to compressors in the production segment.26 The agency requests comment, 

however, on the appropriateness of methods Subpart W currently uses for compressors in the 

processing segment, which rely on more direct measurement. We recommend that EPA apply the 

methods for compressor emission calculations in the natural gas processing, transmission, and 

underground storage segments to compressors in gathering and boosting. The ES&T Study 

discussed earlier underscores the importance of directly measuring these emissions. Moreover, 

the study identifies important gaps in the protocols for compressors (notably, the failure to 

require emissions reporting of nonoperational pressurized mode) that result in underreported 

emissions.27 Accordingly, we respectfully ask that EPA require direct measurement for gathering 
85 

and boosting compressors, consistent with Subpart W’s approach in the processing, transmission, 

and underground storage segments, and address some of the data gaps identified in the ES&T 

Study.28

Footnotes: 

26 79 Fed. Reg. at 73,155. 

27 ES&T Study, supra note 9, at F. 

28 Colorado State University, Press Release, Colorado State University Researchers Measuring 

Methane Emissions from Natural Gas Gathering and Processing Facilities (Oct. 14, 2013), 

available at http://www.news.colostate.edu/Release/7037. We also recommend that EPA 

consider the need to update the emissions factor for reciprocating engines at Subpart C, 40 

C.F.R. 98.33. Since most gathering and boosting facilities use reciprocating engines, combustion 

emissions for this segment could be substantially underestimated with the use of the current 

emissions factor. 

Response 1: The EPA considered requiring direct measurement for compressors in the Onshore 

Petroleum and Natural Gas Gathering and Boosting segment, consistent with the approach for 

compressors in the Onshore Natural Gas Processing, Onshore Natural Gas Transmission 

Compression, and Underground Natural Gas Storage segments. As a matter of fact, the EPA 

proposed direct measurement for compressors in the Onshore Petroleum and Natural Gas 

Production segment as well (75 FR 18608; April 12, 2010). After receiving multiple comments 

on the potential adverse consequences of implementing direct measurement, the EPA revised the 

final rule to exclude direct measurement for compressors. As explained in the memorandum 

Compressor Modes and Thresholds, (Docket Item No. EPA-HQ-OAR-2009-0923): 

The onshore production sector has many small compressors dispersed over 

hundreds of miles at production well-sites. These smaller compressors are 

typically reciprocating type and not “spared” (i.e. a single compressor that does 

not have a standby spare). Hence, they have a high operating factor and because 

of their type and size, have smaller process emissions (vented and equipment 

leaks) primarily from rod packing. By contrast the processing, transmission, gas 

storage, LNG storage and LNG import/export terminal sectors generally have 

larger compressors within a single facility boundary or adjacent to that boundary. 

These large compressors are of different types (reciprocating, centrifugal wet seal 

and centrifugal dry seal). They are almost always spared, and therefore have 

lower operating factors (more time in the standby depressurized mode) and higher 

emissions, particularly from wet seal centrifugals.” 

Given the fact that the basin-level definition of facility in the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment is similar to that for the Onshore Petroleum and Natural 

Gas Production segment, the Onshore Petroleum and Natural Gas Gathering and Boosting 

segment is also likely to include many small compressors dispersed over hundreds of miles. 

Therefore, the EPA has concluded that the approach for reporting emissions from compressors in 
86 

the Onshore Petroleum and Natural Gas Gathering and Boosting segment in this rulemaking 

should be consistent with the approach for the Onshore Petroleum and Natural Gas Production 

segment. 

3.2.5 Equipment Leaks 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 27-28 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 16 

Comment 1: Commenter 0132: Equipment Leaks by Population Count 

The major equipment categories are unclear and possibly not applicable to the ONGGB industry 

segment. 

GPA appreciates that EPA is proposing a population count method for estimating equipment leak 

emissions for the ONGGB industry segment. However, EPA has simply tacked on the ONGGB 

industry segment to the existing requirements for the onshore production industry segment. Due 

to limited time to provide comments, GPA was not able to evaluate the emission factors in Table 

W-1A and whether they are appropriate for ONGGB. GPA was also not able to investigate the 

source of data for Table W-1B and whether those counts are appropriate for ONGGB. However, 

GPA is concerned about the types of “major equipment” in Table W-1B. 

ONGGB facilities will not have wellheads, so this equipment type is not applicable. 

GPA is unclear what EPA means by “separators.” 

Does this refer to all vessels at a gathering and boosting compressor station that separate liquid 

by phases? As noted in previous comments, the high pressure separators and low pressure 

separators typically found at production sites are not necessarily the same types of separators that 

are used at ONGGB compressor stations. ONGGB compressor stations typically do not have 

“wellhead separators” because they do not typically have wellheads onsite. Many ONGGB 

compressor stations have a separator vessel at the inlet of the facility to separate liquids that 

condensed in the gas pipeline. The gas proceeds through the compressor train, which typically 

also includes compressor interstage knockout drums, which are separators. It is unclear if these 

interstage knockout separators should be included in the “separator” count, because 

“compressors” are another, separate major equipment type. 

GPA does not understand how to count “meters/piping.” 
87 

Section 98.233(r)(2)(i)(A) says, “[f]or meters/piping, use one meters/piping per well-pad.” There 

are no wellpads at ONGGB facilities, so would this count always be zero? 

GPA does not understand what “in-line heaters” are at ONGGB facilities. 

Sometimes at facility inlet and/or outlet meters, there may be small heating systems to ensure a 

temperate environment for the meter, but GPA does not think these are in-line heaters. The 

component counts here are very high, so GPA needs to understand how EPA thinks this major 

equipment type applies to ONGGB facilities. 

Commenter 0137: The EPA is proposing to use current methods in Subpart W, when available, 

for monitoring and calculating emissions from the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. 

The TSD does not address how to apply the major equipment types currently used for the 

Onshore Production segment to the Gathering and Boosting segment. In particular, it is not clear 

how the count of Meters/piping equipment is to be determined for a Gathering and Boosting 

facility. 

Response 1: With respect to the comment about “limited time to provide comments,” the length 

of the comment period was as provided by law and assumed sufficient. Additionally, as 

requested by several commenters, the EPA extended the comment period to allow more time to 

comment (80 FR 6495 (Feb. 5, 2014)). 

The EPA is finalizing the proposed population count method for equipment leaks in the Onshore 

Petroleum and Natural Gas Gathering and Boosting segment with a clarification regarding how 

to count “meters/piping.” See Section II.B.6 of the preamble to the final rule for more 

information. 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 9-10 

Comment 2: EPA proposes that emissions from natural gas gathering and boosting systems 

would only need to be reported if the collection of emission sources under common ownership or 

control within a single hydrocarbon basin emits 25,000 metric tons of CO2 equivalent or more 

per year. See 79 Fed. Reg. at 73,153. Once an operator hits this threshold, EPA proposes that 

operators monitor and report using the same method as in the Production segment: “Under the 

proposed approach, a reporter would need to establish an inventory of the components or 

equipment subject to the population counts, apply the emission factors, and then update the 

inventory each year to account for new or retired components or equipment.” See 79 Fed. Reg. at 

73,155. In the alternative, “for equipment leaks, the reporter may count the numbers of pieces of 

major equipment, assume the default component counts in Table W-1B, and then apply emission 

factors per component.” See id. 
88 

Kinder Morgan respectfully draws to EPA’s attention; however, that component counts within 

the gathering and boosting system would require a significant effort and expense not only at the 

outset but potentially on an annual basis. Given the similarities between types of equipment 

within the gathering and boosting segment, EPA should consider adding another, less 

burdensome approach to determining component counts. While Kinder Morgan has many of the 

same types of equipment within its gathering system (for example, Kinder Morgan may have 

multiple of the same make and model engines at multiple locations throughout the gathering 

system), the numbers of the various types of equipment at each location vary significantly based 

on the gas flow conditions for that particular portion of the gathering and boosting system. Thus, 

Kinder Morgan would not be able to conduct a component count at one gathering and boosting 

facility and duplicate that count at the next facility. Rather, Kinder Morgan proposes that EPA 

allow operators the option of developing representative component counts for each type of 

equipment and extrapolate that value across the entire gathering system within a single 

hydrocarbon basin to provide the same information in a more cost-efficient manner, rather than 

requiring a component-by-component count of every facility. Kinder Morgan proposes the 

following language to address its concerns: 

EPA Proposed 40 C.F.R. § 98.233(r)(2): . . . The component count can be 

determined using either of the calculation methods described in this paragraph 

(r)(2), except for miles of gathering pipelines, which must be determined using 

Component Count Method 2 in paragraph (r)(2)(ii) of this section. The same 

calculation method must be used for the entire calendar year. 

(i) Component Count Method 1. For all onshore petroleum and natural gas 

production operations and onshore petroleum and natural gas gathering and 

boosting operations in the facility perform the following activities: 

(A) Count all major equipment listed in Table W -1B and Table 

W-1C of this subpart. For meters/piping, use one meters/piping per 

well-pad. 

(B) Multiply major equipment counts by the average component 

counts listed in Table W-1B for onshore natural gas production and 

onshore petroleum and natural gas gathering and boosting; and 

Table W-1C of this subpart for onshore oil production. Use the 

appropriate factor in Table W-1A of this subpart for operations in 

Eastern and Western U.S. according to the mapping in Table W1D of this subpart. 

(ii) Component Count Method 2. Count each component individually for the 

facility. Use the appropriate factor in Table W-1A of this subpart for operations in 

Eastern and Western U.S. according to the mapping in Table W-1D of this 

subpart. 

(iii) Component Count Method 3. Develop representative component counts for 

each specific manufacturer make and model number of equipment in the onshore 
89 

natural gas gathering and boosting segment.3

 Multiply that representative 

component count by the number of that equipment type in service within the 

gathering and boosting segment within a single hydrocarbon basin. Use the 

appropriate factor in Table W- 1A of this subpart for operations in Eastern and 

Western U.S. according to the mapping in Table W- 1D of this subpart. 

Conducting a component-by-component count at all gathering and boosting facilities 

(particularly on an annual basis) would be a significant undertaking and unnecessary burden for 

operators. Kinder Morgan believes the above-proposed language resolves the issue. 

Footnotes: 

3

 Example of a manufacturer make and model may by a Caterpillar G3330 or Waukesha 275GL. 

Response 2: The EPA considered the commenter’s suggestion to include a Component Count 

Method 3 to develop representative component counts for each specific manufacturer make and 

model number of equipment. The EPA determined that this approach is not necessary, because 

Onshore Petroleum and Natural Gas Gathering and Boosting facilities are not required to use 

Calculation Method 2 only. Calculation Method 1, in which a reporter counts major equipment 

types and multiplies those counts by the number of components in Table W-1B, is provided as a 

less burdensome alternative to counting individual components. Section II.B.6 of the preamble to 

the final rule and the final amendments provide clarification regarding how to apply that method 

to the Onshore Petroleum and Natural Gas Gathering and Boosting segment. 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 10-11 

Comment 3: If EPA does not allow for representative component counts, in the alternative, 

Kinder Morgan proposes that EPA allow operators with facilities in the gathering and boosting 

segment adequate time to complete component counts both from the outset and over time as is 

set forth for certain equipment in the Production segment and proposed for the new gathering 

and boosting segment. In the Proposed GHG Reporting Rule, EPA states the following: 

EPA Proposed 40 C.F.R. § 98.233(a)(2): For the onshore petroleum and natural 

gas gathering and boosting industry segment, you have the option in the first two 

consecutive calendar years to determine “Count” for Equation W-1 of this subpart 

for each type of natural gas pneumatic device (continuous high bleed, continuous 

low bleed, and intermittent bleed) using engineering estimates based on best 

available data. 

See 79 Fed. Reg. at 73,176. Kinder Morgan respectfully requests EPA broaden the scope of this 

multi-year timeframe to apply to any individual component count undertaken for the gathering 

and boosting segment. Kinder Morgan proposes the following as a new subsection under 40 
90 

C.F.R. § 98.233(r). If operators selected the Calculation Method 2, discussed above, operators 

would be granted a reasonable amount of time to develop the necessary “count:” 

EPA Proposed 40 C.F.R. § 98.233(r)(2): (ii) Component Count Method 2. Count 

each component individually for the facility. Use the appropriate factor in Table 

W- 1A of this subpart for operations in Eastern and Western U.S. according to the 

mapping in Table W-1D of this subpart. For the onshore natural gas gathering and 

boosting industry segment, you have the option in the first two consecutive 

calendar years to determine “Count” for Equation W-1 of this subpart for all 

equipment in the natural gas gathering and boosting segment consistent with, as 

defined in this subpart, using engineering estimates based on best available data. 

Once component counts have been established, operators must update the 

component count at least once in any three consecutive calendar year period. 

This approach is consistent with the existing approach in the Production segment where 

operators “have the option in the first two consecutive calendar years to determine ‘Count’ for 

Equation W-1 of this subpart for each type of natural gas pneumatic device (continuous high 

bleed, continuous low bleed, and intermittent bleed) using engineering estimates based on best 

available data.” See 40 C.F.R. 98.233(a)(2).4 EPA should allow operators a multi-year timeframe 

(Kinder Morgan proposes three years, rather than two) to complete any initial component count 

of equipment in the natural gas gathering and boosting segment as granted with respect to certain 

components located within the Production segment. EPA should allow three years rather than 

two years to complete the initial component count because the gathering and boosting segment is 

new and operators will have to invest significant time and resources to develop the appropriate 

systems and management strategies to comply with any final GHG Reporting Rule. Similarly, 

EPA should allow the use of any component counts for a period of time (e.g., three-years) prior 

to requiring another updated component count. Kinder Morgan believes that one of these more 

flexible approaches (already put into practice under Subpart W), or a combination of the two, 

would create more reasonable expectations for operators to satisfy emissions calculations 

obligations. 

Footnotes: 

4 See also 40 C.F.R. § 98.233(o)(1)(i)(C) (with respect to centrifugal compressors, the operator 

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.”). 

Response 3: As noted in Response 2 in this section, Onshore Petroleum and Natural Gas 

Gathering and Boosting facilities are not required to use Calculation Method 2 only. Calculation 

Method 1, in which a reporter counts major equipment types and multiplies those counts by the 

number of components in Table W-1B, is provided as a less burdensome alternative to counting 

individual components. Therefore, the EPA is not providing additional time to develop 

component counts for equipment leaks from Onshore Petroleum and Natural Gas Gathering and 

Boosting equipment. 
91 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 7-9 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 9 

Comment 4: Commenter 0139: EPA should require annual or more frequent leak detection 

surveys. 

EPA proposes adopting production segment methods to calculate equipment leaks in the 

gathering and boosting segment.31 Under this approach, equipment leaks would be calculated 

using population counts and the applicable emission factor according to the procedures set forth 

at 40 C.F.R. 98.233(r). We strongly urge EPA to instead adopt the leak detection survey 

requirements at 40 C.F.R. 98.233(q) for gathering and boosting facilities. Specifically, we 

recommend that EPA incorporate requirements for direct leak detection and monitoring surveys 

(using infrared cameras or similar equipment) and robust quantification of emissions at least 

annually, if not more frequently. 

EPA explains that the population count methods at section 98.233(r) are appropriate because the 

gathering and boosting segment is similar to production in size and number of sources.32 Subpart 

W should also require at least annual direct leak detection and monitoring for well production 

sites for the same reasons cited here for requiring leak detection in gathering and boosting. Even 

so, the gathering and boosting segment is not comparable to the production segment in the way 

the proposal suggests. In fact, estimates suggest that the gathering and boosting segment more 

closely resembles other segments for which leak detection surveys are required. For instance, the 

Greenhouse Gas Inventory estimates that there are approximately 36,000 gathering compressors 

in the oil and natural gas sector.33 This figure is well below the number of oil and gas production 

wells nationwide, and is even lower than the number of above grade transfer stations in the 

distribution segment reporting under Subpart W, which are subject to direct leak detection 

surveys under Subpart W.34 We urge EPA to adopt a requirement for comprehensive, frequent, 

and direct leak detection and quantification in both the production segment and gathering and 

boosting segment, as direct inspection methods are low-cost and available and result in more 

accurate and transparent emissions data. 

Direct and frequent monitoring of leaks in the gathering and boosting segment would promote 

transparency and accountability for existing sources. Leaks are the single largest source of 

fugitive methane emissions from the oil and gas sector35 and are a significant source at gathering 

facilities, according to the ES&T Study.36 Moreover, according to analysis conducted by ICF 

International, leaks are also the leading opportunity for cost-effective emissions reductions.37
92 

Direct leak inspection and reporting would enable facilities to identify and prioritize needed 

repairs and would help to support measures to protect public health and the environment. 

Moreover, the Administration’s January methane announcement underscores the importance of 

shifting towards more direct measurement of leaks in the oil and natural gas sector, and this 

rulemaking represents an opportunity to begin realizing that commitment by establishing such 

requirements.38

Requiring direct measurement, inspection, and reporting of leaks at sources in the gathering and 

boosting segment would also rely on technologies many states have already deployed to help 

find and fix leaks. For instance, Colorado recently finalized leak detection and repair 

requirements at compressor stations at or upstream of natural gas processing plants. Under 

Colorado’s tiered leak detection and repair approach, the frequency of mandatory leak 

inspections depends on the size and emissions potential of the facility and ranges from one-time 

to monthly inspections. Colorado allows inspection using Method 21, infrared camera, or an 

equivalent instrument-based detector (which could also allow for advances in monitoring 

technology).39 Additionally, Wyoming requires new and modified facilities located in the Upper 

Green River Basin Nonattainment Area that have the potential to emit at least 4 tons per year of 

volatile organic compounds from fugitive sources to institute quarterly leak monitoring by 

Method 21, infrared camera, or some combination thereof.40 Wyoming has also proposed 

regulatory revisions that would apply these requirements to existing sources in the Upper Green 

River Basin.41

Footnotes: 

31 79 Fed. Reg. at 73,155. 

32 Proposal TSD, supra note 7, at 14. 

33 Inventory of U.S. Greenhouse Gas Emissions and Sinks, supra note 10, Annex 3 tbl. A-125. 

34 40 C.F.R. 98.232(i)(1), 98.233(q). 

35 ICF Cost Curve Report, supra note 6, at 3-6. 

36 ES&T Study, supra note 9, at F-G. 

37 ICF Cost Curve Report, supra note 6, at 1-2. 

38 Methane Announcement Fact Sheet, supra note 5. 

39 Co. Dep’t of Pub. Health & Env’t Reg. No. 7 (5 CCR 1001-9), Unofficial Draft (Feb. 23, 

2014) Section XVII.F. 

40 Wyo. Dep’t of Envtl. Quality, Oil and Gas Production Facilities: Chapter 6 Section 2 

Permitting Guidance (June 1997, Revised Sept. 2013). 
93 

41 Wyo, Dep’t of Envtl. Quality, Draft Nonattainment Area Regulations, at Ch. 8 (June 4, 2014), 

available at http://deq.state.wy.us/aqd/proposedrules_files/Chapter%208%20-

%20Nonattainment%20Area%20Regulations- Oil%20and%20Gas%20draft%206-4-14.pdf. 

Commenter 0142: Kinder Morgan supports EPA’s proposal not to require annual leak surveys at 

gathering and boosting facilities because such requirement would unduly burden industry. 

Response 4: While the EPA is considering other methods for future amendments, the EPA has 

decided to make no changes in this rulemaking package for emissions from equipment leaks in 

the Onshore Petroleum and Natural Gas Gathering and Boosting segment. These revisions are 

finalized as proposed. 

3.2.6 Gathering Pipeline Equipment Leaks 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 11-12 

Comment 1: With respect to population counts for pipelines in the gathering and boosting 

segment, Kinder Morgan supports EPA’s suggestion that the “population count” for pipelines 

should be the miles of pipeline multiplied by the emission factor. See 79 Fed. Reg. at 73,155; see 

also 40 C.F.R. § 233(r). EPA applies this approach for calculating emissions from the natural gas 

distribution pipelines in the Natural Gas Distribution segment, and Kinder Morgan believes EPA 

should apply this approach to pipelines only in the Gathering and Boosting segment as well as 

for consistent treatment of pipelines. 

Response 1: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed. 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 3 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 16 

Comment 2: Commenter 0125: We assume that EPA intends to allow the use of company 

records and engineering estimates for determining the gas gathering pipeline distances when 

utilizing this emission factor, such that these distances do not need to be explicitly measured by 
94 

field surveys which would be prohibitively expensive (upwards of $9,000 per mile surveyed1

). 

Thus, we request confirmation of this assumption. 

Footnotes: 

1

 Operator-provided Alliance member estimate for hiring a contractor to conduct surveys. 

Commenter 0134: API requests that data collected annually under PHMSA pipeline regulations 

for pipeline length be used to report gathering pipelines length for Subpart W. 

Response 2: It is EPA’s intent to allow the use of company records and engineering estimates 

for determining the gas gathering pipeline distances when utilizing the gathering pipeline 

emission factor. These distances do not need to be explicitly measured by field surveys. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 15-16 

Comment 3: For estimating emissions from gas gathering pipeline segments, EPA is proposing 

to use a factor of 2.81 scf gas/hour/mile. The API Compendium cites an emission factor of 2.67 

scf gas/hour/mile for gathering pipelines. Both are derived from the 1996 GRI/EPA study, but 

apply different gas properties (different standard conditions and CH4 contents). However, both 

emission factors are developed from data for natural gas distribution mains from the 1996 

GRI/EPA study. This fugitive emission factor is not applicable to gathering pipelines that carry 

primarily liquids, as there is no gas stream until after separation. Following separation the gas is 

usually turned over to the third party gas company and the oil to an oil distributor. 

API is not aware of any studies since the 1996 GRI/EPA study that examined fugitive emissions 

from buried gas gathering pipelines. There is, however, updated information on the type of 

gathering pipelines. The Pipeline and Hazardous Materials Safety Administration (PHMSA) 

reports the annual miles of gathering pipelines by material type.3

 API suggests updating the 

GRI/EPA emission factors on the basis of the current gathering pipeline material type. The 

derivation of a more current emission factor is provided in the Table below. 

Applying a sumproduct of columns A and B results in a weighted average CH4 emission factor 

of 1.76 scf CH4/mile-hr. This is converted to a gas basis consistent with the units for EPA’s 

proposed emissions factor by dividing by the CH4 content from the GRI/EPA study of 78.8%, 

resulting in an emission factor of 2.23 scf gas/mile/hr. API requests the use of this emission 

factor which represents current occurrence of gathering pipe materials for gathering pipelines 

carrying natural gas. 
95 

 Table 9-4 of GRI/EPA Volume 9 Report A B 

Pipeline 

Material 

Average 

Emission 

Factors, 

scf/leak-yr 

Average Activity 

Factor (Equivalent 

Leaks) 

CH4 

Emissions, 

Bscf 

Miles of 

Gathering 

Pipelines1

Derived 

GRI/EPA 

Emission 

Factor: Scf 

CH4/hourmile 

Percentage of 

Onshore 

Gathering 

Mileage 

Reported in 

2013 

Protected Steel 17,102 53,657 leaks 0.9 268,082 0.39 81% 

Unprotected 

Steel 

43,705 114,655 leaks 5.0 41,400 13.82 9% 

Plastic 84,237 6,467 leaks 0.6 29,862 2.08 8% 

Cast Iron 201,418 856 miles 0.2 856 22.99 0% 

1

 Table 8-9 of GRI/EPA Volume 9 Report 

2

 PHMSA 2013 Gas Transmission & Gathering Annual Data 

Footnotes: 

3

http://www.phmsa.dot.gov/portal/site/PHMSA/menuitem.6f23687cf7b00b0f22e4c6962d9c8789/

?vgnextoid=a872dfa122a1d110VgnVCM1000009ed07898RCRD&vgnextchannel=3430fb649a2

dc110VgnVCM1000009ed07898RCR D&vgnextfmt=print 

Response 3: The EPA agrees with the commenter that the emission factor should be revised 

from proposal, and the final rule provides gathering pipeline emission factors by pipeline 

material type. See Section II.B.5 of the preamble to the final rule for additional information. 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 2 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 7 

Comment 4: Commenter 0139: Our comments respectfully offer several specific 

recommendations to further strengthen the proposed rule: 

 Require direct measurement of gathering pipeline leaks. 

Commenter 0139: We recommend that EPA require facilities to collect data to update the 

emission factor for gathering pipeline leaks and to use this data to develop facility- and material-
96 

specific pipeline emissions factors (as has been done in the distribution segment). The currently 

proposed per-mile emission factor could be used while this data is being collected. The emission 

factors used in the GHG Inventory (from the GRI/EPA study) were based on measurements of 

local distribution mains, not gathering pipelines. As EPA illustrates in its Technical Support 

Document for the proposed rule, gathering pipelines generally differ from distribution mains in 

material, size, and maximum operating pressure and there is variation even within the gathering 

and boosting segment in material, size, and pressure.29 Despite the adaptation from distribution 

emissions factors, the existing emissions factors may not accurately represent emissions from 

these sources.30 We therefore urge the agency to update the emission factor based on direct 

measurement of gathering pipeline leaks. We also recommend that the agency investigate 

alternative methods such as leak detection and quantification of individual leaks. 

Footnotes: 

29 Proposal TSD, supra note 7, at 22 tbl. 2.3. 

30 Id. at 22. 

Response 4: As noted in Response 4 in Section 3.2.5 of this document, the EPA has decided to 

make no changes in this rulemaking package for emissions from equipment leaks in the Onshore 

Petroleum and Natural Gas Gathering and Boosting segment. As the commenter noted, the EPA 

has used the best data available to apply the distribution mains emission factor to gathering 

pipelines. The EPA is currently considering other methods of estimating emissions for potential 

future amendments. 

3.2.7 Fuel Combustion Equipment 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 25 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 26 

Comment 1: Commenter 0132: EPA should provide reporters with the option of using either 

calculation method (1) or (2) under section 98.233(z). 

EPA is setting a new precedent by deviating from previously accepted compliance methods 

within the same source category. 

Since 2011, EPA has required owners and operators of boosting stations with emissions 

exceeding 25,000 mt CO2e to calculate and report combustion emissions using methods listed in 
97 

Subpart C of this part. Many owners and operators who would be required to report under the 

new ONGGB industry segment have already been reporting combustion emissions, for sites in 

the same industry segment, under Subpart C of this part. Requiring these same reporters to now 

use a different calculation methodology sets an unfair precedent, and imposes additional 

reporting burdens by deviating from previously accepted compliance methods. GPA suggests 

that the existing combustion calculation methodology used in Subpart C is sufficiently accurate 

for future use at all booster stations. Differences in the heating values between fuel types used 

for combustion sources within the gathering and boosting industry segment is expected to result 

in minor differences in GHG emissions. GPA does recognize that EPA models this reporting 

methodology after one that is already in use in the Onshore Petroleum Natural Gas Production 

industry segment, however, one size does not fit all. What works for the Onshore Petroleum 

Natural Gas Production will not work necessarily work in the ONGGB category. Onshore 

Petroleum Natural Gas Production and ONGGB are differentiated as source categories because 

of their vastly different functions and equipment. 

Commenter 0132: The cost and time burden of a new calculation methodology does not justify 

the negligible difference in emissions provided by the different methodologies. 

GPA recognizes that EPA is trying to account for the differences in fuel gas used in combustion 

equipment. However, GPA does not agree with EPA that this distinction is warranted. 

Depending on fuel type, there could be anywhere from a 0-15% difference in emissions between 

the calculation methodologies. In the overall inventory this is negligible and does not justify the 

additional substantial burden that would be imposed. Additional fuel sample analyses would be 

required and current environmental management systems would have to be reprogrammed. In 

addition, there would be a significant new cost for training associated with a new calculation. 

Staff would need to be trained on how to gather and collect the data, as well as, separate staff 

trained to manage, calculate, and report the data. While there would be costs associated with 

expanded reporting regardless of method, use of a prior method would allow staff to use methods 

that have been in place since the birth of the GHG Reporting Rule. 

Response 1: The EPA does not agree that we are setting a precedent by requiring facilities in the 

Onshore Petroleum and Natural Gas Gathering and Boosting segment that were reporting under 

subpart C to instead report combustion emissions using the methods in subpart W. Subpart C was 

finalized on October 30, 2009 (74 FR 56374), and subpart W was finalized November 30, 2010 

(75 FR 74458). Therefore, for reporting year 2010, facilities that would later be defined as 

Onshore Petroleum and Natural Gas Production facilities under subpart W originally reported 

emissions from their combustion sources under subpart C. The EPA acknowledges that there 

may be a one-time cost associated with changing the calculation methods for combustion sources 

in an Onshore Petroleum and Natural Gas Gathering and Boosting facility, but ultimately this 

change is expected to reduce the burden by consolidating reporting. In addition, owners and 

operators of Onshore Petroleum and Natural Gas Gathering and Boosting facilities will be 

allowed to use BAMM for the first year of reporting, which will allow time to transition to using 

the new methods. 
98 

3.3 Reporting Requirements 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 2 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 6 

Comment 1: Commenter 0139: Our comments respectfully offer several specific 

recommendations to further strengthen the proposed rule: 

 Require more granular, site-specific information for gathering and boosting facilities 

within basin-level reports. 

Commenter 0139: While we support basin-level reporting, we urge EPA to ensure each report 

also includes more granular, site-specific analysis of emissions data from the gathering and 

boosting segment. In particular, we respectfully ask that EPA require owners and operators to 

report the number of gathering and boosting sites in each basin-level facility, the non-pipeline 

emissions attributable to each site, and the types and number of equipment in each site. Under 

this approach, EPA could provide further guidance on how owners and operators should 

delineate separate gathering and boosting systems and sites.25 We also urge the agency to require 

reporting of more detailed information on the gathering pipelines in a system, including material, 

diameter, and maximum pressure if available. 

A single basin-level report could then separate non-pipeline data on a site-by-site basis. To 

facilitate system-level reporting, owners and operators could assign system identification 

numbers or generic descriptions to individual gathering and boosting sites within the larger basin 

facility. Source emissions within the larger facility could then be grouped by site identifiers 

within basin reports. This would help to maximize the data collected for a single gathering and 

boosting facility by providing valuable site-specific information for sources within that facility. 

Moreover, many owners and operators will likely collect this data at the level of the individual 

site (rather than for the entire basin), and providing the data in that form would enable detailed 

analysis and verification of the emissions from this segment. More site-specific data could also 

be used for comparison with basin-level data to improve and refine reporting requirements. 

Given the need for more detailed information about the gathering and boosting segment and its 

close connection with the production segment, requiring site-level information will improve the 

overall accuracy of emissions data. 
99 

Footnotes: 

25 In 40 C.F.R. 98.6, EPA currently defines a “site” in the production segment as “any 

combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the 

immediate physical location upon which equipment is physically located.” EPA could similarly 

define a gathering and boosting “site” as “gathering & boosting equipment on a single property.” 

The ES&T Study found that gathering and boosting stations contained compression, dehydration, 

and treatment, or some combination thereof. ES&T Study, supra note 9, at C. 

Response 1: The EPA is not changing the reporting requirements for gathering and boosting 

facilities in the final rule. The EPA believes that the information being collected for the Onshore 

Petroleum and Natural Gas Gathering and Boosting segment will result in improved knowledge 

of the gathering and boosting industry, which will be useful to support verification and possibly 

inform future rules.

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 34 

Comment 2: The data element in section 98.236(aa)(10)(ii), “quantity of produced gas 

consumed,” is redundant of Subpart C and must be deleted. 

GPA does not understand what information EPA is attempting to collect here. GPA assumes that 

by “consumed,” EPA means “combusted.” We do not understand how this data element differs 

from Subpart C. Subpart C contains extensive reporting requirements that are tailored for various 

fuel accounting systems. This data element is redundant of Subpart C, and including it here will 

cause confusion and additional work to try to boil down and combine the complex Subpart C 

reported data into this one single line item. This data element also undermines the specifically 

crafted exemptions that Subpart C allows, such as fuel used by pilot lights.28

Footnotes: 

28 40 C.F.R. 98.30(d); see also id. section 98.30(b). 

Response 2: This data element has been removed from the reporting requirements for the 

Onshore Petroleum and Natural Gas Gathering and Boosting segment. See Section III.B of the 

preamble to the final rule for more information. 

The EPA also notes that the final rule specifies that emissions from fuel combusted in stationary 

or portable equipment at Onshore Petroleum and Natural Gas Production facilities, at Onshore 

Petroleum and Natural Gas Gathering and Boosting facilities, and at Natural Gas Distribution 

facilities will be reported according to the requirements specified in 40 CFR 98.236(z) and not 

according to the reporting requirements specified in subpart C. Therefore, there will be no cases 

where a subpart W Onshore Petroleum and Natural Gas Gathering and Boosting facility is also 
100 

reporting under subpart C. For example, a facility that is classified as a compressor station may 

currently be reporting only under subpart C, but when these amendments take effect, the facility 

may become subject to subpart W under classification in the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. In that case, the facility would no longer report under 

subpart C. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 34-35 

Comment 3: EPA must remove the reporting element in section 98.236(10)(aa)(v), “[t]he 

quantity of gas flared, vented and/or unaccounted for in the calendar year, in thousand standard 

cubic feet.” 

This data element undermines over five years of Subpart W rule development, public comment, 

reconsiderations, and petitioner negotiations. 

The purpose of the extensive and prescriptive data collection, quality assurance, calculation, and 

reporting requirements of Subpart W is to consistently account for gas vented and flared in 

Petroleum and Natural Gas Systems. This single data element effectively requests all the same 

information, but without any guidance or standard methods. This also undermines the equipment 

specific provisions to ease reporting burden, such as the exclusion of blowdowns less than 

50 cubic feet physical volume.29 These blowdowns would have to be reported under this data 

element. Thus, this data element undermines over five years of rule development, public 

comment, reconsiderations, and petitioner negotiations. 

Prior to the proposed rule, “unaccounted for” gas has been specifically exempted from reporting 

in Subpart W. 

For natural gas distribution, section 98.236(aa)(9)(iv) says, “[t]he quantity of natural gas 

delivered to end users, in thousand standard cubic feet. This value does not include stolen gas, or 

gas that is otherwise unaccounted for,” and section 98.236(aa)(9)(v) says, “[t]he quantity of 

natural gas transferred to third parties such as other LDCs or pipelines, in thousand standard 

cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for.” Why 

is EPA requesting the ONGGB industry segment to report “unaccounted for” gas when EPA has 

specifically exempted the natural gas distribution industry segment from reporting “unaccounted 

for” gas? 

Gas that is “unaccounted for” should not be lumped together with gas that is flared and vented. 

EPA does not define what “unaccounted for” gas means. GPA assumes this means the difference 

between the quantities of gas measured at the inlets to the ONGGB facility and the quantities of 

gas measured at the outlets of the ONGGB facility (which includes measured vents, measured 

flares, measured condensate production, measured fuel use, measured process gas use, and 
101 

measured process gas). “Unaccounted for” means just that – the gas was not accounted for. This 

could be due to lack of measurement points or meter calibration discrepancies. “Unaccounted 

for” does not necessarily mean that gas was lost to atmosphere. Yet by having this data element 

that says, “quantity of gas flared, vented and/or unaccounted for,” EPA seems to imply that this 

gas was emitted to atmosphere. As such, this reporting element would yield very misleading 

information for the EPA and the public (as EPA proposed that this data element is not CBI). 

Performing a facility-wide mass balance is very challenging and reporters will not perform these 

balances consistently. 

First, EPA is requesting that a mass balance be reported on each ONGGB facility, which EPA 

has defined as all ONGGB equipment within a basin. As noted in a previous comment, gathering 

systems may span across multiple basins. Thus, under the proposed rule, an ONGGB facility 

may not align with how the gathering system is situated. Owners and operators will typically 

perform mass balances across a gathering system, and their measurement systems are set up for 

these determinations. However, if the gathering system spans multiple basins, the measurement 

systems will not be configured to perform such a mass balance. It may not even be possible to 

perform such a mass balance or it will require significant work to establish a secondary mass 

balance just for the GHG Reporting Rule. 

Also, as noted above, to perform a mass balance on a system, one must evaluate measured vents, 

measured flares, measured condensate production (from gas turning into condensate) (where 

condensate must be converted to a gas equivalent), measured fuel use, measured gas from 

production sites or upstream ONGGB compressor stations, measured non- fuel use of process 

gas or fuel gas (such as for stripping gas or pneumatic systems) and measured process gas exiting 

the system. This is a very complex analysis, and not all operators will perform it the same way. 

For example, some condensate that is produced in ONGGB (from gas condensing into 

condensate) is “credited” to the producer, and different operators may account for this credited 

condensate differently; some will view it as “lost” gas. Also, this data element may unfairly 

disadvantage owners and operators who do not have extensive measurement networks. This 

reporting element will make it look like those companies “lose” more gas than others, but it is 

not necessarily “lost”; it is simply unaccounted for. 

Footnotes: 

29 Id. section 98.233(i)(2). 

Response 3: This data element is not required to be reported in the final rule. See Section III.B 

of the preamble to the final rule for more information. 
102 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 33 

Comment 4: GPA does not understand what the terms “produced gas,” “produced condensate,” 

and “produced oil” mean in section 98.236(aa)(10). 

These are terms that are relevant to the Onshore Production industry segment, but they are not 

relevant to the ONGGB industry segment. 

In section 98.236(aa)(10)(i), EPA requests “[t]he quantity of produced gas throughput in the 

calendar year.” 

How is this “produced gas” distinct from “natural gas” which is the term used in section 

98.236(aa)(3)(i) for natural gas processing? The gas that is gathered and boosted in the ONGGB 

industry segment is effectively the same type of gas that enters a gas plant. 

In section 98.236(aa)(10)(ii), EPA requests “[t]he quantity of produced gas consumed in the 

calendar year.” 

Again, what does EPA mean by “produced gas” in this instance. It is common for gathering and 

boosting stations to use residue gas from the downstream gas processing plant for fuel. In these 

scenarios, is this type of clean fuel gas considered to be “produced gas?” 

In section 98.236(aa)(10)(iii), EPA requests “[t]he quantity of produced condensate throughput 

in the calendar year.” 

As noted in an earlier comment, GPA does not typically consider the condensate that formed in 

the gathering pipeline to be “produced condensate.” Would the condensate that condensed in the 

gathering pipeline not be reported under this data element? Also, what does EPA mean by 

“throughput” since condensate is formed within a gathering system? GPA assumes that EPA 

must mean the total condensate that exits the gathering system, but we request clarification. 

In section 98.236(aa)(10)(iv), EPA requests, “[t]he quantity of produced oil throughput in the 

calendar year.” 

GPA is unclear what an ONGGB facility owner or operator would report here. Oil is not 

produced in the ONGGB industry segment. This data element should be deleted. 

Response 4: The proposed data elements that included these terms have been revised for the 

final rule. See Section III.B of the preamble to the final rule for more information. 

 
103 

4.0 Natural Gas Transmission Lines Between Compressor Stations 

4.1 Applicability and Definitions 

Commenter Name: Pamela Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Comment Number: EPA-HQ-OAR-2014-0831-0136 

Page(s): 1-4 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 7 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 14 

Comment 1: Commenter 0136: We have a simple request to clarify the scope of “intrastate 

pipelines” that would be covered by the proposed requirement to report emissions from 

blowdowns, so that it is clear which intrastate pipelines are included and which ones are 

excluded. 

We are not sure whether the proposed regulatory language would exclude intrastate transmission 

pipelines that offer only intrastate service. The regulatory text requires the reader to consult with 

an attorney who has a thorough understanding of which types of intrastate pipeline operators are 

– or are not – required to have a Statement of Operating Conditions from the Federal Energy 

Regulatory Commission (FERC) under section 311 of the Natural Gas Policy Act. To avoid 

misunderstandings, AGA requests that EPA make a simple clarification in the definition of 

transmission pipeline owner and operator, and provide a clear, “plain English” explanation in the 

preamble to the final rule. 

EPA is proposing to require reporting of blowdown emissions from interstate transmission 

pipelines and from certain intrastate transmission lines. Many AGA member gas utilities operate 

high pressure intrastate transmission pipelines to transport natural gas to the various distribution 

systems they operate within a single state. Most of these utility-operated intrastate pipelines do 

not provide interstate transportation service to interstate pipelines or to other distribution utility 

companies, and thus are not required to obtain a Statement of Operating Conditions from FERC 

under section 311 of the Natural Gas Policy Act (NGSA) and FERC’s implementing regulations 

under 18 C.F.R. Part 284. Only those intrastate pipelines that provide interstate transportation 

service are required to file a Statement of Operating Conditions with FERC. However, it takes a 

close reading of the proposed regulations and consultation with an attorney well versed in the 

requirements of NGSA section 311 to understand that distinction. AGA is concerned that there 

may be confusion among the regulated community and enforcement personnel unless EPA 

provides a less obscure explanation in the preamble to the final rule, as discussed below. 
104 

AGA Supports Exclusion of Intrastate Transmission Lines in Intrastate Service

In proposed section 98.236(i)(3), EPA would require the operator of a “facility” in the “onshore 

natural gas transmission segment” to report annual carbon dioxide and methane emissions from 

“each separate transmission pipeline blowdown event” and the location of each blowdown. 

To find out whether a utility-operated intrastate transmission pipeline would be covered by this 

requirement to report blowdowns, one must consult several overlapping definitions in the 

proposed and existing versions of section 98.238: 

 Proposed definition: “Facility with respect to the onshore natural gas transmission 

pipeline segment means the total U.S. mileage of natural gas transmission pipelines, as 

defined in [the existing Subpart W rule] owned and operated by an onshore natural gas 

transmission pipeline owner or operator as defined in this section.” 

 Existing definition: “Transmission pipeline means a [FERC] rate-regulated Interstate 

pipeline, a state rate-regulated Intrastate pipeline, or a pipeline that falls under the 

“Hinshaw Exemption” as referenced in section 1(c) of the Natural Gas Act...” 

 Proposed definition: “Onshore natural gas transmission pipeline owner or operator

means, for interstate pipelines..., or, for intrastate pipelines, the person identified as the 

owner or operator on the transmission pipeline’s Statement of Operating Conditions 

under section 311 of the Natural Gas Policy Act.” 

Although it requires close reading of the regulatory text to find the answer, we believe the 

proposed rule should exclude operators of intrastate pipelines that offer only intrastate service or 

only a de minimis amount of interstate service and thus are not identified in any Statement of 

Operating Conditions under NGPA section 311. AGA supports this exclusion, but we urge EPA 

to clarify the proposed definition as suggested in our specific comments below. 

We support the exclusion for the following reasons. Blowdowns are a safety precaution. 

Operators of natural gas systems typically empty lines of natural gas before performing repairs or 

replacing pipe. In large transmission pipelines that provide interstate service, these events are 

likely to be connected with large projects that are subject to FERC regulations. It may make 

sense to combine intrastate lines that provide interstate service under a FERC Statement of 

Operating Conditions with FERC-regulated interstate pipelines in a single reporting segment 

under Subpart W. However, utility-operated intrastate transmission lines that provide intrastate 

service are different. These lines are subject to state utility commission oversight rather than 

FERC regulation, and utilities must obtain state utility commission approvals to obtain cost 

recovery for pipe replacement and repair projects that drive much of the need for blow down 

events. 

Moreover, AGA and its members are currently working with EPA’s Natural Gas STAR program 

staff to develop an enhanced voluntary program for reducing natural gas emissions that would 

include any additional reporting associated with the program. AGA supports this effective, 

voluntary initiative, and we support EPA’s proposal to exclude intrastate transmission lines from 

the mandatory blow down reporting requirement that is designed for FERC-regulated 

transmission pipelines that provide interstate transportation service. 
105 

AGA’s Specific Comments: Clearly Explain Intrastate Pipeline Exclusion

1. Clarify Definition of Transmission Pipeline Owner or Operator 

Section 98.238: To ensure that the regulated community and enforcement personnel understand 

who is – and is not – required to report blowdowns under Subpart W, we urge EPA to revise the 

proposed definition of “Onshore natural gas transmission pipeline owner or operator” in 40 

C.F.R. 98.238 to insert the words “providing interstate natural gas transportation service” as 

follows: 

“Onshore natural gas transmission pipeline owner or operator means, for 

interstate pipelines..., or, for intrastate pipelines providing more than a de minimis 

amount of interstate natural gas transportation service, the person identified as the 

owner or operator on the transmission pipeline’s Statement of Operating 

Conditions under section 311 of the Natural Gas Policy Act.” 

2. Clearly Explain the Intrastate Pipeline Exclusion in the Final Preamble

AGA also urges EPA to include an explanation in the preamble to the final rule clearly 

explaining that the requirement to report blowdown emissions applies only to certain types of 

intrastate transmission pipelines that have filed a Statement of Operating Conditions with FERC 

to provide interstate natural gas transportation service, but the blowdown reporting requirement 

does not apply to intrastate transmission pipelines that only provide intrastate or a de minimis 

amount of interstate natural gas transportation service and thus have not filed a FERC Statement 

of Operating Conditions. 

Commenter 0140: INGAA believes that the EPA should clarify its distinction of which intrastate 

pipelines are affected by the Proposed Rule. 

EPA proposes that its rule apply only to intrastate pipelines that are identified in connection with 

Section 311 of the Natural Gas Policy Act of 1978 (NGPA). However, the Federal Energy 

Regulatory Commission (FERC) regulates these particular pipelines on a limited basis because 

such pipelines have a statutory exemption to engage in interstate transactions (transportation or 

storage) without the entity being subject to the full scope of regulation pursuant to the Natural 

Gas Act. 15 U.S.C. 717(f)-(w). Consequently, intrastate pipelines that perform NGPA Section 

311 transportation do not represent the full universe of intrastate natural gas transmission 

pipelines. Therefore, INGAA asks EPA to clarify why the agency decided to limit its reporting 

requirements only to the Section 311 intrastate pipelines rather than all intrastate pipelines. 

Commenter 0142: EPA proposes to define the onshore natural gas transmission pipeline owner 

or operator based on whether the transmission pipeline is interstate or intrastate. See 79 Fed. 

Reg. at 73,156. Kinder Morgan agrees with EPA’s proposed approach, with one exception. EPA 

states that for intrastate pipelines, the operator should be the operator identified on the pipeline’s 

Statement of Operating Conditions prepared for compliance under section 311 of the Natural Gas 

Policy Act (“NGPA”). Section 311 of the NGPA allows an interstate pipeline company to sell or 

transport gas on behalf of any intrastate pipeline or local distribution company without prior 
106 

approval from the Federal Energy Regulatory Commission (“FERC”). Kinder Morgan notes, 

however, that there may be instances when a company does not provide services under Section 

311 of the NGPA and thus the owner or operator is not identified on the “Statement of Operating 

Conditions.” In the event of this situation, which would be true for at least one of Kinder 

Morgan’s intrastate facilities, Kinder Morgan proposes that EPA clarify that the owner or 

operator would be the entity that files reports with the appropriate state agency. Kinder Morgan 

proposes the following revision to EPA’s proposed definition: 

EPA Proposed 40 C.F.R. 98.238: Onshore natural gas transmission pipeline 

owner or operator. Onshore natural gas transmission pipeline owner or operator 

means, for interstate pipelines, the person identified as the transmission pipeline 

owner or operator on the Certificate of Public Convenience and Necessity issued 

under 15 U.S.C. 717f, or, for intrastate pipelines, the person identified as the 

owner or operator on the transmission pipeline’s Statement of Operating 

Conditions under section 311 of the Natural Gas Policy Act, unless the owner or 

operator does not provide services under Section 311 of the Natural Gas Policy 

Act in which case the owner or operator shall be the person identified as the 

owner or operator on the required reports with the appropriate state agency. 

With the above revision, Kinder Morgan would be comfortable with EPA’s proposed definition 

of onshore natural gas transmission pipeline owner or operator. 

Response 1: To clarify the intent to include all intrastate transmission pipelines that meet the 

Subpart W definition of “transmission pipeline, the finalized definition of “onshore natural gas 

transmission pipeline owner or operator” specifies how to determine the owner or operator for 

intrastate transmission pipelines not subject to section 311 of the NGPA and pipelines that fall 

under the “Hinshaw exemption.” See Section II.C.2 of the preamble to the final rule for 

additional information. 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 3 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 7-8 

Comment 2: Commenter 0133: Transmission Pipeline Segment Definitions 

We agree with EPA’s approach of grouping blowdown emissions for all company-owned or 

operated transmission pipelines into one report, regardless of location or connectivity. 
107 

Facility with respect to the onshore natural gas transmission pipeline segment

means the total U.S. mileage of natural gas transmission pipelines, as defined in 

this section, owned and operated by an onshore natural gas transmission pipeline 

owner or operator as defined in this section. 

Onshore natural gas transmission pipeline owner or operator means, for 

interstate pipelines, the person identified as the transmission pipeline owner or 

operator on the Certificate of Public Convenience and Necessity issued under 15 

US.C. 717f, or, for intrastate pipelines, the person identified as the owner or 

operator on the transmission pipeline’s Statement of Operating Conditions under 

section 311 of the Natural Gas Policy Act. 

Combining all company-owned or operated pipelines into one facility reduces the reporting 

burden. However, because we own and operate two companies (DTI and the EOG Company), it 

is unclear if two separate company reports will be required. We request clarification regarding 

the reporting entity. 

We request that the reporting entity be based on operating company, which could be a subsidiary 

of a larger parent company. The East Ohio Gas Company and Dominion Transmission are two 

separate Federal Energy Regulatory Commission (FERC) Code of Conduct (COC) operating 

entities with different Designated Representatives under the EPA Greenhouse Gas Reporting 

Program. In addition, both entities report to the FERC under the subsidiary name rather than the 

parent company name. Therefore, we request provisions that would allow for EOG and DTI to 

each file their own separate reports. 

Commenter 0140: INGAA supports reporting pipeline blowdown emissions by operating 

company. 

In the definition section of the Proposed Rule, the EPA defines a “facility” for an onshore natural 

gas transmission pipeline segment as “the total U.S. mileage of natural gas transmission 

pipelines...owned and operated by an onshore natural gas transmission pipeline owner and 

operator”3

 The EPA further defines “onshore natural gas transmission pipeline owner and 

operator” for interstate pipelines as “the person identified as the transmission pipeline owner or 

operator on the Certificate of Public Convenience and Necessity issued under 15 U.S.C. 717(f)”4

For pipeline companies that operate under a parent company, the certificate may identify the 

operating company as the owner or operator. INGAA supports the reporting structure based on 

the proposed definitions. With this structure, each operating company under a common parent 

would submit a separate Subpart W report for transmission pipeline blowdowns. INGAA 

believes that the EPA should retain this structure in the Final Rule. 

INGAA points out that the EPA’s preamble that may cause confusion. In the preamble, the 

EPA states, “[i]f an entity owned and operated multiple pipelines in the U.S., the facility would 

be considered the aggregate of those pipelines, even if they are not interconnected.”5

 This 

statement could be interpreted as requiring operators to submit one consolidated figure for the 

corporate parent company. INGAA does not support this aggregated approach. The Final Rule 
108 

should retain the structure that is in the proposed rule text, in which the reporting entity 

for a pipeline facility is the operating company listed on the FERC certificate.

This approach is consistent with the method that interstate pipeline operators use to report GHG 

emissions from compressor stations. That is, compressor station emissions are reported by the 

specific operating company – not the corporate parent company. 

Footnotes: 

3

 See 79 Fed. Reg. 73148 at 73188. 

4

 Id. 

5

 Id. at 73156. 

Response 2: The EPA thanks the commenters for their support of the reporting approach for 

Onshore natural gas transmission pipeline owners and operators. The definitions of “facility with 

respect to the onshore natural gas transmission pipeline segment” and “onshore natural gas 

transmission pipeline owner or operator” are finalized as proposed, with clarifications as 

described in Section II.C.2 of the preamble to the final rule. 

The EPA also notes that the use of the term “entity” in the preamble, as identified by Commenter 

0140, was not intended to suggest that one report would be submitted for multiple facilities. The 

statement was included to clarify that if an owner or operator has pipelines in different areas of 

the country, they are part of one facility even if they are not interconnected. Where similar 

language appears in the preamble to the final rule, it has been revised to reflect this intent. 
109 

Commenter Name: Thure Cannon 

Commenter Affiliation: Texas Pipeline Association (TPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0130 

Page(s): 11-12 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 5 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 9-10 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 12-14 

Comment 3: Commenter 0130: EPA should clearly include a de minimis level for blowdown 

emissions reporting. 

TPA believes that the rules should clearly provide a de minimis level below which reporting of 

blowdown emissions would not be required. The proposed rules could be read as requiring 

reporting for any amount of carbon dioxide or methane emissions from each blowdown event 

along a pipeline: “In addition to the total annual emissions of methane and CO2, natural gas 

transmission pipeline reporters would also report the methane and CO2 emissions and location of 

each blowdown event.”22 Requiring emissions from each and every blow down event, no matter 

now inconsequential, to be reported in this way would impose a substantial burden on the 

pipeline industry with little or no corresponding benefit to EPA. It could be that EPA intends for 

the 50 cubic feet exemption contained in 40 CFR 98.233(i) to apply to blowdowns along 

transmission lines, but the preamble’s discussion of this exemption is limited only to the 

gathering and boosting context. See 79 Fed. Reg. 73154 (Dec. 9. 2014). EPA should consider a 

more user-friendly exemption in any event. Many of the facilities at which blowdowns occur are 

remote or unmanned. To determine whether the 50 cubic feet exemption in 40 CFR 98.233(i) 

even applies, the operator must send personnel out to calculate the length and diameter of the 

pipe for the entire flow scheme of the pipeline segment at which the blowdown occurred; this 

must be done for every individual blowdown event. We urge EPA to revise this proposal so as to 

make clear that there is a de minimis emissions level below which reporting of transmission 

pipeline blowdowns would not be required. 

Footnotes: 

22 79 Fed. Reg. 73157 (Dec. 9, 2014). 

Commenter 0133: We appreciate the inclusion of the current exemption that excludes reporting 

if the physical volume of the equipment blown down is less than 50 cubic feet. Additionally, we 
110 

request that EPA include a specific reference to metering and regulating stations and distribution 

piping as exempt equipment. These areas fall within a de minimis category regarding gas 

volumes. In addition, there are often different owners/operators for these assets, complicating the 

tracking and reporting process. 

Commenter 0140: EPA should consider certain exclusions for transmission pipeline blowdowns. 

INGAA believes that the EPA should consider a de minimis exclusion for transmission pipeline 

blowdowns. Section 98.233(i) includes exclusions and de minimis thresholds for reporting 

blowdowns. Those criteria, however, were developed for other source categories such as 

compressor stations. It does not appear that the EPA considered pipeline blowdown 

characteristics or the relevance and applicability of the existing criteria in the Proposed Rule. 

Blowdowns from large diameter high-pressure pipe should be the focus of the “transmission 

pipeline” source category. Smaller ancillary equipment located along pipelines should be 

excluded. Section 98.233(i) exempts blowdowns from equipment with a physical volume less 

than 50 ft3. For transmission pipeline blowdowns, equipment with marginally higher volume 

may be blown down, but tracking those emissions may not be warranted because the emissions 

are trivial when compared to more substantive events. For example, the physical volume of a 

metering run blown down for maintenance could exceed 50 ft3, but those emissions would not be 

a significant contributor to total annual pipeline blowdowns. INGAA believes that the proposed 

100 ft3 reporting threshold for transmission pipeline blowdowns is not adequate. This threshold 

would likely cover filter/separators at meter stations, pipeline heaters, meter station heaters, 

regulator and control valve runs and crossover headers but miss other ancillary facilities that 

exceed that physical limitation. 

Pipeline operators use numerous ancillary facilities along their interstate pipelines. Ancillary 

facilities include metering and/or regulating stations, pipeline interconnects, and pig launchers 

and receivers, etc. The size of these ancillary facilities varies greatly. For example, metering 

facilities are sized based on the number of interconnects (single or multiple pipeline connections) 

and the volumes of gas being received or delivered. Therefore, it is not feasible to establish a 

specific de minimis volume threshold. However, emissions from maintenance activities at any of 

these individual ancillary facilities would be considerably less than the 25,000 ton CO2e 

threshold established for compressor stations. 

INGAA recommends exclusions for ancillary equipment to reduce the reporting burden. This 

recommended exclusion does no harm to the purpose of the rule since the rulemaking focuses on 

mainline pipeline blowdowns. This is similar to current exclusions in section 98.233(i) for 

blowdowns for over-pressure relief, operating pressure control, desiccant dehydrators, etc. For 

transmission pipelines, INGAA recommends excluding blowdown reporting for ancillary 

pipeline equipment including metering and/or regulating stations, pipeline interconnects, valve 

assemblies or valve body cavities, and pig launchers and receivers. If a blowdown of a 

transmission pipeline section occurred at one of these ancillary facilities, the blowdown volume 

and purpose would still be reported under the operating company’s pipeline blowdown totals in 

accordance with Section 98.232(m). 
111 

Commenter 0142: EPA provides a definition of “blowdown” in the preamble and defines 

“blowdown” as “the release of gas from transmission pipelines for the purpose of reducing 

system pressure or complete depressurization.” See 79 Fed. Reg. at 73,156. Kinder Morgan 

believes this definition is quite vague and could have unintended consequences. 

Kinder Morgan further contends that it is important that reported blowdowns be limited to 

blowdowns of the pipeline. Pipeline operators operate numerous ancillary equipment along their 

interstate and intrastate pipelines. Ancillary equipment includes metering and/or regulating 

stations, pipeline interconnects, and pig launchers and receivers, etc. At times, operators may 

need to blow down these ancillary equipment without also blowing down any of the pipeline 

(e.g., during maintenance on the ancillary equipment). Such minor releases from these ancillary 

equipment should not be included in the definition of blowdown as they do not include any 

blowdown of the pipeline, and the small volumes vary based on the pressure at the time and the 

portion of ancillary equipment being blown down. 

Thus, for transmission pipelines, Kinder Morgan recommends excluding blowdown reporting for 

ancillary pipeline equipment including metering and/or regulating stations, pipeline 

interconnects, remotely operated valves, and pig launchers and receivers that does not result in 

any blow down of the transmission pipeline. This approach is consistent with the intent of EPA’s 

Proposed GHG Reporting Rule regarding blowdowns, which focuses on mainline pipeline 

blowdowns. This approach is also similar to current existing exclusions in section 98.233(i) for 

blowdowns resulting from over-pressure relief, operating pressure control, desiccant dehydrators, 

etc. See 40 C.F.R. 98.233(i).5 Additionally, exempting ancillary equipment would avoid a 

significant unnecessary burden from tracking emissions from normal operation and maintenance 

from the ancillary equipment. Importantly, any blowdown of a transmission pipeline segment 

that potentially would occur at these ancillary equipment (e.g., metering and/or regulating 

stations, pipeline interconnects, and pig launchers and receivers) would be reported in 

accordance with the provisions of this proposed rule (40 C.F.R. Part 98.232(m)). 

As an alternative to the above-described exemption, Kinder Morgan would support a specific de 

minimis volume threshold of 3,000 mcf, as a reporting threshold for these ancillary facilities. 

This threshold is consistent with PHMSA’s de minimis volume threshold for reporting under 49 

C.F.R. 191.5 and would allow operators to more effectively manage multiple regulatory regimes. 

New Proposed Language to 40 C.F.R. 98.238: Blowdown means the release of 

gas to the atmosphere from transmission pipelines for the purpose of reducing 

system pressure or complete depressurization. Blowdown does not include 

blowdowns of ancillary pipeline equipment, including metering and/or regulating 

stations, pipeline interconnects, and pig launchers and receivers that do not also 

result in any blowdown of the pipeline. 

Alternative Proposed Language to 40 C.F.R. 98.238: Blowdown means the 

release of gas to the atmosphere from transmission pipelines for the purpose of 

reducing system pressure or complete depressurization. Blowdown does not 

include any blowdown of ancillary pipeline equipment, including metering and/or 
112 

regulating stations, pipeline interconnects, and pig launchers and receivers in an 

amount less than 3000 mcf. 

Footnotes: 

5

 The 50-cubic-foot physical volume thresholds established in 40 C.F.R. 98.233(i) are not 

appropriate to apply to blowdowns along a pipeline or through pipeline ancillary equipment. 

Rather, a threshold related to the natural gas volume released to the atmosphere reflects the 

intentions of the GHG reporting rule and creates consistencies with existing reporting 

requirements. 

Response 3: The EPA is finalizing the reporting threshold of 50 ft3

 of physical volume for 

blowdowns in the Onshore Natural Gas Transmission Pipeline segment as proposed. In addition, 

the final rule clarifies that facilities in the Onshore Natural Gas Transmission Pipeline segment 

report pipeline blowdown emissions from blowdown vent stacks. See Section II.C of the 

preamble for additional information. 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 13-14 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 13 

Comment 4: Commenter 0140: The EPA should clarify the name of the emissions source for 

blowdown events 

Subpart W refers to “blowdown vent stack” emissions. Depending on the type of event, 

blowdown emissions may not be released to the atmosphere via a stack. In comparison, the 

definition of “blowdown” and “blowdown vent stack” in the general definitions section of 

Subpart A14 implies that blowdown emissions other than those emitted through a stack are 

included. Thus, this emission source should be called “blowdowns” or “blowdown venting.” 

INGAA recommends revising the name of this emissions source, which would require revising 

the title to section 98.233(i) and references to this emissions source in section 98.232. 

Footnotes: 

14 40 C.F.R. 98.6 (2015). 

Commenter 0142: Kinder Morgan recommends that EPA define “blowdown” in the rule itself in 

the manner recommended below. Upon defining the term “blowdown,” EPA should use the term 

“blowdown,” as opposed to “blowdown vent stacks,” with regard to requirements related to the 
113 

transmission pipeline segment as not all blowdowns from pipelines will occur through vent 

stacks. Use of the term blowdown vent stacks in reference to the transmission pipeline creates 

confusion and does not accurately reflect the operational realities. 

Response 4: As Commenter 0140 noted, the terms “blowdown” and “blowdown vent stack” are 

defined in subpart A; 40 CFR 98.6 states that “Blowdown vent stack emissions mean natural gas 

and/or CO2 released due to maintenance and/or blowdown operations including compressor 

blowdown and emergency shut-down (ESD) system testing.” Because this term is not defined in 

subpart W, the definition in subpart A applies to subpart W. 

The EPA disagrees that any clarifications to this definition are necessary for subpart W. While 

the chosen term may imply the presence of a physical stack, the definition does not specify that 

the emissions be released through a physical stack; it only states that the emissions include those 

released due to maintenance and/or blowdown operations. Therefore, the EPA is not amending 

this definition relative to onshore natural gas transmission pipeline blowdowns between 

compressor stations. 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 6-7 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 14 

Comment 5: Commenter 0140: Pipeline blowdown reporting for transmission compression 

segment and transmission pipeline segment 

The EPA should distinguish between the reporting obligations for pipeline blowdowns that occur 

within the boundary of a compressor station versus blowdowns that occur outside the station 

boundary. 

INGAA recommends that the EPA retain the reporting approach currently applicable to 

transmission compressor stations but add clarifying amendments to the reporting obligations for 

transmission pipeline blowdowns. For transmission compressor stations, blowdown event 

categories are identified in section 98.233(i)(2) and include “pipeline venting” for lines outside 

the compressor station if the venting occurs within the facility boundary. 

Regarding sections in Subpart W that address categorizing of Blowdowns as “facility” or 

“pipeline” emissions, some text is provided: 
114 

To categorize blowdown emissions originating from the pipeline with the 

“transmission pipeline segment” rather than the “transmission compression” 

segment, the Proposed Rule require revisions: 

 In section 98.233(i)(2), the list of categories for reporting blowdowns should 

eliminate “pipeline venting” from the types of events that apply to transmission 

compressor stations. Comment 5 provides additional INGAA recommendations on 

the event categories that should be used for tracking pipeline segment blowdowns. 

 Similar conforming revisions may be required to clearly indicate reporting obligations 

in sections 98.236(i)(1) and (i)(3). 

Further, INGAA believes that this facility definition might need to be adjusted under the existing 

Subpart W regulation in section 98.236(i) and section 98.236(i)(3) for clarity. 

Commenter 0140: INGAA supports reporting pipeline blowdown emissions released within the 

boundary of a compressor station to be incorporated within transmission pipeline segment. 

Response 5: The EPA understands the commenters’ concerns about separating transmission 

pipeline segments from compressor stations. However, compressor stations are already reporting 

facilities in the Onshore Natural Gas Transmission Compression segment as defined in 40 CFR 

98.230. As stated in the preamble to the proposed rule, the intent of the Onshore Natural Gas 

Transmission Pipeline segment is to capture emissions from blowdowns between compressor 

stations, and the EPA decided not to make any changes to the existing segments to provide 

consistency for reporters in those segments. This decision allows the EPA to ensure that the data 

gap in subpart W related to transmission pipeline blowdowns is addressed while minimizing 

confusion over changes to other segments. In addition, consistent segment descriptions will 

allow the EPA to track emissions trends over time to inform future policy decisions. Therefore, 

the EPA is not changing the reporting requirements for the Onshore Natural Gas Transmission 

Compression segment. 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 6 

Comment 6: EPA should distinguish between its definition for the “transmission pipeline” 

source category included in the Proposed Rule and the existing definitions for “transmission 

compressor station” and “underground storage facility” source categories. 

In the Proposed Rule, the EPA adds natural gas transmission pipelines as a new source category 

in 40 C.F.R. 98.230(a)(10). The EPA also adds related definitions in section 98.238. The agency 

already has definitions in the existing rule for transmission compressor station and underground 

storage facilities. While it appears that the EPA intends to create clear lines of demarcation for 

the three source categories, the EPA should include additional details in the proposed definitions 

to avoid confusion. 
115 

Facility definition

Subpart W “transmission pipeline” sources are interspersed with compressor stations and storage 

facilities along an interstate natural gas transmission pipeline. This characteristic is unique to the 

Subpart W source categories. For example, a pipeline “facility” stops at the inlet to a compressor 

station and re-starts at the outlet of the facility. To improve clarity, INGAA recommends a 

revision to the proposed definition of “facility” for the natural gas transmission pipeline 

segments, as follows: 

“Facility with respect to the onshore natural gas transmission pipeline segment

means the total U.S. mileage of natural gas transmission pipelines, as defined in 

this section, owned and operated by an onshore natural gas transmission pipeline 

owner or operator as defined in this section. This facility excludes the following 

related natural gas transmission and storage sector operations in other 

Subpart W source categories: the onshore natural gas transmission 

compression source category identified in section 98.230(a)(4), the 

underground natural gas storage source category identified in section 

98.230(a)(5), and the LNG storage segment identified in section 98.230(a)(6).” 

Response 6: The final definition of “facility with respect to the onshore natural gas transmission 

pipeline segment” includes the following statement: “The facility does not include pipelines that 

are part of any other industry segment defined in this subpart.” This statement addresses the 

commenter’s request to clarify that there should be no overlap between segments but is more 

consistent with other facility definitions within subpart W. 
116 

4.2 Data Reporting Requirements 

Commenter Name: Public Hearing: Thomas Bach 

Commenter Affiliation: Public Hearing: Kinder Morgan, Representing Interstate Natural Gas 

Association of America 

Comment Number: EPA-HQ-OAR-2014-0831-0055-A 

Page(s): 12-13 

Commenter Name: Thure Cannon 

Commenter Affiliation: Texas Pipeline Association (TPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0130 

Page(s): 10-11 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 6 

Commenter Name: Kelly L. Guertin 

Commenter Affiliation: DTE Energy 

Comment Number: EPA-HQ-OAR-2014-0831-0135 

Page(s): 2 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 11 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 15-16 

Comment 1: Commenter 0055-A: Pipeline blowdown spatial data. EPA proposes that pipeline 

blowdown data will be reported by the specific latitude and longitude where the blowdown 

occurs. 

However, operators currently do not compile pipeline blowdown data by latitude and longitude. 

Therefore, company management systems will need to be revised to address these new reporting 

requirements. There are significant implementation and timing costs associated with those 

efforts. 

In addition, EPA has not explained what the air quality benefit would derive nor why it said 

reporting at this level of detail is needed. 

INGAA recommends that pipeline blowdown data be reported by the pipeline operator, that is, 

the specific operating company, as EPA currently proposes, but that it be done on a national or 
117 

state aggregate basis. Reporting at the national or state aggregate basis would reduce 

implementation time and costs. 

Commenter 0130: EPA proposes to add reporting requirements for carbon dioxide and methane 

emissions from natural gas transmission pipeline blowdowns between compressor stations in a 

new Onshore Natural Gas Transmission Pipeline industry segment.20 Among the information that 

EPA seeks in the proposed rules is the precise location of each blowdown event along the 

pipeline system. Specifically, EPA would require reporters to provide “[t]he location of the 

blowdown, in latitude and longitude in decimal degree format...”21 This is information that 

pipeline operators have not traditionally maintained, and to comply with this requirement would 

necessitate a significant amount of expense, effort, and time in order to precisely locate the 

latitude and longitude of each and every blow down event along a pipeline system. As EPA 

acknowledges, there were over 300,000 miles of transmission pipelines in the United States as of 

2012, a fact which underscores the significant amount of work and time that will be required to 

pin down the precise geographic location of all blowdown events along domestic transmission 

pipelines. 

TPA questions the need for, and potential benefit of, the proposed longitude / latitude 

requirement for blowdown locations. We do not believe that EPA policy or data quality will be 

significantly enhanced by requiring reporters to pinpoint blowdown locations in the precise 

manner that EPA is proposing. EPA has certainly not provided a justification for its proposed 

request. Accordingly, we urge EPA to remove this requirement from the proposed rules, as it 

would create a substantial new burden on reporters without any ascertainable regulatory or 

environmental benefit. 

Footnotes: 

20 See 40 CFR 98.232(m) (proposed). 

21 See 40 CFR 98.236(i)(3)(iii) (proposed). 

Commenter 0133: The proposed rules require inclusion of location data for each blowdown: The 

location of the blowdown, in latitude and longitude in decimal degree format provided as a 

comma-delimited ‘“latitude, longitude’” coordinate pair reported in decimal degrees to at least 

four digits to the right of the decimal point. We believe that this does not provide meaningful 

value to EPA or the public and is also extraneous to EPA’s objective of filling data gaps in the 

national inventory. Therefore, we request that EPA remove the location-related reporting 

requirements. 

Commenter 0135: DTE Energy requests the EPA to consider whether information such as 

latitude and longitude of a single blowdown event is necessary and in compliance with the 

Paperwork Reduction Act requirements. 

Commenter 0140: INGAA requests that EPA eliminate its proposal to require pipelines to report 

longitude and latitude data of each location where a blowdown has occurred since the data is 

burdensome and will not produce air quality benefits. 
118 

INGAA argues that EPA’s request to collect the longitude and latitude data of each location 

where a blowdown has occurred is burdensome without producing data that has a “practical 

utility.”10 This data is not currently collected for each location along the pipeline. The EPA has 

not demonstrated how this additional location data will produce valuable information on the 

transmission sector’s greenhouse gas inventory levels. The need for such localized data is 

unclear because greenhouse gas emissions and methane emissions are a global issue. Interstate 

pipelines have not geospatially located all potential blowdown locations along the pipeline 

system and would need to survey and develop databases of these locations. This regulatory 

reporting burden is compounded by the compilation of the annual volumes released per pipeline 

blowdown category for each location where a blowdowns occurs. 

Footnotes: 

10 Id. 

Commenter 0142: Kinder Morgan strongly opposes EPA’s proposal to require reporting 

emissions of each individual pipeline blowdown and the specific location of each blowdown 

event. Kinder Morgan proposes changes to eliminate the requirements to report specific location 

and has made revisions to the proposed language below. Kinder Morgan notes that striking 40 

C.F.R. 98.236(i)(3)(i) and (ii) does not alter the requirement to report annual emissions as 

described in 40 C.F.R. 98.236(i). 

EPA Proposed 40 C.F.R. 98.236(I): (i) Blowdown vent stacks. You must indicate 

whether your facility has blowdown vent stacks. If your facility has blowdown 

vent stacks, then you must report whether emissions were calculated by 

equipment or event type or by using flow meters or a combination of both. If you 

calculated emissions by equipment or event type for any blowdown vent stacks, 

then you must report the information specified in paragraph (i)(1) of this section 

considering, in aggregate, all blowdown vent stacks for which emissions were 

calculated by equipment or event type. If you calculated emissions using flow 

meters for any blowdown vent stacks, then you must report the information 

specified in paragraph (i)(2) of this section considering, in aggregate, all 

blowdown vent stacks for which emissions were calculated using flow meters. For 

the onshore natural gas transmission pipeline segment, you must also report the 

information in paragraph (i)(3) of this section. 

... 

(3) Onshore natural gas transmission pipeline segment. Report the information in 

paragraphs (i)(3)(i) to (i)(3)(iii) for each separate transmission pipeline blowdown 

event. 

(i) Annual CO2 emissions in metric tons CO2. 

(ii) Annual CH4 emissions in metric tons CH4. 
119 

(iii) The location of the blowdown, in latitude and longitude in 

decimal degree format provided as a comma-delimited “latitude, 

longitude” coordinate pair reported in decimal degrees to at least 

four digits to the right of the decimal point. 

Reporting the specific emissions and the location of each blowdown event results in precisely the 

higher reporting burden that EPA seeks to avoid by allowing operators to report total emissions 

on a national basis. Furthermore, because the emissions reported are GHG emissions related to 

global climate change, reporting of blowdown events at a local level does not improve the 

quality of data or provide relevant information regarding ambient air quality levels at the location 

of the blowdown event. If EPA does not finalize the preferred national approach regarding 

blowdown emission reporting, Kinder Morgan would support as an alternative, reporting 

blowdown emissions on a state basis by each owner or operator. 

Response 1: The EPA is not finalizing the requirement to report the emissions or latitude and 

longitude for each individual blowdown. Instead, reporters will aggregate blowdown emissions 

by state and report the number of blowdowns per state. See Section II.C of the preamble to the 

final rule for additional discussion responding to this comment. 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 6-7 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 10-11 

Comment 2: Commenter 0133: Additional Reporting Related to the Transmission Pipeline 

Facility 

In section 98.236(aa)(11) of the proposal, EPA identifies related “facility” reporting 

requirements for pipelines and includes segregation of natural gas volumes into different 

categories as follows: 

“11) For onshore natural gas transmission pipeline facilities, report...

(i) The quantity of natural gas received at all custody transfer stations in the 

calendar year, in thousand standard cubic feet. This value may include meter 

corrections, but only for the calendar year covered by the annual report. 

(ii) The quantity of natural gas withdrawn from in-system storage in the calendar 

year, in thousand standard cubic feet. 
120 

(iii) The quantity of natural gas added to in-system storage in the calendar year, 

in thousand standard cubic feet.

(iv) The quantity of natural gas transferred to third parties such as LDCs or other 

transmission pipelines, in thousand standard cubic feet. 

(v) The quantity of natural gas consumed by the transmission pipeline facility for 

operational purposes, in thousand standard cubic feet. 

(vi) The miles of transmission pipeline in the facility.”

The purpose of these additional facility reporting requirements is not clearly explained or 

justified in the proposal; however, we believe our company provides this same information 

annually to FERC on pages 512, 514, and 520, of FERC Form 2. On the FERC form, we report 

our gas in units of dekatherms (Dth), whereas the proposed rule would require thousand standard 

cubic feet (mscf or mcf) as the reporting unit. When reporting to EPA under the proposed rule, 

we would assume one Dth is equivalent to one thousand cubic feet (mcf) of natural gas, based on 

an approximate heat value of 1,000 British thermal units (Btu) per cubic foot, and would 

therefore make a one to one conversion. 

Commenter 0140: INGAA opposes EPA’s proposal to require pipelines to report data pursuant 

to section 98.236(aa)(11) since the data is irrelevant to assisting EPA in identifying pipeline 

blowdowns. 

In Section 98.236(aa)(11), EPA proposes that pipelines report the following data: 

For onshore natural gas transmission pipeline facilities, report the quantities specified in 

paragraphs (aa)(11)(i) through (aa)(11)(vi) of this section. 

(i) The quantity of natural gas received at all custody transfer stations in the 

calendar year, in thousand standard cubic feet. This value may include meter 

corrections, but only for the calendar year covered by the annual report. 

(ii) The quantity of natural gas withdrawn from in-system storage in the calendar 

year, in thousand standard cubic feet. 

(iii) The quantity of natural gas added to in-system storage in the calendar year, in 

thousand standard cubic feet. 

(iv) The quantity of natural gas transferred to third parties such as LDCs or other 

transmission pipelines, in thousand standard cubic feet. 

(v) The quantity of natural gas consumed by the transmission pipeline facility for 

operational purposes, in thousand standard cubic feet. 

(vi) The miles of transmission pipeline in the facility.6
121 

While INGAA’s members are committed to addressing the data gap for pipeline blowdowns, the 

reporting requirements must provide valuable information. INGAA asserts that data requests 

listed in Section 98.236(aa)(11) are irrelevant to determining pipeline blowdown volumes. A 

data user cannot calculate pipeline blowdown volumes by comparing pipeline injections versus 

withdrawals. 

Nonetheless, pipelines already report publicly the proposed section 98.236(aa)(11) data in Form 

EIA-176 and/or FERC Form 2 (albeit in dekatherms and not Mcf). Interstate pipelines also report 

the number of transmission pipeline miles to both PHMSA as part of that agency’s annual 

reports (PHMSA Form 7100-2) and FERC (as part of FERC Form 2). Requiring pipelines to 

report this information to EPA would be duplicative and therefore the proposal should be 

eliminated. 

Moreover, the Paperwork Reduction Act (PRA) is intended to reduce the information burden 

imposed by the federal government.7 The stated purpose of the PRA is “to have Federal agencies 

become more responsible and publicly accountable for reducing the burden of Federal paperwork 

on the public...”8

As the EPA is aware, in order to obtain Office of Management and Budget (OMB) approval of 

an information collection, an agency must demonstrate that it has “taken every reasonable step” 

to ensure that the proposed collection: 

(i) is the least burdensome necessary for the proper performance of the agency’s 

functions to comply with the legal requirements and achieve program objectives; 

(ii) is not duplicative of information otherwise accessible to the agency; and 

(iii) has a practical utility.9

Therefore, INGAA requests that EPA eliminate the proposed Section 98.236(aa)(11) reporting 

requirement since the data is duplicative and lacks a practical utility. 

Footnotes: 

6

 40 C.F.R. 98.236(aa)(11). 

7 See 44 U.S.C. section 3501 (1995). 

8 Id. 

9

 5 C.F.R. 1320.5(d) (2013). 

Response 2: These reporting elements are finalized as proposed. See Section II.C.2 of the 

preamble to the final rule for additional discussion responding to this comment. 
122 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 2 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 9-11 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 14 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 17 

Comment 3: Commenter 0139: Our comments respectfully offer several specific 

recommendations to further strengthen the proposed rule: 

 Require leak reporting from transmission pipelines and coordinate with data reported to 

the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the Energy 

Information Administration (“EIA”), and the Federal Energy Regulatory Commission 

(“FERC”) 

Commenter 0139: Transmission pipeline leak reporting. We support the agency’s proposal to 

strengthen reporting standards in the transmission segment and urge EPA to require monitoring 

and reporting of leaks in this segment as well. As EPA notes in the proposed rule, the agency 

previously considered provisions addressing fugitive emissions from transmission pipelines in its 

2010 Subpart W rulemaking.45 In that rulemaking, EPA ultimately chose not to finalize pipeline 

leak provisions because of (1) the dispersed nature of fugitive emissions from transmission 

pipelines, and (2) its assumption that once fugitives are found, leaks are usually quickly 

addressed for safety reasons.46 In the proposed rule, EPA further notes that owners and operators 

must report larger fugitive leaks to PHMSA.47 EPA also explains that additional data, such as the 

total miles of pipeline included in a facility and the quantity of gas received at custody transfer 

stations, to EIA or FERC, suggesting there is no need for EPA to require separate reporting.48

On the contrary, it is critical that EPA incorporate leak reporting obligations into the Subpart W 

rules for the transmission segment for several reasons. First, the size and recent growth of 

transmission pipeline infrastructure alone underscore the need for robust reporting standards 

under Subpart W. The 2014 Greenhouse Gas Inventory estimates that there were over 300,000 
123 

miles of transmission pipeline in the U.S. in 2012.49 This segment has also experienced growth 

as a result of increased shale gas production, with approximately 2,000 miles of new natural gas 

pipeline added between 2010 and 2012.50 Accidental leaks at these facilities can be a significant 

source of methane emissions, and those at remote locations may not be noticed or repaired 

immediately. Indeed, a PHMSA-commissioned study found that the volume of natural gas 

released from large leaks and ruptures in transmission lines is approximately 1.3 billion standard 

cubic feet annually, over ten times greater than the estimated transmission pipeline leaks in the 

Greenhouse Gas Inventory.51 The scale of this emissions source is therefore substantial, and we 

urge EPA to adopt direct leak inspection and reporting requirements under Subpart W. 

We also note that the Greenhouse Gas Inventory uses an emission factor of 1.55 scfd/mile for 

pipeline leaks in the transmission segment.52 This emission factor for transmission pipeline leaks 

is based on measurements of distribution main leaks in the EPA/GRI (1996) study and is 

adjusted based on specific characteristics of transmission pipelines. We urge EPA to update this 

emission factor based on direct measurements of transmission pipeline leaks. 

The reporting required under other federal programs does not provide comprehensive data on 

transmission pipeline leaks. PHMSA requires incident reporting of accidental leaks resulting in 

the release of 3 million cubic feet or more of natural gas – leaks large enough to pose safety 

risks.53 PHMSA’s obligations therefore extend to only a subset of total leaks from transmission 

pipelines, and do not provide comprehensive and accurate information on total fugitive 

emissions from transmission pipelines. 

Moreover, Subpart W currently requires reporting of leaks from distribution mains, and the 

proposed rule includes requirements for leak reporting from gathering lines, even though these 

facilities are also subject to PHMSA’s incident reporting requirements concurrent with that 

agency’s jurisdiction.54 EIA and FERC reporting obligations do not cover fugitive emissions and 

do not address the reporting gap in the proposed rule. EPA reporting requirements could 

therefore play a distinct role and we encourage EPA to coordinate with the relevant federal 

agencies to ensure that data collection from these sources is efficient, accurate, and 

comprehensive. 

For these reasons, it is critical that EPA establish mandatory reporting requirements under 

Subpart W for fugitive emissions at transmission pipelines. We respectfully recommend that 

EPA include these obligations in its final rule and that it coordinate with PHMSA regarding 

incident reporting, as well as with EIA and FERC where appropriate, to ensure that these data 

can be effectively cross-referenced and analyzed. 

Footnotes: 

45 79 Fed. Reg. at 73,157. 

46 Id. 

47 Id. 
124 

48 Proposal TSD, supra note 7, at 30-31. 

49 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012, at Annex 3 tbl. A129. 

50 GAO Report, supra note 11, at 28. 

51 See D. Shaw et al., Final Report: Leak Detection Study – DTPH-11-D-000001, at 3-27, 

PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (2012), 

available at http://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=430 (annualizing the emissions 

rate for the 30 months of PHMSA incident reporting). 

52 Inventory of U.S. Greenhouse Gas Emissions and Sinks, supra note 10, Annex 3 tbl. A-129. 

53 49 C.F.R. 191.3, 191.15(a). 

54 Id. sections 191.9, 191.15. 

Commenter 0140: INGAA supports the EPA’s decision to exclude pipeline leak reporting. In the 

preamble,17 EPA stated that it is not proposing to add pipeline leaks because PHMSA already 

requires reporting of leaks. INGAA agrees with this explanation and supports the EPA’s 

decision.

Footnote: 

17 See 79 Fed. Reg. 73148 at 73157. 

Commenter 0142: EPA proposes not to require reporting of fugitive leaks between compressor 

stations “due to the dispersed nature of the fugitive emissions, and the fact that, once fugitives 

are found, the leaks causing the emissions are usually addressed quickly for safety reasons.” See 

79 Fed. Reg. at 73,157; see also 75 Fed. Reg. 18,616 (April 12, 2010). Kinder Morgan supports 

EPA’s position not to require reporting of fugitive leaks along the gathering lines. 

Response 3: The EPA is not finalizing a requirement to report fugitive emissions from 

transmission pipeline leaks. See Section II.C of the preamble to the final rule for additional 

discussion responding to this comment. 
125 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 9 

Comment 4: We respectfully ask that the agency also require owners and operators to include 

within national-level reports the total mileage of transmission pipeline in each state. Reporting of 

state-by-state information would maximize the granularity and usability of reported data and 

would comport with the state-specific information owners and operators are already reporting to 

the EIA. 

Response 4: The EPA is requiring reporters to aggregate blowdown emissions by state and 

report the number of blowdowns and mileage of pipeline per state in the final rule. See Section 

II.C of the preamble to the final rule for more information. 

4.3 Blowdown Reporting Categories 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 5-6 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 8-9 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 16 

Comment 1: Commenter 0133: Regarding blowdown categories, we recommend that EPA 

define event categories specific to pipeline blowdowns. The current seven categories in the rule 

are specific for compressor station blowdowns and do not provide meaningful information 

regarding pipeline blowdowns. We recommend revising 98.233(i)(2) to include the following 

categories for pipeline blowdowns, and retaining the existing categories for blowdowns that 

occur at compressor stations: 

1. Pipeline integrity work including, but not limited to, the preparation work of modifying 

facilities, assessments, maintenance or mitigation and traditional pipeline maintenance 

and post-maintenance commissioning 

2. Equipment replacement or repair 

3. Pipe abandonment 
126 

4. New construction, or modification of pipelines including commissioning and change of 

service 

5. Pipeline incidents as defined by PHMSA 

6. Operational precautions during activities (such as excavation near pipelines) 

7. Pipeline operations (including pigging for water removal, drop blowing, hydrate 

blockage, removing of stuck pigs) 

8. Other 

Commenter 0140: The EPA should develop pipeline blowdown categories, rather than relying on 

the seven event categories listed in section 98.233(i) that were developed for compressor station 

blowdowns. 

When the EPA added blowdown reporting for transmission pipelines in the Proposed Rule, it did 

not revise the estimation methods to reflect the activities that result in blowdowns along a 

pipeline. Consequently, the proposed rule would apply the methods developed for tracking 

compressor station blowdowns. The EPA should develop a separate list of categories for tracking 

and reporting pipeline blowdowns, because the activities that result in blowdowns along a 

pipeline differ from those that occur at compressor stations. The value of the data generated from 

pipeline blowdown reporting would significantly improve if the reporting categories correspond 

to the activities that occur along a pipeline. 

INGAA recommends the following list of event causes: 

1. Pipeline integrity work 

o the preparation work of modifying facilities 

o ongoing assessments 

o maintenance or mitigation 

2. Traditional operations or pipeline maintenance 

3. Equipment replacement or repair (e.g. valves) 

4. Pipe abandonment 

5. New construction or modification of pipelines including commissioning and change of 

service 

6. Pipeline incident (as defined by PHMSA) management and repair 

7. Operational precaution during activities (e.g. excavation near pipelines) 

8. Other. 

Recent amendments to the regulation for compressor station blowdown reporting were designed 

to improve the value of data collected. Similarly, tracking pipeline blowdowns by these 

categories would provide more valuable information than relying on the categories in the current 

rule. INGAA recommends revising section 98.233(i)(2) to include these categories for pipeline 

blowdowns, and retaining the existing categories for compressor station blowdowns. The 

associated reporting requirements, discussed further in Comment 7, would include annual 

blowdown volumes by category as well as the number of annual events. 

Commenter 0142: Kinder Morgan supports and incorporates by reference INGAA’s comments 

that suggest EPA develop pipeline blowdown categories (and require reporting by category), 
127 

rather than relying on the seven event categories listed in section 98.233(i) that were developed 

for compressor station blowdowns. The value of the data generated from pipeline blowdown 

reporting would significantly improve by identifying categories based on pipeline activities and 

not compressor station activities. Consistent with INGAA, Kinder Morgan recommends the 

following list of event causes: 

 Pipeline integrity work; 

 Maintenance, including post-maintenance commissioning; 

 Pipe replacement; 

 Equipment replacement or failure; 

 Pipe abandonment; 

 New construction, including commissioning; 

 Pipeline incidents; and 

 Other. 

Response 1: The final rule includes blowdown categories specific to blowdowns in the Onshore 

Natural Gas Transmission Pipeline segment. See Section II.C of the preamble to the final rule for 

more information. 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 14 

Comment 2: The EPA should revise or clarify the use of the term “distribution pipelines,” in 

section 98.233(i)(2). 

In the November 2014 Final Rule revising Subpart W,15 the EPA added a reference to 

“distribution” pipelines in the emissions estimation method section for blowdowns.16

The description of blowdown event types in section 98.233(i)(2) includes the following: 

“Equipment or event types must be grouped into the following seven categories: 

facility piping (i.e., piping within the facility boundary other than physical 

volumes associated with distribution pipelines), pipeline venting (i.e., physical 

volumes associated with distribution pipelines vented within the facility 

boundary)...” [Emphasis added] 

This reference was not included or explained in the proposed rule issued in March 2014. This 

new terminology is unclear and should be revised or clarified. A compressor station is usually 

associated with “transmission” pipelines, so reference to “distribution” pipelines is confusing. In 

addition, the distribution sector is a separate industry sector, and the “natural gas distribution” 

source category in Subpart W has different reporting requirements than the transmission sector. 

INGAA recommends deleting the parenthetical text from section 98.233(i)(2). If not, the EPA 

should explain its intent. 
128 

Footnotes: 

15 “Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems,” 79 Fed. Reg. 70352 (November 25, 2014). 

16 40 C.F.R. 98.233(i). 

Response 2: The final rule includes blowdown categories specific to blowdowns in the Onshore 

Natural Gas Transmission Pipeline segment, and 40 CFR 98.233(i)(2) specifies that the other 

blowdown categories do not apply to the Onshore Natural Gas Transmission Pipeline segment. 

Therefore, the reference to distribution pipelines does not apply to the Onshore Natural Gas 

Transmission Pipeline segment, and no further clarification is needed. 

4.4 Supportive Comments 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 14-15 

Comment 1: EPA proposes that the “Facility” for the new onshore natural gas transmission 

pipeline industry segment would be defined as the “total U.S. mileage of natural gas transmission 

pipelines owned or operated by an onshore natural gas transmission pipeline owner or operator.” 

See 79 Fed. Reg. at 73,156. Kinder Morgan agrees with EPA’s approach and specifically agrees 

with EPA’s rationale: 

After comparing the options, the EPA concluded that requiring reporters to file 

separate reports for each portion of the system in any one segment, state, or basin 

would impose higher evaluation and reporting burden on owners and operators 

without providing the EPA with additional useful emissions information and 

activity data. Defining the facility on the national level limits the burden on 

reporters to correlate the pipeline ownership transfer points with specific 

geographical segments. Instead, the reporters can track the required information 

for their various pipelines, regardless of location, and submit data associated with 

all of them in one report. 

See Technical Support Document, at 29. Given Kinder Morgan’s extensive gas pipeline network, 

Kinder Morgan supports EPA’s national approach with respect to the definition of “Facility” in 

the new Transmission and Pipeline segment. In addition, Kinder Morgan agrees with reporting 

emissions from the Transmission and Pipeline segment on a national basis per pipeline operator. 

Response 1: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed. 
129 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 9 

Comment 2: The proposed rule contains new reporting requirements for emissions from natural 

gas transmission pipeline blowdowns between compressor stations.42 EPA proposes defining the 

facility for the Onshore Natural Gas Transmission Pipeline segment as an owner or operator’s 

total mileage of natural gas transmission pipelines in the U.S.43

Commenters strongly support these proposed requirements along with EPA’s proposed facility 

definition. A national approach to reporting in this segment ensures the most robust emissions 

reporting and, accordingly, the most transparent data.44

Footnotes: 

42 79 Fed. Reg. at 73,156. 

43 Id. 

44 We also support EPA’s decision to create a new Onshore Natural Gas Transmission Pipeline 

segment rather than adding natural gas transmission lines between compressor stations to the 

existing Onshore Natural Gas Transmission Compressions segment. 

Response 2: The EPA thanks the commenter for their support. These revisions are finalized as 

proposed. 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 5 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 16-17 

Comment 3: Commenter 0133: The EPA proposes to allow two methods for calculating 

emissions from pipeline blowdowns. Although we currently do not utilize flow meters on our 

blowdown vent stacks, we appreciate the option to use this method in the future. 

Commenter 0142: EPA proposes that pipeline operators would use the methods in 40 C.F.R. 

98.233(i) to calculate or measure emissions from pipeline blowdowns. Section 98.233(i) 
130 

articulates two methods. The first method allows an operator to calculate emissions based on the 

volume of the pipeline segment between isolation valves that is blown down and the pressure 

and temperature of the gas within the pipelines. The second method allows the operator to 

measure the emissions on the blowdown and vent stack. Kinder Morgan supports EPA’s 

proposal to allow operators to use either of the above-two methods. Kinder Morgan favors 

emissions calculations versus flow meter measures primarily because operators do not always 

have a flow meter at the location where the blowdown occurs (e.g., when a third party strikes a 

pipeline causing the pipeline to blowdown at the strike location or other locations along the 

pipeline) and blowdown may occur as needed, particularly for safety purposes, rendering such a 

requirement impractical. 

Response 3: The EPA thanks the commenters for their support. These methods are finalized as 

proposed. 

 
131 

5.0 Well Identification Numbers 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 13-14 

Comment 1: Commenters support the agency’s proposal to add requirements for reporting well 

identification numbers from sources in the production segment.59 This requirement is well within 

EPA’s authority under section 114, which permits the agency to require, among other monitoring 

and reporting, that entities “provide such other information as the Administrator may reasonably 

require.”60

Reporting well identification numbers will significantly enhance the potential uses and analysis 

of emissions data by facilitating cross-referencing among production segment data and will help 

ensure the transparency of reported data. Collected data that includes well identification numbers 

will also allow policymakers to understand which facilities are reporting and how the reporting 

threshold may be adjusted to provide the most comprehensive emissions information.61

Moreover, these numbers are readily available to reporters and could be seamlessly integrated 

with existing reporting requirements. Accordingly, EPA’s proposal will add little burden to 

covered sources while permitting enhanced data analysis and transparency. 

Footnotes: 

59 See 79 Fed. Reg. at 73,157-58. 

60 42 U.S.C. section 7414(a)(1)(G). 

61 All of the undersigned organizations, along with other environmental groups, joined a 

comment letter to the 2009 Subpart W proposal that outlined the difficulties associated with the 

25,000 MT CO2e threshold and requested a lower threshold. Comments of Clean Air Task Force, 

Colorado Environmental Coalition, Environmental Defense Fund, Natural Resources Defense 

Council, Sierra Club, and Wilderness Workshop, Doc. EPA-HQ-OAR-2009- 0923-3545. 

Response 1: The EPA thanks the commenter for their support. The EPA is finalizing the well 

identification number reporting requirements for wells but not for other emission sources. See 

Section II.D of the preamble to the final rule for additional discussion responding to this 

comment. 
132 

Commenter Name: Public Hearing: Karin Ritter 

Commenter Affiliation: Public Hearing: American Petroleum Institute 

Comment Number: EPA-HQ-OAR-2014-0831-0055-B 

Page(s): 22-24 

Commenter Name: Gretchen C. Kern 

Commenter Affiliation: Pioneer Natural Resources USA, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0134 

Page(s): 5-6 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 2 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 18-20 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 21 

Commenter Name: C. William Giraud 

Commenter Affiliation: Concho Resources Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0141 

Page(s): 4 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 5 

Comment 2: Commenter 0055-B: The rule proposes to add requirements for reporting well 

identification numbers, which are claimed to improve data quality by enabling identification of 

wells associated with different sources. The EPA claims that these identification numbers are 

readily available and do not require any additional data gathering or calculation. 

API contends that this requirement is an overreach of EPA’s authority for the reporting program, 

and the information requested is extraneous and not needed to validate emissions data. The 

requirement is inconsistent with the aggregation of equipment and emissions within a basin or 

sub-basin, as currently required in the rule. With the requirement for complete mapping of all 

wells to all sources, the EPA seems to be attempting to construct a comprehensive accounting of 

wells and their ownership. Therefore, such a requirement will impose significant implementation 

burdens without contributing to improved emissions data. 
133 

API stresses that EPA’s estimate that this requirement will impose only a small additional burden 

of 10 hours per reporter per year to report the well ID numbers lacks any rational basis and is 

arbitrary. In addition, EPA ignores the burden associated with mapping and maintaining the well 

ID database that could change throughout the year due to the dynamics of well acquisition, 

divestment, and other changes to facilities operation and movement of transportable equipment 

based on operational needs. API also notes that EPA has other avenues at its disposal to acquire 

the well information data, such as commercial data systems like the DI-Desktop or the EIA’s 

information. 

API is requesting that EPA in the final rule abandon the requirement to provide a unique well 

identification number. This reporting requirement does not have any influence on the final 

emission calculations and only serves to detract from the resources needed to manage and report 

the emissions data. 

Commenter 0134: Requiring the reporting of well identification numbers could result in negative 

consequences for operators and the public, and this requirement should be stricken in the final 

rule 

Pioneer is concerned that EPA’s proposed requirement for operators to report well identification 

numbers associated with the reporting of emissions data could result in negative consequences 

for both operators and the public. Oil field wells and operations are far-flung assets and because 

they occur over hundreds of square miles, they are hard to completely secure. Identifying the 

sites associated with emissions reported under the onshore production segment of Subpart W by 

individual well identification numbers will create an opportunity for certain mischiefs that are 

not in the safety interests of the public. Therefore, Pioneer requests that the reporting of well 

identification numbers not be a requirement in the final rule.

Commenter 0137: Reporting the well ID number for all wells associated with each emission 

source is a significant expansion of burden without any impact on the accuracy of reported GHG 

emissions. This requirement is also in direct conflict with the previously established policy of 

aggregating emissions data at the basin and sub-basin level. API strongly opposes this 

requirement. 

Commenter 0137: At the outset, EPA lacks the legal authority to require facilities to report well 

ID numbers. In the proposed Subpart W revisions, EPA relies on Section 114 of the Clean Air 

Act as the source for its legal authority. EPA’s use of Section 114 historically has been 

appropriately limited to issuing Information Collection Requests (ICRs). ICRs are 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, does not provide legal 

authority for an economy-wide, ongoing reporting rule requiring all affected entities to submit 

data annually with new, onerous, and ever-changing monitoring and measurement processes. 

Thus, the broad, pervasive, and ongoing information collection obligations under the GHGRP 

exceed the limits of Section 114. 

In addition, EPA’s authority under Section 114 is directly limited by a reasonableness 

requirement. See 42 U.S.C. section 7414(a)(1)(G). Here that reasonableness standard is provided 
134 

by the 2008 Consolidated Appropriations Act, which authorized a one-time funding “for 

activities to develop and publish a draft rule not later than 9 months after the date of enactment 

of this Act, and a final rule not later than 18 months after the date of enactment of this Act, to 

require mandatory reporting of greenhouse gas emissions above appropriate thresholds in all 

sectors of the economy of the United States.” P.L. 110-161, 121 Stat. 1844, 21218 (2008). This 

Appropriations Act expressly limited EPA’s authority to promulgating a rule to require reporting 

of “greenhouse gas emissions.” The term “emissions” unambiguously means material that is 

actually discharged into the air. “If the intent of Congress is clear, that is the end of the matter; 

for the court, as well as an agency, must give effect to the unambiguously expressed intent of 

Congress.” Chevron U.S.A, Inc., v. NRDC, 467 U.S. 837, 842, 43 (1984). Therefore, EPA has 

no authority to require any more than GHG emissions to be reported. 

The proposal to require facilities to report well ID numbers exceeds this limitation and would 

unlawfully require facilities to report information that is unrelated to actual emissions of GHGs. 

By defining the relevant Onshore Petroleum and Natural Gas Production facility for reporting 

purposes at the basin level, see 40 C.F.R. 98.238, EPA has elected to aggregate emissions at a 

level that is necessarily broader than an individual well, making the identification of specific 

wells within a given basin irrelevant for purposes of calculating and reporting GHG emissions. 

Indeed, EPA’s proffered justifications for reporting well ID numbers do not suggest that GHG 

emissions data cannot be accurately measured and reported at the basin level without listing 

associated well ID numbers. Nor do they suggest that reporting well ID numbers would have a 

positive impact on current emissions inputs or data quality. Thus, because well ID numbers are 

not necessary for reporting GHG emissions, it is unreasonable and unlawful under Section 114 

for EPA to require that they be reported. 

Second, EPA has failed to provide a reasoned basis for reversing its former policy that wellspecific data was not necessary under Subpart W. When an agency promulgates regulations, it 

must “examine the relevant data and articulate a satisfactory explanation for its action including 

a rational connection between the facts found and the choices made.” Motor Vehicles Mfrs. 

Ass’n v. State Farm Mut. Auto. Inc. Co., 463 U.S. 29, 43 (1983) (quotation omitted). This 

standard applies equally when an agency seeks to revise or revoke entirely an existing regulation 

or policy. Jacarilla Apache Nation v. Dep’t of the Interior, 613 F.3d 1112, 1119 (D.C. Cir. 2010) 

(“One of the core tenets of reasoned decision-making announced in State Farm is that ‘an agency 

changing course...is obligated to supply a reasoned analysis for the change.’” (alteration in 

original) (citations omitted); Dillmon v. Nat’l Transp. Safety Bd., 588 F.3d 1085, 1089-90 (D.C. 

Cir. 2009); Indep. Petroleum Ass’n v. Babbit, 92 F.3d 1248, 1258 (D.C. Cir. 1996). Here, EPA 

has offered no reasoned basis for departing from its current basin-level approach to GHG 

reporting for the onshore production sector or from its commitment to work with industry to 

complete an accurate GHG inventory with a manageable reporting burden. 

When EPA first finalized reporting requirements for Onshore Petroleum and Natural Gas 

Production under Subpart W, it elected to require reporting at an aggregate basin-wide level. API 

supported EPA’s conclusion that GHG emission data should be aggregated across multiple well 

sites with similar characteristics. EPA justified this aggregated reporting approach as striking an 

appropriate balance between accuracy in emission data and burdens imposed on reporting 

entities. See Mandatory Greenhouse Gas Reporting Rule Subpart W – Petroleum and Natural 
135 

Gas: EPA’s Response to Public Comments (Nov. 2010) at 117 (“A basin level definition is the 

least complex of all facility definition options given the well defined facility definition and 

minimal impact on small and medium businesses.”); id. at 120 (“EPA has chosen the basin level 

definition with due consideration of the burden to report and necessary coverage to inform 

policy.”); id. at 123 (“EPA has chosen the most cost-effective but adequate monitoring methods 

such that the quality of data is sufficient to inform policy.”). Moreover, EPA considered, and 

expressly rejected the option of requiring facilities to report GHG emissions on a well-by-well 

basis. Id. at 118 (“Using a well pad definition would have necessitated the use of a lower 

threshold or no threshold. This in turn would have impacted small and medium operators to a 

much larger extent than the basin level definition will in today’s rule.”). Thus, adopting a basin 

level approach was critical to EPA’s goal of obtaining accurate GHG emissions from a sufficient 

number of operators in a given basin without having to lower emission reporting thresholds in a 

manner that would unduly impact small businesses. 

Nothing in the proposed rule provides a reasoned basis for deviating from the approach adopted 

by EPA in the original Subpart W rule. EPA does not question the accuracy of the aggregate 

GHG emissions data currently reported under Subpart W. Nor does it suggest that the existing 

data is no longer sufficient to inform policy. Instead, without providing any basis at all, EPA 

appears to have abandoned the former goal of balancing data collection with reporting burdens 

and has determined instead simply that more data is better, regardless of the cost and burdens. In 

essence, EPA’s proposal appears to be seeking an entirely holistic approach to gathering any and 

all industry related data using an aggregated basin-wide definition of facility to exclude some 

small and medium businesses, while requiring larger operators to still report well ID numbers 

and, thus provide emissions data at the well-pad level. But the general desire to have more data – 

in the absence of any showing that the currently collected emissions data is inaccurate or 

otherwise inadequate to inform EPA’s policy decisions – cannot provide a reasoned basis for 

rejecting EPA’s existing approach for this sector. 

Commenter 0137: For these reasons, it would be arbitrary and capricious to require companies to 

expend the resources necessary to report this data. EPA can clearly obtain high quality GHG 

emissions information from operators at the basin level as it has been doing since 2011, and 

changing its approach to the well ID level will add significantly to burdens without improving 

the quality of reporting GHG emissions. 

Commenter 0141: The Proposed Requirement to Report Individual Well ID Numbers Is Unduly 

Burdensome and Would Present Significant Compliance Challenges for Reporting on Storage 

Vessels and Emergency Flares. 

In the December 9, 2014 notice regarding the Proposed Subpart W Revisions, EPA proposes to 

“amend 40 C.F.R. 98.236 to add reporting requirements for well identification numbers to 

improve data quality by enabling identification of wells.” 79 Fed. Reg. at 73,157. EPA thus 

proposes to require reporting of well identification numbers “associated with different emission 

sources for all wells in a sub-basin included in the reported emission data.” 79 Fed. Reg. at 

73,158. Concho believes that the requirement to report individual well ID numbers “associated 

with” emission sources or equipment is inconsistent with the aggregation of equipment and 

emissions authorized under Subpart W. For example, Section 98.236(j)(1)(iii) requires reporters 
136 

to provide, for each sub-basin, the “total annual oil volume” sent to storage tanks. Providing the 

individual well ID number of each well that contributed to that total volume does not provide a 

data point necessary to determine the GHG emissions from that total volume of oil sent to the 

storage tanks. 

Commenter 0142: EPA’s Proposed GHG Reporting Rule proposes to amend 40 C.F.R. section 

98.236 to add reporting requirements for well identification numbers to improve data quality by 

enabling identification of wells. ... This approach would be inconsistent with EPA’s current 

approach, which requires reporting of aggregated equipment and emissions within a basin or subbasin only. 

Response 2: The EPA is finalizing the well identification number reporting requirements for 

wells but not for other emission sources. As noted by Commenter 0055-B, well identification 

numbers are available via “commercial data systems like the DI-Desktop or the EIA’s 

information,” which should lessen the industry’s burden related to gathering well identification 

numbers. 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) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 21 

Comment 3: Reporting of well identification numbers for previous years (e.g., 2012) is not 

being proposed by the EPA. API does not support reporting well IDs for any year, current or 

previous. 

Response 3: The EPA thanks the commenter for their support. The EPA did not propose and is 

not finalizing well identification number reporting requirements for previous years. See Section 

II.D of the preamble to the final rule for additional information regarding well identification 

number reporting for future reporting years. 

Commenter Name: C. William Giraud 

Commenter Affiliation: Concho Resources Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0141 

Page(s): 5 

Comment 4: The requirement to report individual well ID numbers is burdensome and ignores 

the commercial and operational realities of the oil exploration and development business. The 

proposed requirements for flare stacks and storage tanks illustrate the problems with reporting of 

individual well ID numbers. EPA is proposing to amend section 98.236(n) (flare stacks) by 

adding a new paragraph 13 which would provide that, for the onshore petroleum and natural gas 

production industry segment, reporters would have to provide a “list of the well ID numbers 
137 

associated with flare stacks in each sub-basin.” 79 Fed. Reg. at 73,186. Similarly, the Proposed 

Subpart W Revisions would add new subparagraphs to section 98.236(j) requiring reporting of 

the following information for “each sub-basin:” 

(ii) A list of the well ID number(s) associated with the tanks that controlled 

emissions with flares (for the onshore petroleum and natural gas production 

industry segment only) 

(iii) A list of the well ID number(s) associated with the tanks that did not control 

emissions with flares (for the onshore petroleum and natural gas production 

industry segment only). 

These proposed requirements are burdensome and would present significant compliance 

challenges. Because Subpart W does not define the phrase “associated with,” it is not clear what 

well ID numbers must be reported in each of the above categories. For instance, oil produced 

from several wells may be delivered to a single tank battery. Thus, oil produced in one sub-basin 

(county) might be delivered to a tank battery located in a different sub-basin (county). In such 

cases, it is not clear whether Concho would be required to report only the well ID number for 

wells within the same sub-basin as the tank battery or whether it would be obligated to list the 

well ID number for all wells that had product delivered to the tank battery during the reporting 

year, regardless of the sub-basin in which the well is located. A further complication arises from 

the practical reality that oil from a given well or number of wells may have been delivered to a 

tank battery, but then removed from the tank battery before the flare at that tank battery had to be 

used to control emissions. Thus, while product from those wells may have been present at one 

time, it was not present at the time the flare operated. In such circumstances, would those wells 

be considered “associated with” the flare? Would Concho be required to report all wells that 

delivered product to the tank battery at any time during the reporting year or would only those 

wells that had product present in the tank battery at the time the flare operated be “associated 

with” the flare stack? 

Given the inconsistency with other provisions of Subpart W, and the recordkeeping burden and 

practical and compliance problems described above, Concho recommends that EPA either (1) 

drop the proposal to require the reporting of well ID numbers in its entirety, or (2) clarify 

whether reporters must report the well ID number for only wells within the same sub-basin as the 

location of a tank battery or must instead list the well ID number for all wells that had product 

delivered to a given tank battery during the reporting year, regardless of the sub-basin in which 

the well is located, and (3) delete proposed section 98.236(n)(13). 

Response 4: The EPA is finalizing the well identification number reporting requirements for 

wells but not for other emission sources. See Section II.D of the preamble to the final rule for 

additional discussion responding to this comment. 

The EPA is not finalizing the proposed requirements to report a list of well identification 

numbers for storage tanks and flare stacks; as such, proposed 40 CFR 98.236(n)(13) is not 

finalized. 
138 

6.0 Compliance Date and Best Available Monitoring Methods 

Commenter Name: Thure Cannon 

Commenter Affiliation: Texas Pipeline Association (TPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0130 

Page(s): 11 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 5 

Comment 1: Commenter 0130: TPA questions the need for, and potential benefit of, the 

proposed longitude / latitude requirement for blowdown locations. ... If EPA intends to retain this 

proposal, then we would urge the agency to at least provide pipeline operators more time to 

comply with the requirements of the new rules pertaining to Onshore Natural Gas Transmission 

Pipelines, so that the precise blowdown locations can be ascertained in the requisite detail and 

reported accurately. We believe that it would be appropriate to extend the effective date for the 

new rules by six months, so that they would take effect on July 1, 2016, rather than on January 1, 

2016. 

Commenter 0133: We agree that reporting blowdown emissions along transmission pipelines 

would fill data gaps in EPA’s national inventory; however, it will take some time to set up the 

processes necessary to begin tracking these pipeline blowdown volumes, including categorizing 

them into the seven categories established in the most recent rule revision (effective January 1, 

2015). Although we have been voluntarily tracking and reporting blowdown emissions for some 

of our operations under the EPA Natural Gas Star Program, the proposal will increase these 

obligations significantly. Therefore, we request that reporters be provided additional time to set 

up adequate internal processes to comply. 

Response 1: The EPA is not finalizing the requirement to report the emissions or latitude and 

longitude for each individual blowdown, so extending the effective date to provide time for that 

provision is not necessary. See Section II.C of the preamble for more information about these 

changes. 
139 

Commenter Name: Public Hearing: Thomas Bach 

Commenter Affiliation: Public Hearing: Kinder Morgan, Representing Interstate Natural Gas 

Association of America 

Comment Number: EPA-HQ-OAR-2014-0831-0055-A 

Page(s): 13 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 4 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 5 

Commenter Name: Thure Cannon 

Commenter Affiliation: Texas Pipeline Association (TPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0130 

Page(s): 11 

Commenter Name: Thure Cannon 

Commenter Affiliation: Texas Pipeline Association (TPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0130 

Page(s): 12-13 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 7-8 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 7 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 9-10 

Commenter Name: Gretchen C. Kern 

Commenter Affiliation: Pioneer Natural Resources USA, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0134 

Page(s): 4 
140 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 2 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 24-27 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 14

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 12-13 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 18-19 

Comment 2: Commenter 0055-A: Best Available Monitoring Methods, otherwise known as 

BAMM. EPA proposes to allow operators to use preapproved BAMM from January 1 through 

March 31, 2016, to implement the systems necessary for the proposed reporting. INGAA 

believes that this is insufficient time for gas transmission and other affected sources, such as the 

gathering and oil production operators, to develop and implement those systems. With that, 

INGAA recommends that EPA extend the BAMM deadline through 2016. 

Commenter 0125: We appreciate that EPA developed BAMM provisions for the initial 

implementation of the proposed amendments, with the ability for extension requests through 

December 31, 2016. However, the proposed vast expansion of the rule to include oil well 

completions and workovers with hydraulic fracturing, coupled with two completely new 

segments, creates great challenges in being inclusive of all segments with regard to monitoring 

methods. 

Commenter 0125: We request that EPA automatically allow BAMM for the newly required 

elements to be extended to December 31, 2018. Note that EPA allowed 3 years of BAMM when 

Subpart W was originally proposed for the production segment, and now that two new segments 

have been proposed, EPA should allow the same amount of time given the large amount of 

potential sources and effort needed to comply with the rule. 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. Operators 
141 

that may have common ownership in more than one segment will be required to follow 

monitoring methods from each segment. 

Commenter 0130: We urge EPA to revise the proposed rules relating to the use of best available 

monitoring methods (“BAMM”) to provide more flexibility and a greater opportunity to use 

BAMM during the initial implementation phase of all of the new Subpart W revisions. 

Commenter 0130: We urge EPA to allow the use of BAMM without the need to receive EPA’s 

permission for the entirety of 2016 (or 2017 if the effective date is extended), as opposed to the 

currently proposed three-month period from January 1 to March 31, 2016. This would add 

needed flexibility and would be appropriate because the proposed rules would not only subject 

entirely new industry segments to the reporting requirements, but the proposed rules would also 

cause a huge number of additional facilities and individual sites and equipment components to 

become covered by the reporting requirements. This problem would be especially acute in the 

gathering and boosting industry segment, as explained above. It would take a significant 

implementation effort to institute protocols needed to report emissions from the vast array of farflung components that would be newly covered by these proposed rule revisions, and that effort 

would not only take a substantial amount of effort and resources, it would also take a large 

amount of time. Allowing automatic use of BAMM for the entirety of the first reporting year 

would relieve some of the pressure and would allow covered entities the opportunity to design 

and implement needed systems in an orderly, systematic, and efficient manner. 

Commenter 0132: Automatic BAMM is needed for the entire first reporting year for ONGGB 

rather than the proposed three months. 

Justification of a longer period of automatic BAMM is as follows: 

Subpart W implementation originally allowed one year of BAMM.

Subpart W became effective in 2011, and automatic BAMM was allowed for all of reporting 

year 2011.9

 There is no reason data collection for the ONGGB industry segment should be 

treated differently. Entirely new industry segments are being added to reporting, which will 

require a significant implementation effort. 

New requirements represent a substantial increase in the number of reporting facilities.

Even according to EPA’s underestimated impact analysis, this proposal represents at least an 

estimated threefold increase in the number of reporting compressor stations when based on the 

number of processing plants reporting.10 As such, if one year was allowed to implement Subpart 

W reporting in other industry segments, at least one year must be allowed to implement Subpart 

W, in the ONGGB industry segment, particularly in light of the geographically dispersed nature 

of the sites and the significant reporting expansion. 

Although all proposed emission estimation methods are currently in the rule, many 

reporters are not currently using these methods.
142 

Many of GPA’s members currently only report in the Onshore Natural Gas Processing industry 

segment, and some members might not report under Subpart W at all. Additionally, many 

ONGGB industry segment reporters do not report under the Onshore Production industry 

segment. Thus, implementing this rule is not just a matter of expanding current practices to 

additional facilities. Understanding the final rule requirements, preparing applicability analyses, 

developing and implementing recordkeeping tools, conducting training, collecting data and data 

quality assurance/quality control (QA/QC) activities will require significant time and resources. 

Reporters will need focus on implementing these expansive new reporting requirements 

and will not have time to request BAMM on a case-by-case basis.

Many reporters will have hundreds of gathering and boosting stations that will be subject to the 

proposed expanded requirements. Preparing case-by-case BAMM requests will require extensive 

time and effort, which can be better spent in implementing data collection practices. 

Footnotes: 

9

 40 C.F.R. 98.234(f)(2), (3), (4), (5) (2014). 

10 EPA Climate Change Division, Assessment of Impacts of the 2015 Proposed Revisions to 

Subpart W (Nov. 10, 2014), available at

http://www.regulations.gov/contentStreamer?objectId=0900006481948b3c&disposition=attachm

ent&contentType= pdf. EPA estimates three compressor stations upstream of each gas treatment 

facility. 

Each of the two gathering and boosting systems that comprise the model reporter 

is connected to three producing fields, so six fields total. There is a compression 

station associated with each connected field and each gathering and boosting 

system has a stand-alone gas treatment facility with a compressor station on the 

outlet side. 

Id. at 5. 

Commenter 0133: We acknowledge the need to collect and quantify emissions from the 

Gathering and Boosting segment to achieve more complete coverage of the petroleum and 

natural gas systems sector. However, we request that reporters be provided additional time to set 

up adequate internal processes to comply. 

Commenter 0133: We request an extension of the BAMM monitoring method discussed below. 

Short Term Best Available Monitoring Method (BAMM)

The proposed rule allows automatic BAMM for the first three months of 2016 and requires 

submittal of a request by January 31, 2016, if BAMM is needed after March 31, 2016. This is 

intended to provide flexibility to reporters subject to new monitoring requirements and the first 

time monitoring of new emissions sources. We intend to put processes in place to meet the new 
143 

reporting requirements within the timeframes required, but foresee that additional time may be 

necessary to complete all the component counts, tank inventories, and to ensure that records of 

all blowdowns from transmission pipelines and from the new Gathering and Boosting segment 

can be accurately captured. In order to ensure full compliance with the proposed revisions to 

Subpart W, we request that automatic BAMM be extended through 2016, without written request 

by the reporter. This would provide the flexibility needed, and eliminate additional burdens upon 

reporters and the EPA for addressing extensions of BAMM. 

Commenter 0134: Pioneer agrees with GPA that BAMM for the new Gathering and Boosting 

Segment should be automatically available for the first reporting year, as opposed to only three 

months as proposed, with an option to apply for BAMM for three years thereafter, consistent 

with the historical treatment of BAMM under Subpart W. 

In regard to the complexity of reporting under a new industry segment, especially in the 

preparatory stages, as articulated above, and as GPA explains, Subpart W implementation 

originally allowed one year of automatic BAMM. There is no reason that data collection for the 

gathering and boosting segment proposed in this rule should be treated any differently. This is an 

entirely new segment being added to the overall reporting. Although the same methodologies 

from the Onshore Production and Processing segments are to be applied, data collection 

procedures and methods for emission sources in this new segment, that have not previously been 

captured for Subpart W reporting, will need to be put into place in order to comply, resulting in a 

significant implementation effort. It is likely that additional monitoring equipment will need to 

be purchased and installed as well. 

Further, the Onshore Production and Processing segments of Subpart W allowed BAMM to be 

available for three subsequent years, after the first year of automatic BAMM, upon a timely 

request by the operator and approval by EPA. For the same reasons stated above requesting that 

automatic BAMM be granted for year, this new segment should be given the same deference and 

time to comply. It is unreasonable for EPA to believe that there will never be a situation where 

BAMM may not be required beyond the first year of reporting under a new industry segment. 

Therefore, allowing automatic BAMM for one year and the option to use BAMM for three 

subsequent years upon EPA’s approval is fair, appropriate, and consistent with EPA’s historical 

application of BAMM under Subpart W. 

Commenter 0137: API requests a one-year BAMM period for the new Gathering and Boosting 

segment, consistent with the transitional BAMM periods that EPA provided for other sectors 

when they were first included in the reporting rule. 

Commenter 0137: API appreciates EPA’s recognition in the proposed rule that a transitional 

BAMM period is necessary to ensure that the proposed revisions to the reporting requirements in 

Subpart W can be implemented in an efficient and cost-effective manner. 79 Fed. Reg. at 73,158 

(proposing three-month transitional BAMM for select facilities affected by the proposed rule). 

First, to clarify, API is not proposing that EPA should continue to allow BAMM indefinitely for 

all facilities. However, API does not believe that EPA’s transitional BAMM proposal goes far 

enough to assist facilities that will be required to report emissions under the proposed rule. Thus, 

we urge EPA to extend the BAMM transitional period from three months to one year and to 
144 

make BAMM available for every new reporting obligation that is finalized in this rulemaking. 

Further, we urge EPA to maintain BAMM as a short term transitional option for newly acquired 

wells where owners and operators are faced with reporting obligations for the first time with 

respect to the newly acquired equipment. 

Providing a one-year transitional BAMM period for all facilities subject to new reporting 

obligations under the proposed revisions to Subpart W will provide necessary flexibility to 

reporters and also accommodate the inevitable issues that will arise regarding situations beyond 

the companies’ control while new monitoring, recordkeeping, and reporting protocols are being 

implemented. Based on prior years of experience in implementing new requirements under the 

GHGRP, EPA’s proposed three-month transitional period is insufficient to meet challenging and 

unforeseen circumstances and, accordingly, will make compliance difficult for some facilities. In 

fact, EPA has traditionally provided facilities with at least a one-year transitional period to apply 

BAMM after new reporting obligations have been imposed. Thus, consistent with EPA’s past 

practice, providing a one-year transitional period represents a reasonable balance between EPA’s 

goals of full compliance with the reporting requirements and the need to accommodate the 

possibility that the terms as finalized in the rule will require further clarification or that reporters 

will find it more difficult than expected to develop the required systems for reporting GHG 

emissions under the new requirements. Thus, API believes that a one-year transitional period is 

necessary and critical to resolving any additional issues that may arise from the ultimate 

finalization of this rule. 

API’s position is supported by past experience, where BAMM has proven critical in bridging the 

gap between the timing of EPA’s final rules and compliance obligations. EPA has allowed 

BAMM in some form 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 request or 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). 

Likewise, API’s members have found, over the course of implementing the Subpart W reporting 

requirements, 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. BAMM has 

been critical in those cases. This is particularly true where there is limited lead time from the 

finalization of reporting requirements and the implementation in the following calendar year. For 

example, with respect to natural gas actuated pneumatic devices, providing a transitional BAMM 

period was essential in allowing member companies sufficient time to collect more refined data 

on low-, intermediate-, and high-bleed devices. This type of equipment-level data was not readily 

available from company records and, as a result, required more costly and time-consuming field 
145 

survey to collect accurate data. While this regulatory burden ultimately was not insurmountable, 

the additional time afforded by a transitional BAMM period was essential to the eventual 

reporting of accurate and stratified data on natural gas actuated pneumatic devices. Likewise, 

certain event-driven data collection contemplated by Subpart W required member companies to 

create and implement new data collection systems and new training programs to accurately 

collect and report the data identified by EPA. Without a transitional BAMM period, member 

companies could not have developed the capacity to report emissions data for emission source 

categories such as well venting during liquids unloading and blowdown venting. These examples 

cited above are unequivocal success stories that demonstrate how important BAMM is as a 

transitional tool under the GHG reporting program. In each case, due to unforeseen complicating 

factors, companies would not have been able to report emissions data by the effective dates of 

the Subpart W rules without transitional BAMM as an interim measure. Given the likelihood that 

similar unforeseen challenges will arise in the future, it is imperative that EPA continue to 

provide at least a one-year transitional BAMM period to ensure that reporting entities have 

alternative options for reporting as they develop the tools and capacity to comply fully with the 

requirements under Subpart W. Doing so furthers EPA’s goals of reporting timely and accurate 

GHG emissions data. 

Commenter 0139: The proposed rule would allow new industry segments and sources included 

in the proposal to use best available monitoring methods (“BAMM”) for the 2016 reporting 

year.63 We recommend that EPA not extend the use of BAMM beyond that year. Extended use of 

BAMM would undermine the accuracy and rigor of emissions data from the oil and gas sector 

and would be inconsistent with the agency’s recently finalized revisions to Subpart W, which 

remove all prior BAMM provisions but allow transitional BAMM for new reporting 

requirements.64 Accordingly, we urge EPA to strictly limit the use of BAMM to the 2016 

reporting year. 

Footnotes: 

63 Id. at 73,158. 

64 Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems, Final Rule, 79 Fed. Reg. 70,352, 70,372 (Nov. 25, 2014). 

Commenter 0140: INGAA believes that the EPA should allow operators to use BAMM for the 

entire 2016-reporting year without the need for pre-approval to accommodate the necessary 

changes in recordkeeping systems. 

The EPA proposes to allow operators to use BAMM without pre-approval for the first three 

months of 2016. If additional time is needed, a BAMM use request must be submitted to the 

EPA by January 31, 2016. Operators will need time to develop systems to implement the new 

Subpart W requirements. For example, a new tracking system would be needed if detailed event 

location information were required for each pipeline blowdown event. INGAA recommends 

allowing BAMM without the need for pre-approval for the entire 2016 reporting year to provide 

operators adequate time to implement new requirements. This one-year waiver would also 

reduce the costs of compliance with the proposed regulation. If EPA does not agree with 
146 

INGAA’s recommendation and BAMM is only allowed for three months, many operators will 

likely submit BAMM requests by the January 31 deadline. Consequently, if EPA takes this 

course, the Proposed Rule should be revised to identify the EPA’s plan for reviewing and acting 

on BAMM requests. The EPA should be obligated to respond to BAMM requests well in 

advance of the March 31, 2016 expiration date. 

Comment 0142: In the Proposed GHG Reporting Rule, EPA provides a short-term solution to the 

potential implementation timing issue by allowing reporters to use Best Available Monitoring 

Methods for any data that cannot reasonably be obtained. Per EPA’s proposal, operators can use 

BAMM without pre-approval from January through March 2016. However, to implement 

BAMM beyond March 31, 2016, operators would need to seek pre-approval from EPA by the 

end of the first month of the reporting year (January 31, 2016). It is impossible for operators to 

implement the improvements necessary to comply with the Proposed GHG Reporting Rule 

between January and March of 2016, especially since the rule is not projected to be finalized 

until summer of 2015. There will undoubtedly be a learning curve during the first year of the 

data collection and without BAMM, operators would likely be at a high risk for operational 

disruptions, which is not likely EPA’s intent. As with the originally promulgated GHG Reporting 

Rule, operators will most likely be required to submit BAMM requests because there will be 

insufficient time between when the final rule is adopted and the effective date to fully implement 

required data collection and management system changes. EPA also needs to consider its own 

time considerations for review and approval of the expected BAMM requests. Kinder Morgan 

submits the following revisions to the Proposed GHG Reporting Rule: 

EPA Proposed 40 C.F.R. 98.234: (g) Special reporting provisions for best 

available monitoring methods in reporting year 2016. 

(1) Best available monitoring methods. From January 1, 2016 to March 31, 

20167, you must use the calculation methodologies and equations in 98.233 but 

you may use the best available monitoring method for any parameter for which it 

is not reasonably feasible to acquire, install, and operate a required piece of 

monitoring equipment by January 1, 20167 as specified in paragraphs (g)(2) 

through (5) of this section. Starting no later than April 1, 20167, you must 

discontinue using best available methods and begin following all applicable 

monitoring and QA/QC requirements of this part, except as provided in paragraph 

(g)(6) of this section. 

In addition to the above revisions, Kinder Morgan proposes EPA strike all of the proposed 

98.234(g)(6) which discusses “Requests for extension of the use of best available monitoring 

methods beyond March 31, 2016.” Thus, like INGAA, Kinder Morgan supports the use of 

BAMM without pre-approval for the full 2016 reporting year to accommodate the time needed to 

integrate new technology and data collection and management systems as well as to avoid 

potential operational disruptions. 

Response 2: The EPA is providing 1 year of automatic (i.e., without pre-approval) transitional 

BAMM for the new industry segments and emission sources included in this rulemaking. See 
147 

Section II.E of the preamble to the final rule for additional discussion responding to this 

comment. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 8 

Comment 3: BAMM will be needed in limited circumstances. 

Past experience has proven BAMM critical in bridging the gap between final rules and 

compliance obligations and EPA has found that extensions were necessary in limited 

circumstances. With this large expansion of the rule, EPA should recognize that BAMM may be 

required for certain unique scenarios. GPA does not expect for EPA to grant BAMM in scenarios 

when data can be reasonably collected. However, EPA should retain their ability to review 

BAMM requests and decide whether approval is granted. GPA also reminds EPA that the ability 

to grant BAMM requests for compressor monitoring was critical during the period of rule 

reconsideration for that equipment type. Should an analogous situation arise, EPA should retain 

their ability to grant BAMM requests. 

Response 3: The EPA is providing 1 year of automatic transitional BAMM for the new industry 

segments and emission sources included in this rulemaking. The EPA is not granting requests for 

BAMM beyond this time frame. See Section II.E of the preamble to the final rule for additional 

discussion responding to this comment. 
148 

Commenter Name: Thure Cannon 

Commenter Affiliation: Texas Pipeline Association (TPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0130 

Page(s): 12 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 9 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 2 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 27 

Comment 4: Commenter 0130: Under the currently proposed timeline, for 2016 emissions, EPA 

proposes to allow use of BAMM for reporters who would be subject to new reporting 

requirements associated with the proposed revisions.24 These reporters would have the option of 

using BAMM from January 1, 2016 to March 31, 2016 without seeking prior EPA approval; 

reporters could also request EPA approval to use BAMM for the remainder of 2016.25

While TPA appreciates the agency’s inclusion of these provisions, we believe that EPA should 

expand the opportunity for reporters to use BAMM. To begin with, we urge EPA to leave the 

door open to the use of BAMM beyond 2016 (or 2017 if the effective date is extended). As the 

rules are currently proposed, use of BAMM beyond 2016 would not be a possibility under any 

circumstance. See, e.g., 79 Fed. Reg. 73151 (stating that “[f]or 2016 emissions only, the EPA is 

proposing to allow the use of short-term transitional BAMM”). We believe, however, that 

circumstances could arise well beyond 2016 that could make the use of BAMM appropriate. For 

example, a transaction could occur after 2016 whereby assets that were not previously subject to 

the reporting rules were acquired by and added to a larger system, making the acquired assets 

subject to reporting for the first time. In such a circumstance, BAMM might be appropriate to 

allow time for the acquiring company to institute and implement reporting protocols for the new 

assets. In such a situation, the acquiring company should at least have the opportunity to ask 

EPA for permission to employ BAMM. We see no reason to finalize rules that could eliminate 

the possibility to use BAMM, with EPA’s permission, where extraordinary circumstances 

warranted such use. 

Footnotes: 

24 79 Fed. Reg. 73151 (Dec. 9, 2014). 

25 79 Fed. Reg. 73151 (Dec. 9, 2014). 
149 

Commenter 0132: BAMM is needed when facilities are acquired and divested. 

When non-reporting assets are added to existing facilities, they must be incorporated into 

existing facility reporting. In another scenario, two small non- reporting assets may be combined 

and trigger the reporting threshold. In sections 98.235(e) and (f), EPA allows best engineering 

estimates “for the first 6 months of required data collection” in cases of newly reporting facilities 

or source acquisition from another facility that was not previously subject to Subpart W. 

However, this is not adequate for ONGGB divestiture and acquisition. For example, if an 

acquisition closes on December 1, the provisions of sections 98.235(e) and (f) only cover 

January through June (the first six months of required data collection). There is no available path 

in the rule for BAMM or missing data procedures for the July through November data. 

Therefore, BAMM must be available to be approved by EPA for cases such as these. For 

acquisition of facilities that were reported under Subpart W by the previous owner or operator, 

GPA notes that there is no distinction in the level of effort required to integrate newly acquired 

sources into an existing reporting program whether previously excluded from Subpart W or 

reported by a different entity. 

Commenter 0137: It is also critical that EPA maintain a one-year transitional BAMM option for 

newly acquired wells or other equipment that were previously reported by another company. 

Commenter 0137: It is critical that EPA permanently maintain a one-year transitional BAMM 

option for newly acquired wells or other equipment that were previously reported by another 

company. As a practical matter, 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 excluded from Subpart W or reported by a different entity. 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. Regardless of 

a company’s experience with respect to the Subpart W reporting requirements, each well is 

unique and companies must have the flexibility – during a brief one year transitional period – to 

apply BAMM until they can integrate the new well into their broader basin level reporting 

program. 

Response 4: The EPA is not allowing reporters a permanent 1-year transitional BAMM option 

for newly acquired wells or other equipment that were previously reported by another company. 

As noted by Commenter 0132, 40 CFR 98.235(e) and (f) already provide for the use of 

engineering judgment during the first 6 months of data collection. This ensures consistency 

between the new segments and the emissions sources already covered. See Section II.E of the 

preamble to the final rule for additional discussion of transitional BAMM that is being finalized 

in this rulemaking. 
150 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 5 

Comment 5: Although, as of January 1, 2015, BAMM is no longer allowed for the currently 

regulated segments of Subpart W, we are requesting that BAMM be reopened, and extended 

until December 31, 2017. Due to the inclusion of all segments of the onshore oil and gas 

operations, operators will need time to incorporate and re-evaluate the methods of monitoring on 

a corporate, grand scale. This is necessary for operators to ensure the implementation of 

monitoring methods can be efficiently applied and integrated across each of the segments. This 

will allow for a more accurate and inclusive internal management system to be implemented for 

all of the data. 

Response 5: The EPA is not allowing extension requests for the use of BAMM. See Section II.E 

of the preamble to the final rule for additional discussion of transitional BAMM that is being 

finalized in this rulemaking. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 27 

Comment 6: To ensure consistency during the transitional BAMM period, we encourage EPA to 

use available industry-reported data to develop average emission factors for emissions data to 

which BAMM is applicable. In addition to existing BAMM programs that can be implemented 

by new in-scope facilities, providing such data would give facilities a means of scaling up certain 

emissions data. Such an approach to supplementing existing BAMM procedures would have the 

benefit of reducing inconsistencies in BAMM data reported by different entities in a given field. 

Response 6: The calculation methods provided in subpart W were selected to minimize burden 

on industry while maintaining the necessary quality and consistency of data to inform policy. All 

known emission factors have already been incorporated into the subpart W requirements; 

BAMM is reserved for reporters that are reasonably unable to follow the subpart W 

requirements. Therefore, outside of the transitional BAMM provisions being finalized in this 

rulemaking, the EPA does not agree to allow reporters to use customized, individual information 

for their emission sources. The EPA is currently investigating additional calculation methods for 

subpart W sources and may propose additional calculation methods that would apply consistently 

to all reporters of a particular emission source and/or segment in the future. 
151 

Commenter Name: Thure Cannon 

Commenter Affiliation: Texas Pipeline Association (TPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0130 

Page(s): 12 

Comment 7: In the preamble, EPA states that it intends for the new Subpart W provisions to 

become effective on January 1, 2016.23 However, given the substantial logistical issues that 

would be involved in complying with the new rules as they are currently proposed, we do not 

believe that it would be realistic to make the rules effective beginning in 2016. A more realistic 

starting point would be January 1, 2017, and we urge EPA to extend the effective date until then 

in order to allow reporters a reasonable amount of time to identify affected sources and to 

develop and implement reporting systems needed to comply with the new provisions. 

Footnotes: 

23 79 Fed. Reg. 73151 (Dec. 9, 2014). 

Response 7: The EPA has reviewed the comment and has determined that for new emissions 

sources and new industry segments, the EPA is allowing the use of BAMM. For information 

regarding the timing for allowing application of BAMM and other details, see Section II.E of the 

preamble to the final rule. 

 
152 

7.0 Disclosure Concerns Related to Exploratory Wells 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 2 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 27-28 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 28-30 

Comment 1: Commenter 0137: EPA has provided a two-year deferral for reporting some data 

associated with exploratory oil wells. However, release of any information that identifies 

exploratory wells is likely to cause irreparable and substantial commercial and competitive harm 

to reporters. API urges EPA to provide a two-year delay in reporting any information for 

exploratory wells. 

Commenter 0137: API has commented on several occasions regarding concerns with the 

GHGRP leading to improper disclosure of confidential business information (CBI) and the need 

for EPA to protect business confidential and sensitive information from competitors as being 

critically important to API and its members. 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 subbasin. We again focus our comment on exploratory wells because this issue is of the utmost 

importance to the industry in order to avoid the disclosure of sensitive, confidential and 

competitive business information prematurely to competitors and the public. In these comments, 

API reiterates its previous legal and technical comments regarding CBI, which API submitted to 

EPA on November 26, 2013 and April 24, 2014. Thus, API incorporates by reference those 

comments (including legal objections to EPA’s treatment of CBI) and also attaches those 

comments to this comment package (as Attachment A). 

Commenter 0137: Federal law and state codes 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. 

Releasing data to the public regarding operating characteristics of such wells, including postflowback flaring/venting volumes, could cause competitive harm if made publicly available too 

early. Industry makes substantial investments in exploration and development projects in new 
153 

areas. These investments in exploration are long-term and it takes a long time for companies to 

characterize the magnitude and potential production characteristics of prospective resources. In 

some areas, 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. 

In light of these concerns, API is encouraged by EPA’s recognition in the proposed rule that “the 

early public disclosure of certain data elements that are inputs for [wildcat wells and delineation 

wells] could reveal data on well productivity that could give competitors an advantage by giving 

them information on new fields or new areas of existing fields without have to drill their own 

wildcat or delineation wells.” 79 Fed. Reg. at 73,160. API agrees with EPA that it is appropriate 

to defer reporting for such data elements for a period of two years and thus supports EPA’s 

proposal to defer the reporting of data elements related to oil well completions and workovers 

with hydraulic fracturing. See proposed 40 CFR 98.236(g)(5)(i); 40 CFR 98.236(g)(5)(ii); and 

onshore production storage tanks: 40 CFR 98.236(j)(1)(v). 

API is concerned, however, that EPA has not provided such a delay in reporting for all emissions 

data and data elements that are associated with exploratory wells in order to protect the release of 

confidential and sensitive business information to competitors. Release of any information that 

identifies exploratory wells is likely to cause irreparable and substantial commercial and 

competitive harm to reporters. Specifically, EPA failed to provide a necessary two-year deferral 

in reporting for the following data elements: 

 40 CFR 98.236(g)(5)(iii)(A) – If you used Equation W-12C to calculate the average gas 

production rate for an oil well, the gas to oil ratio for the well in standard cubic feet of 

gas per barrel of oil (“GORp” in Equation W-12C). 

 40 CFR 98.236(g)(5)(iii)(B) – If you used Equation W-12C to calculate the average gas 

production rate for an oil well, the volume of oil produced during the first 30 days of 

production after completions of each newly drilled well or well workover using hydraulic 

fracturing, in barrels (“Vp” in Equation W-12C).

 40 CFR 98.236(g)(6)(i) – If you used Equation W-10B to calculate annual volumetric 

total gas emissions for completions that vent gas to the atmosphere, the vented natural 
154 

gas volume, in standard cubic feet, for each well in the sub-basin (“FVs,p” in Equation 

W-10B).

 40 CFR 98.236(g)(6)(ii) – If you used Equation W-10B to calculate annual volumetric 

total gas emissions for completions that vent gas to the atmosphere, the flow rate at the 

beginning of the period of time when sufficient quantities of gas are present to enable 

separation, in standard cubic feet per hour, for each well in the sub-basin (“FRp,i” in 

Equation W-10B).

 40 CFR 98.236(g)(7) – For each oil well completion or workover and well type 

combination, annual gas emissions, in standard cubic feet (“Es,n” in Equation W-10A or 

W-10B).

 40 CFR 98.236(g)(8) – For each oil well completion or workover and well type 

combination, annual CO2 emissions, in metric tons CO2.

 40 CFR 98.236 (g)(9) – For each oil well completion or workover and well type 

combination, annual CH4 emissions, in metric tons CH4.

 40 CFR 98.236 (g)(10) – For each oil well completion or workover and well type 

combination, the total N2O emissions, in metric tons N2O, if the well emissions were 

vented to a flare.

This information is as business sensitive and confidential as the other information properly 

deferred by EPA for two years. Thus, API requests – consistent with state and federal laws in oil 

producing states – that EPA categorically determine that reporting of all information associated 

with exploratory wells be deferred for a period of two years. While providing significant 

protection to our members, such an approach will have little effect on emissions reporting 

because only a small amount of information would be deferred in a typical year as relatively few 

exploratory wells are drilled in any given area and, ultimately, such information will be made 

available to EPA and the public after two years. 

As in past comments, API is proposing two options that EPA could use to categorically defer the 

release of data related to exploratory wells for two years: 

(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 two years. 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 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. 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. 

Response 1: In the final rule, the EPA is finalizing the proposed option for reporters to delay 

reporting for 2 reporting years in specific situations related to two types of exploratory wells, 
155 

delineation and wildcat wells (as defined in 40 CFR 98.238) for specific data elements. See 

Section III of the preamble to the final rule for more information. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 31 

Comment 2: API agrees that some data elements should not be disclosed - in certain situations - 

beyond the initial 24 months for exploratory wells. These include 40 CFR 98.236(g)(5)(i); 40 

CFR 98.236(i)(1)(i) and 40 CFR 98.236(j)(3)(ii), in situations when the applicable data are 

available for only one well, one blowdown, or one gas-liquid separator. API requests that EPA 

would promulgate this additional CBI protection to prevent commercial harm due to the easily 

identifiable nature of the confidential data. 

Response 2: At proposal, the EPA determined that the three data elements referenced by the 

commenter are inputs only in certain situations. Specifically, these data elements are inputs when 

the applicable data are available for only one well, one blowdown, or one gas-liquid separator. 

For situations when these data elements are not inputs (i.e., when data are available for multiple 

wells, blowdowns, or gas-liquid separators), the EPA proposed these data elements to be “not 

CBI.” Specifically, the “not CBI” determination applies to all situations that involve multiple 

non-exploratory wells or a mix of exploratory and non-exploratory wells. 

The EPA foresees no disclosure concerns with the inputs identified by the commenter beyond the 

2-year delay in reporting provided in the proposed rule. The commenter has previously noted 

that information related to exploratory wells is made available by state agencies after 2 years. 

The commenter did not specify their disclosure concerns, nor did the commenter indicate that the 

state agencies would not release these particular inputs after 2 years. Therefore, the EPA is 

finalizing the 2-year delay in reporting for these inputs as proposed. 

 
156 

8.0 Confidentiality Determinations and Data Category Assignments for New 

Data Elements 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 36 sect 15.5 

Comment 1: GPA asserts that the proposing reporting element in section 98.236(aa)(10)(i), 

“[t]he quantity of produced gas throughput in the calendar year in thousand standard cubic feet,” 

should be treated as CBI. 

EPA has stated, “[w]e have decided to maintain the annual quantity of natural gas received at 

gas plants and the annual quantity of processed (residue) gas leaving gas plants as 

confidential.”30 The EPA should allow businesses to determine the confidentiality of the gas 

received because ONGGB companies have contract agreements with producers that could allow 

for competitive harm. In fact, as noted in Table 3, under the Proposed Confidentiality 

Determinations and Rationale the statement, “[o]nce these agreements are established, 

information on the actual throughput of the gathering and boosting system is not likely to affect 

the competitive position of the company operating the gathering and boosting system . . .”31 The 

GPA questions the phrase “is not likely.” The main scope of the GHG inventory is to provide 

information concerning the greenhouse gases on an annual basis at a facility or facilities and 

should not involve publicizing the input values. 

Footnotes: 

30 Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems, 79 Fed. Reg. 70,352, 70,375 (Nov. 25, 2014) (emphasis 

added). 

31 Proposed Rule at 73,170 (emphasis added). 

Response 1: The EPA is finalizing the data elements related to gas throughput in 40 CFR 

98.236(aa)(10) as “not CBI.” See Section III of the preamble to the final rule for additional 

information. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 32 

Comment 2: GPA asserts that the proposed reporting element in section 98.236(aa)(10)(ii), 

“[t]he quantity of produced gas consumed in the calendar year, in thousand standard cubic feet,” 

should be treated as Confidential Business Information (CBI). 
157 

EPA is proposing that this new data element not be designated CBI because it “is not likely to 

affect the competitive position of the company” and “the information will be aggregated.”27 This 

information should be designated as CBI for the following reasons. First and most importantly, 

revealing this information could result in competitive harm. Information on fuel consumed at 

gathering and boosting stations is not typically publically available and this information directly 

indicates the fuel efficiency of a station. While a station’s contract may be established for long 

periods of time, contracts at other stations owned by the same company may be renegotiated at 

any given time. These contracts are not publically available and are negotiated privately. If 

information is available through the Greenhouse Gas Reporting Rule that negatively reflects on 

an ONGGB company’s fuel efficiency, this could lead to a competitive disadvantage in 

negotiating any open contracts within or outside of that basin. 

Additionally, EPA is also requesting the data element section 98.236(aa)(10)(i) “[t]he quantity of 

produced gas throughput in the calendar year, in thousand standard cubic feet.” If both the 

throughput and the fuel use are publically available, then fuel efficiency (throughput divided by 

fuel use) is publically available. This could lead to competitive disadvantage, especially if not all 

ONGGB owners and operators are reporting because they are below the reporting threshold. 

Indeed, even if this fuel efficiency was available for every single ONGGB owner and operator 

nationwide, this would result in competitive information that would not be publically available 

otherwise, and this could alter how contracts are negotiated. GPA does not think that EPA 

intends to alter this contract negotiation process, but making this data publically available could 

do just that. Finally, EPA states that because this information is aggregated, it should not be CBI. 

However, EPA does not account for a scenario where an operator may only have one (or a small 

number) of stations within the reporting facility. As previously stated, even aggregated 

information could lead to competitive disadvantage. 

Footnotes: 

27 See Proposed Rule at 73,169. 

Response 2: The EPA has revised the reporting elements in 40 CFR 98.236(aa)(10) for the final 

rule. See Section III of the preamble to the final rule for additional information. 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 15 

Comment 3: EPA is proposing 171 data elements to be reported by the gathering and boosting, 

transmission, and production segments.65 Commenters support the agency’s determination that 

these data are not confidential business information, and, accordingly, will be made publicly 

available. Transparency is of the utmost importance to the integrity and usefulness of Reporting 

Program data. It is especially important to have reliable information about facility characteristics 
158 

and operations in order to understand the drivers of emissions and opportunities for reductions, 

as well as to verify the accuracy of emissions reporting. This information also has important 

market uses, allowing investors and purchasers to factor in emissions profiles when choosing 

among various companies or operators.66

Footnotes: 

65 79 Fed. Reg. at 73,159, 73,162-68 tbl. 2. 

66 See Goldman Sachs, Global Markets Institute, Unlocking the economic potential of North 

America’s energy resources, at 10-11 (June 2014) (concluding that uncertainty about 

environmental impacts and regulatory policies has delayed much needed demand-side 

investment in oil and gas). 

Response 3: The EPA thanks the commenter for their support. The confidentiality 

determinations are finalized as proposed. 

 
159 

9.0 Impacts of the Proposed Amendments 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 7 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 7 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 10 

Commenter Name: C. William Giraud 

Commenter Affiliation: Concho Resources Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0141 

Page(s): 3 

Commenter Name: C. William Giraud 

Commenter Affiliation: Concho Resources Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0141 

Page(s): 4 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 4 

Comment 1: Commenter 0125: Many of the added data elements to be gathered and reported 

under the EPA’s proposal, although not confidential business information, are not essential to the 

emission calculations required under the GHG emissions reporting rule. These added data 

elements do not embody the purpose of the GHG emissions reporting rule and, in being mindful 

of limited resources and challenging economic times, should not be required of the regulated 

community. For instance, EPA has added many reporting data elements to atmospheric tanks: 

number of tanks, number of tanks with VRUs and flares, number of tanks 

controlled/uncontrolled, etc., within a basin or sub-basin. The number of tanks in a basin or subbasin is not used in calculations when estimating the associated emissions. Furthermore, 

depending on the operations, the number of tanks may be variable during any given calendar 

year. This information is not technically relevant to estimating emissions. Rather emissions are 

estimated based on oil and/or gas throughput, composition, controls, etc. – data already required 

(and reported to EPA) under the GHG emissions reporting rule. 
160 

We request that EPA reconsider the addition of data elements to report in this rulemaking, 

particularly those that do not pertain to emission calculations. While we recognize that much of 

the non-emissions calculations data is not CBI (e.g., information submitted in permit applications 

or contained in permits) we urge EPA to remove or significantly limit its request for information 

that does not inform the actual emissions calculation as issue under the GHG emissions reporting 

rule. The significant resources consumed by the regulated community to gather and cull the nonemissions calculations data will outweigh the informational benefit to EPA and may detract for 

reporting entities’ ability and focus to provide timely and accurate emissions information to the 

Agency. 

Commenter 0132: EPA’s assertion that complete information is needed extends beyond the 

purpose of the Greenhouse Gas Reporting Program (GHGRP) and the original intent of Subpart 

W. 

GPA understands that the onshore natural gas gathering and boosting (ONGGB) industry 

segment was included in the original Subpart W proposal. GPA also understands that there 

currently is a data gap in GHG reporting without this industry segment. However, in the 

preamble, EPA states “[t]hese proposed revisions, which address this petition, are consistent with 

the EPA’s intent to ‘collect complete and accurate facility-level GHG emissions from the 

petroleum and natural gas industry’ (79 FR 74484, November 30, 2010) and to provide accurate 

and transparent data to inform future policy decisions.”6

 GPA notes that EPA’s intent in 

designing Subpart W was to collect emissions information from the largest sources contributing 

to approximately 80% of the emissions from each industry segment.7 This rationale explains why 

EPA does not require all possible emitting equipment to report in each industry segment. 

However, in this proposal, EPA provides no evaluation of which emission sources contribute to 

80% of emissions from the ONGGB industry segment, and instead EPA has chosen to include 

every possible emission source for which a data collection method is defined in Subpart W. 

GPA has long struggled to understand EPA’s goals for collecting the GHGRP data considering 

the extremely labor intensive data collection efforts (for example the thousands of direct 

measurements from compressors which were hardly discussed in the EPA Compressor White 

Paper). GPA supports informed data collection, but with shifting goals and unclear intended uses 

for the data to be collected, GPA cannot endorse collection of data merely because the equipment 

type can be found within an industry segment. We do not support the notion that the GHGRP 

was intended to collect 100% of available emissions information for an entire industry segment, 

as supported by the April 12, 2010 proposed rule. In the following comments, we propose 

eliminating costly and unnecessary data collection efforts that GPA considers unreasonably 

burdensome. 

Footnotes: 

6

 Proposed Rule at 73,151. 

7

 Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems, 75 Fed. Reg. 

18,608, 18,614 (Apr. 12, 2010). 
161 

Commenter 0132: Blowdown vent stack reporting requires continuous data collection, which 

requires extensive training, personnel time, and recordkeeping. 

Unlike other equipment types that involve an annual equipment survey, whenever a blowdown 

occurs, it must be evaluated and documented. This means that data must effectively be collected 

continuously. Blowdown tracking must involve field operators tracking every single blowdown. 

Training every operator in a company to evaluate blowdown events, document the results, 

determine if they should be reported under Subpart W (including evaluating and documenting 

physical volume), maintain the proper records, and transfer the records to the GHGRP 

coordinator is overly burdensome. 

Commenter 0141: The Proposed Subpart W Revisions would impose on the oil and gas industry 

a number of unnecessary, costly, and burdensome monitoring, data collection, and reporting 

requirements, many of which would not improve the quality of the GHG data EPA seeks. Those 

new regulatory burdens would be in addition to both a number of recently promulgated 

regulations specific to the oil and gas industry (e.g., the recent amendments to 40 C.F.R. Part 60, 

Subpart OOOO) and the recently announced proposal to adopt methane regulations tailored to 

that industry. Moreover, the Proposed Subpart W Revisions would be the ninth (9th) revision of 

Subpart W since its original promulgation in late November 2010. The constant amendment to 

the Subpart W regulations, and the flurry of promulgation of other oil and gas industry specific 

regulations, creates regulatory uncertainty and does not provide industry adequate time to adapt 

monitoring, recordkeeping and reporting systems to the constantly changing regulatory 

requirements. EPA should either not adopt or should delay adoption of the Proposed Subpart W 

Revisions. 

Commenter 0141: Many of the data elements that the Proposed Subpart W Revisions would 

require be gathered and reported are not relevant to the emission calculation methods employed 

in the regulation and should not be part of the Proposed Subpart W Revisions. For example, data 

regarding the number of tanks in a sub-basin, the number of tanks within a sub-basin with vapor 

recovery units and flares, and the number of tanks that are controlled/uncontrolled within a subbasin are not relevant because the number of tanks in a sub-basin is not used to calculate 

emissions under Subpart W. The requirement to include such data also fails to recognize the 

practical realities of oil and gas field operations. The number of tanks may be variable during 

any given calendar year depending on production, product demand, access to pipelines or trucks 

and other factors. 

The increased burden of expanding reporting data and elements reduces efforts to find innovative 

technologies to increase accuracy and efficiency in operations. EPA should reconsider the 

addition of data elements to report in this rulemaking, particularly those that do not pertain to 

emission calculations. EPA should only require reporting of emissions calculation “value added” 

information. 

Commenter 0142: Due to Kinder Morgan’s extensive natural gas pipeline network and sizable 

number of facilities providing natural gas transmission, storage, and processing services on a 

continuous basis, Kinder Morgan has a large number of facilities triggering GHG reporting and 

monitoring. In fact, Kinder Morgan’s monitoring and reporting alone has resulted in the 
162 

collection of thousands of data inputs over the last four (4) years. EPA indicates that the 

Proposed GHG Reporting Rule is intended to “enhance the quality of data from petroleum and 

natural gas systems gathered through Part 98.” See 79 Fed. Reg. at 73,150. Kinder Morgan 

understands and respects the need for accurate and quality data gathering. Kinder Morgan 

respectfully requests, however, that EPA thoughtfully consider how EPA can utilize and evaluate 

existing data already collected for major sources and emitters at facilities to fill data gaps, if any 

exist. In many instances, future and additional data gathering may not prove to be cost-effective 

and may, in some circumstances, be duplicative of existing data. In fact, Kinder Morgan submits 

that EPA significantly underestimates the overall annual burden to be assumed by operators as a 

result of the Proposed GHG Reporting Rule – particularly during the initial reporting year, which 

will require substantial start-up costs to develop data collection and management programs and 

train personnel for newly designated source categories. Kinder Morgan respectfully requests 

EPA consider the impacts of these burdens on operators in an effort to balance meaningful data 

gathering with cost-efficiency and necessity. 

Kinder Morgan remains committed as always to working with EPA, industry, and other 

stakeholders to identify environmentally beneficial, cost-effective, and feasible mechanisms 

related to reporting requirements and the development of necessary GHG emissions data. 

Response 1: The EPA appreciates the commenters’ concerns 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. Section 114(a)(1) of the CAA 

provides the EPA broad authority to require the information to be gathered by this rule because 

such data would inform future greenhouse gas policy and improve the verification of reported 

emissions. Such authority is not circumscribed by direct relevance to emissions or emission 

calculation. 

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: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 28 

Comment 2: GPA does not understand how EPA’s estimate of 200 ONGGB respondents was 

derived. 

In the Assessment of Impacts, EPA states that “[a]ccording to the Office of Pipeline Safety 

(OPS), there are 400 natural gas gathering pipeline operators under regulation by OPS. OPS 

estimated that 50% of these operators are potentially subject to the new regulation (depending 

upon proximity to population centers), resulting in approximately 200 reporters.” Further, in the 

Supporting Statement, Appendix B, footnote “e,” EPA states; “[a]ssuming that 50% of the 400 
163 

natural gas gathering pipeline reporters are large diameter, high pressure lines potentially subject 

to regulation.” GPA fails to understand how “proximity to population centers,” pipeline 

diameter, or pipeline pressure relate to rule applicability. If an ONGGB facility is aggregated 

across a county or a basin, it is more likely that combustion emissions will exceed reporting 

thresholds long before pipeline blowdown emissions come close. In addition, EPA estimates that 

the number of reporters under the Onshore Natural Gas Processing industry segment will total 

291 reporters. GPA wishes to point out that by the nature of the industry, any company with a 

processing plant will most likely also have an associated gathering system subject to reporting, 

therefore the number of reporters in the ONGGB industry segment will total 291, at minimum, 

but potentially more. 

Response 2: The EPA disagrees with the suggested change to the number of reporters in the 

Onshore Petroleum and Natural Gas Gathering and Boosting segment. See Section IV of the 

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

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 11-12 

Comment 3: The Proposed Rule and supporting documents do not adequately consider 

perceived benefits or costs. In Appendix B of its Supporting Statement, EPA estimates that there 

are 150 reporters for Onshore Natural Gas Transmission Pipeline facilities. However, INGAA 

asserts that there are actually 183 reporters representing approximately 234,156 miles (out of a 

total of 302,813 of transmission miles regulated by PHMSA).11 INGAA bases this figure on the 

number of operators that are required to complete a PHMSA annual report (PHMSA F-7100-2) 

or are regulated by FERC under Section 311 of the NGPA. 

Footnotes: 

11 See Appendix B, Supporting Statement, EPA-HQ-OAR-2014-0831. 

Response 3: The EPA agrees with the suggested change to the number of reporters in the 

Onshore Natural Gas Transmission Pipeline segment. See Section IV of the preamble to the final 

rule for additional discussion responding to this comment. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 2, 39-41 

Comment 4: GPA has included an Appendix to its comments, which outlines the cost estimates 

GPA believes are associated with the proposed rule. 
164 
165 
166 
167 

EPA's GHG Mandatory Reporting Rule (Proposed Subpart W) 

Gas Processing Plant and Booster Station Cost Assumptions 

Table 1. Booster Stations 

General 

Number of Booster Stations based on EPA count of gathering compressors in the Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-2012 

3 compressors per station 

Spreadsheet estimates Year 1 through 3 costs 

Pneumatic Pumps and Devices 

Assume that the inventory of pneumatic devices is spread over 3 years as is allowed in the rule 

Inventory labor includes travel to and from the booster site 

Assumes that more than one site will be visited per trip 

Assume that the pneumatic pump inventory will be done while on site for pneumatic device inventory 

Acid Gas Vents 

10% of booster stations have acid gas treatment 

Outlet gas requires sampling 

Assume inlet gas is currently being sampled 

Sampling includes travel to and from booster station 

Dehydrators 

Assume 1 dehy per booster station 

Assume 10% of dehys not currently being modeled for other compliance requirements 

Feed gas extended analysis, feed gas water content and dry gas water content require sampling 

Sampling labor includes travel to and from the booster station 

Blowdown Vent Stacks 

Includes training to ensure consistent determination of equipment volumes and tracking of blowdowns 

Assume one operator for every four sites 

Storage Tanks 

Costs for tank modeling are based on 1 tank per booster station and a half hour to model each tank 

Assume that 75% of tanks will require modeling 

Assume half modeled by third party at $400 each 

Sampling costs are based on 1 separators per booster station 

Costs for a pressurized hydrocarbon sample, run lab extended analysis and lab report can vary 

A value of $1,000 is applied for the separator analyses 

Includes training to ensure consistent determination of equipment volumes and tracking of blowdowns 

Assume one operator for every four sites 

Flares 

20% of booster stations have flare 

Labor includes time to determine flare gas rate, representative gas sample, and flare efficiency 

Centrifugal Compressor 

No centrifugal compressors used for gathering 

Reciprocating Compressor 

Inventory management cost has been applied to this category 

Assume 3 compressors per booster station 

Fugitive Emissions 

Inventory management cost has been applied to this category 

Gathering Pipeline Fugitive Emissions 

Cost assumes that the reporting burden is spread amongst the basin 

EPA's assumption of 8 booster stations per basin was used 

Gathering pipelines have to be “assigned” to a basin for reporting 

Combustion 

Assume all booster stations in ONGGB industry segment will require combustion calculations 

Assume one meter per booster station 

Assume use of new calculation methodology for this industry segment 

Data Management 

Assume data management system exists, requires modifications for Subpart W reporting 

Reporting and Compliance Management 

Costs based on individual booster station costs 
168 

Response 4: All burden estimates in the commenter’s Table 1, except for Gathering Pipeline 

Fugitives, Storage Tanks, and Combustion, are also applicable to the Onshore Natural Gas 

Processing segment. It is not clear whether the estimates are based on reporters that would be 

subject to the new Onshore Petroleum and Natural Gas Gathering and Boosting segment or 

reporters that are currently subject to the Onshore Natural Gas Processing segment. As discussed 

in Section IV.B of the preamble to the final rule, the two segments are defined differently and 

reporters that are subject to one segment will not necessarily be subject to the other segment. 

The commenter also asserted that “[n]o centrifugal compressors [are] used for gathering.” 

According to an April 2013 article about gathering systems, screw, reciprocating and centrifugal 

compressors are the most common types and centrifugal compressors are “best used for 

applications with stable large gas flow rates and low to moderate pressure boost.”2

 Therefore, 

while the commenter’s operations may not include centrifugal compressors, some operations in 

the Onshore Petroleum and Natural Gas Gathering and Boosting segment are expected to have 

centrifugal compressors, and these should be included in the Onshore Petroleum and Natural Gas 

Gathering and Boosting facility where they exist. 

Also, it is not clear whether the estimates are based on an average of multiple reporters or a highend estimate, which could determine whether the assumptions should be applied differently 

based on the size of the reporter. 

Unfortunately, for the above reasons, the commenter has not provided enough information for 

the EPA to apply the commenter’s estimates to the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. 

The cost estimates in the economic and impacts analysis for subpart W were based on the best 

available information and are consistent with cost estimates for all other industry segments that 

are already subject to subpart W of Part 98, including the burden estimates related to storage 

tanks and combustion. The only example provided by the commenter that is specifically related 

to gathering and boosting is for Gathering Pipeline Fugitives. The burden estimate related to 

determining the miles of gathering pipeline is based on the burden for counting pieces of 

equipment in industry segments that are already subject to subpart W of Part 98. 

Without more detailed citations or support, there is no justification for changing the proposed 

costs related to the above data collection activities. 

Commenter Name: Public Hearing: Karin Ritter 

Commenter Affiliation: Public Hearing: American Petroleum Institute 

 

2

 “Gathering and Processing Design Options for Unconventional Gas” by K.A. Lawlor and M. Conder in Hart 

Energy Midstream Business, Vol. 3, No. 4, April 2013. 
169 

Comment Number: EPA-HQ-OAR-2014-0831-0055-B 

Page(s): 19-22 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 5 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 6-7 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 7 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 21 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 29 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 31 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 7-8 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 9 

Commenter Name: Pamela F. Faggert 

Commenter Affiliation: Dominion Resources Services, Inc. 
170 

Comment Number: EPA-HQ-OAR-2014-0831-0133 

Page(s): 9 

Commenter Name: Gretchen C. Kern 

Commenter Affiliation: Pioneer Natural Resources USA, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0134 

Page(s): 3-4 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 2 

Commenter Name: C. William Giraud 

Commenter Affiliation: Concho Resources Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0141 

Page(s): 4 

Comment 5: Commenter 0055-B: API is concerned that the newly proposed requirements pose 

an especially high burden on the industry sector. The EPA estimates that approximately 3,300 

respondents will be subject to the regulation, and that this rulemaking will increase labor costs 

for Subpart W facilities by levying an incremental annual burden of 73,000 hours, valued at $7.2 

million per year, estimates which are extraordinarily slight compared to the real-world 

experience of the industry. 

More specifically, the reporting burden estimated by EPA for the newly defined reporting 

segment of Onshore Petroleum and Natural Gas Gathering and Boosting is grossly 

underestimated. Based on API’s members’ experience in reporting under Subpart W, this 

estimate is arbitrarily low by at least an order of magnitude, especially for the initial reporting 

year when one has to address the startup costs for setting up the reporting and recordkeeping 

systems for this newly defined segment. 

For the onshore petroleum and natural gas production segment, EPA states in its own assessment 

that the proposed reporting amendments would impose an additional annual burden of 57,963 

technical hours for the production segment, which API contends is also underestimated. 

API maintains that EPA’s estimate is highly unrealistic since it would mean that the increased 

annual burden for implementation of the new reporting requirements for the production segment 

would amount to only 29 hours per response, which is totally unrealistic, especially in view of 

the extent of the new data collection and measurements required for implementation. 

So, for example, the inclusion of reporting requirements for blowdown vent stacks for the 

gathering and boosting segment will be quite burdensome for unmanned sites. The EPA 

Technical Support Document justifies using default emission factors for quantifying fugitive 

emissions associated with the gathering and boosting segment, quote, because, as in the onshore 

petroleum and natural gas production segment, the equipment is often geographically dispersed 

and may be visited only intermittently, end of quote. 
171 

For this same reason, EPA should exclude the reporting of emissions from blowdown vent stacks 

for gathering and boosting segment, similarly to its exclusion from the onshore petroleum and 

natural gas production segment. 

API urges the EPA to work with industry to streamline the reporting requirements in order to 

minimize the heavy burden imposed on some of the petroleum and natural gas industry 

segments. 

Commenter 0125: The increase in meter installation and recalibrations that would be required 

due to the inclusion of completions and workovers of oil wells with hydraulic fracturing and the 

two newly proposed segments will significantly increase the efforts and costs of compliance. The 

applicable elements of Subpart W are spread out over very large geographical regions. The 

mobilization man-hours and associated costs need to be factored into the overall cost impact of 

the amendments. The availability of not only the meters, themselves, but also the contractors 

needed to perform the installations and calibrations is unknown. Furthermore, if liquid and/or gas 

compositional data are required for calibrations, more contactors will need to be hired to 

properly gather and analyze the samples. Securing contractors for the purpose of meter 

installation/calibration throughout a basin will take several years to fully implement. 

Commenter 0125: The proposed rule, with the expansion of oil wells completed with hydraulic 

fracturing and the addition of the two new reporting segments, adds a large number of additional 

data collection and reporting requirements that will be unduly burdensome for the regulated 

community, as well as costly and difficult to implement. 

The majority of resources (e.g., cost, time, and efforts) are associated with gathering and 

documenting required data under the regulation. A typical operator currently reporting for the 

production segment that has gathering and boosting operations is estimated to more than double 

its current level of effort, including the time and materials needed to set up and implement 

systems for sources that previously were not required to be reported under the current Subpart W 

rule.2 Based on Alliance members’ experience, EPA vastly underestimated, by at least an order 

of magnitude, the amount of time necessary to accommodate the new reporting obligations as 

proposed. For example, if a consultant was hired to gather and report the information on behalf 

of a regulated entity, a large process would need to be implemented. This process includes: 

1. Developing new processes and creating or modifying software to collect the required 

information 

2. Updating monitoring plans 

3. Conducting training for persons responsible for collecting and reporting data 

4. Auditing new data elements for accuracy 

5. Revising reporting processes and updating data management software 

6. Preparing and reviewing expanded annual reports 

7. Documenting and archiving data used for reporting. 
172 

The level of effort could easily total 1,000 to 1,500 man-hours or more across the three segments 

(production plus the two newly proposed segments). Assuming a labor consulting costs of 

$150/hr, the initial investment would be between $150,000 and $225,000. This estimate does not 

even include the expected additional costs for such items as conducting site-specific inventories, 

gathering and analyzing oil or gas samples, installing/calibrating flowmeters. 

Data reported under the GHG emissions reporting 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 accessed, 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 than the EPA estimate of 113 hours per 

respondent, by at least an order of magnitude, especially during the initial implementation of data 

gathering and reporting of the associated amendments. 

Footnotes: 

2

 Operator-provided Alliance member estimate that the number of sources that would require 

evaluation and potentially be reported under the gathering and boosting segment would increase 

112% compared to the current number of sources reported for the production segment. 

Commenter 0125: In the very least, we urge EPA to recalculate compliance and implementation 

dates for the proposed rules in light of the significant man-hours that will be required to 

implement the proposed data additions and changes to calculation methodologies. 

Commenter 0132: According to Appendix B of the Supporting Statement, it appears that EPA 

estimates there are eight tanks per reporter. With EPA’s estimated 200 reporters, this yields a 

total of 1,600 tanks. GPA estimates that there are several thousand tanks in the ONGGB industry 

sector, if not tens of thousands. Just one GPA member company has over 1,000 atmospheric 

pressure fixed roof storage tanks. 

Commenter 0132: EPA’s cost and time estimates are extremely low. 

EPA stated in the preamble that, “[t]he proposed amendments to subpart W are not expected to 

significantly increase burden.” We respectfully disagree and believe the proposed rule is very 

expansive and burdensome as written. As demonstrated below, EPA’s estimates of burdens and 

costs are extremely low and the compliance burden is much more than EPA has estimated. EPA 

estimates that there are three gathering and boosting compressor stations per processing plant 

(plus one compressor station downstream of gas treatment). This estimate is low, but even still, 

this means that for each gas processing plant, there is a threefold increase in the number of 

facilities that need to be tracked plus all the pipeline associated with those facilities. Under the 

proposed rule, one GPA member estimates going from reporting 60 gas plants to reporting 900 

compressor stations plus the entire pipeline system associated with those compressors stations. 

Without looking at any other numbers, this information alone is enough to realize this rule, as 

proposed, will be a very significant increase in burden; therefore, we ask EPA to implement the 

many suggested revisions to significantly reduce the compliance burden. 
173 

Commenter 0132: EPA’s estimate of total respondent time is significantly underestimated and 

unreasonable. 

Section 6(a) states that the total annual burden to all affected entities is 63.4 hours per year. We 

urge EPA to reevaluate this determination. It is not reasonable to assume that it would that it will 

take a reporter just eight business days to: review the rule; understand the rule; develop training 

materials; train all affected personnel; develop a budget; hire and schedule contractors where 

needed; evaluate facility applicability; update the monitoring plans; develop recordkeeping 

systems; collect all the data; collect and analyze gas samples; perform all the calculations; run all 

software simulations; QA/QC all the raw data and calculated results; determine if there was any 

missing data; format all the data into the correct reporting form (which can include XML 

programming); and review the final reports with the certifying official. 

Even for the smallest entity that would only submit one report (as EPA incorrectly assumes all 

reporters to be), this is an unreasonable estimate. If a one-hour training session was held with 8 

people, it would use up 1/8 th of the total estimated time. Due to staff turnover, nearly none of 

these requirements is a “one-time only” requirement. Reading and understanding the rule and 

training personnel are ongoing tasks. According to Appendix D of the Supporting Statement, 

EPA estimates the total time burden for ONGGB to be 9,297 hours for 200 reporters, which is 

just 46.5 hours per reporter – or just six business days. EPA should revisit and revise these 

inaccurate time estimates. We believe that several orders of magnitude increase in time is 

warranted, if not more. Many Subpart W reporters and GPA members have full time staff whose 

job, sometimes year-round, is managing the GHGRP. These positions do not generate revenue 

for the company and they only exist because it is not possible to meet the regulatory 

requirements otherwise. GPA assures EPA that these positions would not exist if it truly only 

took one full time employee a week and a half to comply with this rule. 

Commenter 0133: The additional reporting requirements for “atmospheric storage tanks” under 

the proposed rule for the Gathering and Boosting segment may be substantial. Reporters must 

conduct a full inventory of all produced fluid tanks within the Gathering and Boosting segment 

for our two affected business units. Next reporters must determine whether or not the tanks are 

considered “atmospheric”. Then, reporters must determine daily oil/condensate throughput into 

each tank to understand which tanks exceed the ten (10) barrels per day (bpd) threshold. Fourth, 

reporters must determine whether or not tank gases are vented to a flare or other control device. 

And finally, based on the above, reporters must calculate methane and carbon dioxide emissions 

using the appropriate equation(s) (of three methods) specified in the rule depending upon 

whether the tank throughput is greater than or equal to 10 bpd. 

Conducting a full inventory, including characterizing the type and amount of fluids passing 

through each tank daily, is a daunting task. Other regulatory requirements for volatile organic 

compound emissions and spill containment require us to identify and track select information for 

affected large volume tanks, but information required by the proposed rule on all fluids tanks is 

not currently available. 
174 

Commenter 0133: Determining whether or not each tank vents to a control device is an added 

step in the inventory process. This is further complicated by having to adjust emission estimates 

based on control efficiencies. 

Commenter 0133: For blowdown vent stacks, EPA proposes that the Gathering and Boosting 

segment blowdown emissions be reported according to the current rule, with the expanded 

blowdown event categories that became effective on January 1, 2015. These categories include 

planned or emergency shutdowns and equipment maintenance and repairs. The same 

exemptions, including those for volumes less than 50 cubic feet and for desiccant dehydrator 

reloading, are applied to the Gathering and Boosting segment. The EPA states in the preamble 

that the exemptions should alleviate any concerns with the burden of calculating emissions from 

small gathering pipelines. Nevertheless, reporters still will need to conduct an inventory of all 

pipeline and equipment measurements to characterize blowdown volumes to determine which 

areas fall below the 50 cubic feet exemption level. Each “unique physical volume between 

isolation valves”, as defined in the rule, along more than 5,400 miles of gathering pipeline and 

93 gathering compressor stations will take some time to establish. We are currently evaluating 

the potential resources and time required to implement these new requirements within the 

proposed timeframe, but believe it will be a substantial effort. 

Commenter 0134: With the expansion of oil wells completed with hydraulic fracturing and the 

addition of the new gathering and boosting segment, this rule adds a large number of additional 

data collection and reporting requirements. The majority of cost, time and efforts are associated 

with gathering and documenting required data under the regulation. Although considered, EPA 

has vastly underestimated the amount of time that is needed in order to modify data collection 

and management and update reporting systems and processes. Data reported for the rule is 

compiled from a number of different systems and the addition of each new data element will 

require an evaluation of where the data can be accessed, how it can be integrated into the current 

data management systems and processes, and how it can be recorded into existing raw data 

reporting formats. This process will take additional man-hours per data element, and based upon 

Pioneer’s historical/previous reporting experience, vastly more than EPA has estimated in its 

technical documents supporting this rule, especially during the initial implementation of data 

gathering and reporting of the associated amendments. Therefore, Pioneer urges EPA to reevaluate the man hours that will be required to implement the proposed data additions and 

changes to calculation methodologies and current data management systems in place in 

determining compliance and implementation dates.

Commenter 0137: EPA has significantly underestimated the level of effort for reporting 

emissions associated with the newly defined Gathering and Boosting segment, reporting 

emissions for oil well completions and workovers, and has totally disregarded the burden 

associated with the requirement to report Well ID numbers. API recommends that EPA carefully 

consider the comments below which provide opportunities for reducing the reporting burden 

without compromising data completeness and accuracy. 

Commenter 0141: EPA has significantly underestimated the amount of time that will be required 

to modify data collection, management, and reporting systems to comply with the Proposed 

Subpart W Revisions. To compile the numerous categories of data that would need to be reported 
175 

to comply with the Proposed Subpart W Revisions, operators and producers will need to evaluate 

whether such data points are already being collected, where the data can be accessed or how it 

can be collected, how the data can then be integrated into current data management systems and 

processes, and how it can be integrated into existing raw data reporting formats. This process 

will require extensive coordination among field operations, third parties, IT staff and others. The 

total time to develop compliant data compilation and reporting systems will be significantly 

greater than the EPA estimate of 113 hours per respondent. 

Response 5: The commenters offered general information, such as the costs were “significantly 

underestimated” or “inaccurate” or that the level of effort should total “1,000 to 1,500 man-hours 

or more across the three segments.” However, without specific burden information, including the 

amount of time required for each activity and the number of reporters expected to conduct each 

activity, the EPA is unable to apply their comments to this rulemaking. The cost estimates in the 

economic and impacts analysis for subpart W were based on the best available information. 

Without more detailed information, there is no justification for changing the proposed costs 

related to the above data collection activities. 

Regarding Commenter 0132’s comment on time allowed for training, see Response 17 in this 

section. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 11 

Comment 6: For blowdowns, EPA estimates that there will be eight blowdowns per year per 

facility (one per ONGGB compressor station within a basin) and it will take eight minutes to 

perform each calculation.13 Setting aside EPA’s inaccurate estimate of the number of ONGGB 

compressor stations per facility, EPA’s estimate of just one blowdown event in an entire year at 

an ONGGB compressor station is unrealistic. 

A more reasonable estimate for one compressor station is 24 blowdowns per compressor, 12 

blowdowns from filter/strainer opening, four other blowdowns for routine maintenance, and one 

pipeline blowdown within the fenceline. Assuming EPA’s estimate that there is an average of 

three compressors per compressor station is accurate,14 this results in 89 blowdowns per year. 

Note that while some of these blowdowns may be less than 50 cubic feet physical volume or 

meet another exemption provided in section 98.233(i), each blowdown must be evaluated to 

determine if this is the case, so some time is required for every blowdown. This results in (8 

compressor stations x 89 blowdowns x 8 minutes x 200 reporters)/ 60 min/hr = 18,987 hours, 

compared to EPA’s estimate of 213.3 hours. To calculate total increased costs, GPA used EPA’s 

hourly engineer labor rate from the Supporting Statement of $78.29,15 and determined that the 

estimated costs significantly increased from $16,702 to $1,486,466. 

Footnotes: 
176 

13 Supporting Statement: Environmental Protection Agency--Greenhouse Gas Reporting Rule: 

2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; 

Proposed Rule (40 CFR Part 98, subpart W), Appendix B at note j, Docket No. EPA-HQ-OAR2014-0831-0013 (Nov. 2014), http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR2014-0831-0013 (Supporting Document). 

14 Id., Appendix B at note k. 

15 See id. at 15. 

Response 6: The EPA used the GHGRP data in determining the average number of blowdowns. 

Based on RY2014 data for the Onshore Natural Gas Processing industry segment, there were an 

average of eight blowdowns per facility. With no indication that the number of blowdowns will 

increase significantly in future years, the EPA disagrees with changing the number of 

blowdowns at Onshore Petroleum and Natural Gas Gathering and Boosting facilities that were 

assumed at proposal. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 13-15 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 26 

Comment 7: Commenter 0132: Tank emissions tracking and calculations is very burdensome 

and is not justified in the proposed rule or supporting materials. 

The Technical Support and Assessment of Impacts do not discuss the storage tank requirement 

for the ONGGB industry segment. Other than one small line item in Appendix B of the 

Supporting Statement, there is no discussion on the implementation of this burdensome reporting 

requirement for the ONGGB industry segment. It is unreasonable for EPA to include this 

burdensome requirement without justifying the need for the data and adequately discussing the 

burden associated with this requirement. 

Annual tank specific data would be required for every single tank in the ONGGB industry 

segment. 

For the thousands of tanks in the ONGGB industry segment, reporters would need to assess tank 

throughput data (see comments below related to concerns about “separators” and separator 

throughput). While this data is usually available as a normal course of business, EPA should 

assume it takes at least 10 minutes per tank per year to locate the data, QA/QC it, evaluate it, and 

retain a record. Nearly all compressor stations in the ONGGB industry segment will have at least 
177 

one condensate or produced water storage tank. EPA provides no justification of why this 

massive data collection effort is necessary or appropriate for this industry segment. 

EPA underestimates that there are eight tanks per reporter. 

GPA believes that the number of tanks per reporter is significantly under estimated and is at least 

an order of magnitude higher. 

Additional tank specific data would be required for an unknown portion of tanks in the ONGGB 

industry segment. 

If Calculation Methods 1 or 2 are required, other operating data would need to be collected 

annually for each tank such as operating pressures and temperatures, which would require 

reporter time and a visit to each site. For some tanks, a liquid sample would be required to 

perform the calculation, so a site visit would be needed to take the sample, and time would be 

required to send the sample to the lab. Again, EPA provides no justification of why this massive 

data collection effort is necessary or appropriate for this industry segment. 

EPA estimates of burden do not account for all tasks and underestimate the burden of each task. 

For tanks, EPA estimates “1 minute per separator for technician to collect pressure data; and 30 

minutes per separator for engineer to perform simulation run.” First, EPA does not include time 

to assess tank throughput, which should be estimated at 10 minutes per tank. Second, to collect 

other operating data, EPA should estimate 20 minutes per tank. The task must be explained to the 

operator, planned into the operator’s duties, a data collection form must be created or identified, 

the data must be collected, the data must be transferred to the GHG reporting coordinator, the 

GHG reporting coordinator must store the data in a centralized location, and the GHG reporting 

coordinator must note receipt of the data. 

Third, if a condensate sample would need to be taken, EPA should estimate $1,000 for sample 

collection and analysis. Pulling samples of pressurized liquid must be planned to ensure that the 

task is completed in a safe and correct manner (without depressurizing the liquid). Additionally, 

the sample containers must be prepared and obtained, the task planned and coordinated with 

other site activities, which may involve a safe work permit, the sample taken, the sample 

transported or shipped to the lab, analysis completed, laboratory report prepared, results provided 

to the company, data entered in a centralized database, and emissions determined for subsequent 

reporting. For unstabilized condensate liquids entering a tank, the sample must be taken at the 

separator, which may not contain liquid when the operator arrives to pull the sample. This could 

add even more time to this task. 

Fourth, EPA’s assessment of 30 minutes to perform the emissions determination may be 

optimistic. We note that if running the simulation is done in house, the average cost of time and 

labor is $200; however, if the run is outsourced, the typical fee is at least $400 per run. Thus, 

total time for tanks using Calculation Method 1 or 2 is more accurately estimated at two hours 

per tank at $1000 per sample plus an additional $400 if the process simulation is outsourced. 
178 

Commenter 0132: EPA provides no estimate of time or cost associated with stuck dump valve 

tracking and reporting. 

In Appendix B of the Supporting Statement, EPA estimates 0.52 hours per tank, which is based 

on “assuming 1 minute per separator for technician to collect pressure data; and 30 minutes per 

separator for engineer to perform simulation run.” This dump valve task certainly takes time, and 

this time must be accounted for in EPA’s cost analysis. Like blowdowns, this piece of 

information requires continuous data collection, so every operator, and possibly third party 

pumpers/technicians, will need to be trained on this task. Every operator in a company will need 

to know how to inspect for dump valve issues (which many already do), but most importantly, 

they will need to be trained to document any issues, maintain the proper records, and transfer the 

records to the GHGRP coordinator. It is difficult to assess an appropriate amount of time to 

assign because this is a continuous data collection effort; GPA recommends that EPA estimate 

one hour per tank annually. Additionally, if the tank emissions are routed to a flare, then the 

emissions calculated in Equation W-16 would need to be applied to the flare calculations, and 

then this volume would need to be subtracted out of the total site flare emissions. This is a 

complex set of calculations and EPA should estimate an additional 30 minutes per tank that is 

routed to flare. 

Response 7: The requirements for storage tanks in the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment are consistent with the requirements for storage tanks in the 

Onshore Petroleum and Natural Gas Production segment. The burden required to meet these 

storage tank requirements is independent of the subpart W industry segment. The cost estimates 

in the economic and impacts analysis for subpart W are consistent with cost estimates for all 

other industry segments that are already subject to subpart W of Part 98, including the burden 

estimates related to storage tanks. Therefore, the burden estimates presented here are appropriate 

for storage tanks in the Onshore Petroleum and Natural Gas Gathering and Boosting segment. 

The commenter does not provide a new estimate of the number of tanks per reporter or how such 

a number would be determined. Without more detailed information, there is no justification for 

changing the proposed estimates. 

For stuck dump valves, the EPA requires the detection of an anomaly with the dump valves 

before any calculations are required. Therefore, only those dump valves found to not be closing 

properly (i.e., stuck dump valves) would have to be quantified using Equation W–16. While the 

reporter can choose to use any monitoring or inspection procedure to detect stuck dump valves, 

the rule does not require any “continuous data collection effort” for stuck dump valves. 

Therefore, the commenter provides no justification for changing the proposed estimates. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 18 
179 

Comment 8: Combustion Calculation Methods: EPA does not provide a detailed cost or time 

analysis to justify the use of a new calculation methodology. 

Appendix B of EPA’s supporting documentation details cost and time burden for years 1 through 

3 of reporting. However, EPA fails to provide a detailed cost estimate for the additional 

combustion reporting using new methodologies for the source category. 

Response 8: For Onshore Petroleum and Natural Gas Gathering and Boosting, the capital and 

operation and maintenance (O&M) costs associated with combustion emissions were based on 

the assumptions in Regulation to Establish Mandatory Reporting of Greenhouse Gases (Final 

Rule for Petroleum and Natural Gas Systems, Subpart W). See the memorandum Assessment of 

Impacts of the 2015 Final Revisions to Subpart W in Docket ID No. EPA-HQ-OAR-2014-0831. 

Commenter Name: C. William Giraud 

Commenter Affiliation: Concho Resources Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0141 

Page(s): 3 

Comment 9: The requirement to install a flow meter on every well completed with hydraulic 

fracturing, calibrate those meters, and collect the necessary data will significantly increase costs 

and time for compliance. The mobilization man-hours and associated costs need to be factored 

into the overall cost impact of the amendments. Furthermore, if liquid and/or gas compositional 

data is required for calibrations, more contactors will need to be hired to properly gather and 

analyze the samples. Securing contractors for the purpose of meter installation/calibration 

throughout a basin could take years to fully implement. 

Response 9: Mobilization man-hours were included in the cost estimates. Travel costs were 

included and assumed to consist of 14 overnight trips per reporter per year. Calibrations would 

be performed as part of the measurement process. 

The commenter has not provided enough specific burden information related to potential 

additional contractor costs for EPA to make changes to the proposed costs. The cost estimates in 

the economic and impacts analysis for subpart W were based on information gathered through 

the GHGRP. Without more detailed information, there is no justification for changing the 

proposed costs related to the above data collection activities. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 31-32 

Comment 10: EPA’s proposed rule is also arbitrary and capricious because it significantly 

underestimates the data collection and reporting burdens that will be imposed on regulated 
180 

entities in the oil and gas sector. In implementing the GHG reporting program, EPA cannot 

simply operate with the assumption that more data is always better. At some point, the additional 

information that could be requested by EPA is redundant and subject to diminishing returns, 

whereby the additional costs associated with collecting more data simply cannot be justified 

based on the limited new information that can be gleaned from collecting more data. In order for 

regulated entities, the general public, and, if necessary, the courts, to appropriately weight the 

benefits and burdens of additional data reporting, it is essential that EPA accurately report the 

costs and benefits of its proposal in the administrative record. Here, EPA has significantly 

underestimated the costs associated with several key aspects of the proposed revisions. In doing 

so, EPA has essentially mislead the public and created the risk that the public will support ever 

expanding reporting obligations without fully understanding the regulatory burden associated 

with each incremental piece of information sought by EPA. 

For example, for onshore petroleum and natural gas production, EPA projects a total regulatory 

burden of 57,963, or 53.52 hours per reporting entity. EPA, Impacts Memo at 10. In doing so, 

EPA appears to assume that the total number of reporting entities will increase by 5%, but adds 

no additional costs for existing reporters who may face new obligations related to completions 

and workovers of oil wells with hydraulic fracturing. Thus, contrary to EPA’s projected burden 

of approximately 50 additional hours per respondent, API’s members estimate that the additional 

burden may be as much as 300 hours per year if the rule is finalized as proposed. Even if all of 

API’s suggested improvements were included, the additional burden would be at least 200 hours 

in the first year (if necessary tracking systems need to be implemented) and would remain at 50-

100 hours per respondent per year on an ongoing basis. The justification of these additional 

obligations is significantly diminished if the full implementation costs are considered. 

Likewise, EPA’s burden estimates for Petroleum and Natural Gas Gathering and Boosting are 

highly misleading. EPA assumes a total burden of approximately 9,000 hours, with an average 

annual burden of slightly less than 50 hours per reporting entity per year. EPA, Impacts Memo at 

10. Again, EPA severely underestimates the costs of implementing this program. API members 

suggest that initial burdens may be as high as 2,000 hours per year, while burdens in subsequent 

years will fall to 1,000 hours and eventually to 500 hours per year. Even the lowest estimates are 

an order of magnitude higher than EPA’s projections. Again, these dramatically different cost 

estimates call into question EPA’s assertions that the costs of the proposed rule are justified by 

the regulatory benefits. Hence, EPA would have to demonstrate that the proposed rule would 

lead to substantially higher regulatory benefits in order to justify the burden imposed by the 

proposed GHGRP revisions. 

Rather than relying on regulatory burden estimates that have proven to be wildly inaccurate, API 

urges EPA to reach out to members of the regulated community now and before any additional 

regulations are proposed or promulgated to ensure that cost estimates provided to the public 

reflect the reality of the industry practice. Without such assurances, the public cannot fill its 

critical role of reviewing and providing substantive comments on EPA’s proposed rules in order 

to provide constructive feedback that improves the rulemaking process and the Agency risks 

misleading the public regarding the costs and benefits of such additional information. Such an 

approach is particularly necessary here to ensure that the public is fully informed of the potential 

impacts of EPA’s proposed rules. 
181 

Response 10: During the proposal process, costs were estimated for existing reporters related to 

completions and workovers of oil wells with hydraulic fracturing. As shown in Appendix B of 

the Supporting Statement, there are 246 existing Onshore Petroleum and Natural Gas Production 

facilities in oil sub-basins where hydraulic fracturing is occurring. 

At proposal, the total burden of 57,963 hours was mistakenly applied to a total of 1,083 reporters 

(1,033 existing reporters plus 50 new reporters), resulting in an average hourly burden of 53.52 

hours per reporter. However, the total burden of 57,963 hours should have been applicable only 

to the number of reporters affected by this rulemaking, which is 296 reporters (246 existing 

reporters and 50 new reporters that are expected to report completions and workovers for oil 

wells with hydraulic fracturing). Therefore, the average burden per affected reporter at proposal 

should have been 195.82 hours for three years, which is more consistent with the estimates that 

the commenter provided for the first year costs. The memorandum Assessment of Impacts of the 

2015 Final Revisions to Subpart W in Docket ID No. EPA-HQ-OAR-2014-0831 reflects the 

correct average annual hourly burden of 195.82 hours per reporter. 

The commenter suggested 250 hours per year in the first year and 100-150 hours in subsequent 

years. The EPA believes that the corrected average annual hourly burden of 195.82 hours per 

reporter per year is consistent with the estimates suggested by the commenter. Therefore, no 

changes have been made to the burden estimates. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 20 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 32-33 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 5 

Comment 11: Commenter 0137: EPA’s proposal to require reporting of well ID numbers is 

arbitrary and capricious because the burdens associated with collecting and reporting this data far 

outweigh any minimal benefits in data quality that EPA asserts may be provided. In the technical 

support documents accompanying the proposed rule, EPA assumes that “[well ID] numbers are 

readily available and do not require any additional data gathering or calculation.” EPA, 

Memorandum to Docket ID No. EPA-HQ-OAR-2014-0831 from Alexis McKittrick and Mark de 

Figueiredo, EPA/CCD re: Assessment of Impacts of the 2015 Proposed Revisions to Subpart W, 

at 7 (Nov. 10, 2014) (hereinafter “EPA, Impacts Memo”). As a result, EPA asserts that “this 

proposed change would not impose any additional burden and costs (beyond the additional 
182 

reporting burden...).” Id. EPA estimates that the additional reporting and recordkeeping burden – 

for all 232 additional data elements – will be 20 hours per year (10 for reporting and 10 for 

recordkeeping). 

EPA is mistaken. At present, many reporters do not currently track GHG reporting information 

by well ID number. Because reporting is conducted at an aggregate basin level, it is unnecessary 

to track most equipment by well ID number. This is particularly true in instances where multiple 

types of equipment – such as pneumatic controls – are used at different wells in a given basin or 

where equipment is moved from well to well within a basin over relatively short periods of time. 

In reality, reporting entities are expected to incur significant costs to report well ID numbers, 

both as an initial matter as such data is collected for the first time and on an ongoing basis as data 

reporting continues. The table below shows reporting burdens – on an hourly basis – for the 

API’s members on a per basin level. 

Well ID Reporting Burden – Lower 48 States, Onshore 

Year Per Basin Burden, hours 

First Year 90-100 hours 

Second Year 56-60 hours 

Ongoing 25-30 hours 

Well ID Reporting Burden – Alaska North Slope 

Year Per Basin Burden, hours 

First Year 200 hours 

Ongoing 100 hours 

As the table above demonstrates, the costs of reporting will be significantly higher than what 

EPA estimates. In particular, data estimates for the first (and possibly second) years are higher to 

account for costs associated with mapping, linking existing databases, and creating systems to 

streamline ongoing reporting. But even once these measures have been completed, the ongoing 

reporting obligations will be significant. In light of the limited and questionable benefits of 

reporting well ID numbers discussed above, these reporting burdens are excessive. 

Commenter 0137: API contends that since Well ID numbers are not necessary for reporting 

GHG emissions, the proposal to require facilities to report Well ID numbers exceeds EPA’s 

established requirement of reporting GHG emissions at the basin level (40 C.F.R. 98.238). EPA 

has clearly elected previously to aggregate emissions at a level that is necessarily broader than an 

individual well, making the identification of specific wells within a given basin irrelevant for 

purposes of calculating and reporting GHG emissions. 

Furthermore, as already discussed above, API believes that EPA’s proposal to require reporting 

of Well ID numbers is arbitrary and capricious because the burdens associated with collecting 

and reporting this data far outweigh any minimal benefits in data quality that EPA asserts may be 

provided. Such a requirement would merely pose a substantial reporting burden without 

impacting the quality or substance of the reported GHG emissions. 

API strongly objects to EPA’s premise that the burden of incorporating Well ID information is 

very low and view it as uninformed. The reality is that the burden for accounting for differential 
183 

mapping of Well IDs per the requirements for each of the specified data elements amounts to a 

burden that is at least one order of magnitude, or more, higher for each respondents in 

comparison with the extremely small burden assumed by EPA. 

 From data received from API members onshore operations in five almost all gas 

producing basins in the lower 48 (representing about 9,000 gas producing wells in a mix 

of tight formations; shale; coal bed methane; and some conventional), the burden for 

implementing the Well ID requirement would amount to 90-100 hours per basin from 

year 1; 50-60 hours per basin from year 2; and 25-30 hours per basin ongoing from year 3 

onwards. The first and second year estimates are higher due to costs associated with 

mapping between databases and setting up the systems to streamline ongoing reporting. 

 From data received from API members with Alaska operations (with about 1,700 

producing wells and 65 gas injection wells, in a single basin, with no pneumatic devices 

and very limited combustion sources), the burden of implementing the Well ID 

requirements would impose a burden of about 200 labor hours for year 1 for a basin, and 

100 hours from year 2 onwards. 

Commenter 0142: EPA’s Proposed GHG Reporting Rule proposes to amend 40 C.F.R. 98.236 to 

add reporting requirements for well identification numbers to improve data quality by enabling 

identification of wells. EPA suggests that the use of well identification numbers will only add ten 

(10) hours to reporting requirements for each reporter each year. Kinder Morgan respectfully 

disagrees with EPA and does not support the use of well identification numbers. The number of 

individual equipment requiring a well identifier, and the continuous reporting and certifications 

each year, would require significant resources (far beyond 10 hours a year) and would be unduly 

burdensome on operators. 

Response 11: The EPA is finalizing the well identification number reporting requirements for 

wells but not for other emission sources. 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) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 33-34 

Comment 12: API questions EPA’s rationale for these assumptions. The assumption that for the 

400 new reporters the burden for recordkeeping and reporting into e-GGRT amounts to only 10 

hours each does not withstand any reality check when compared to the actual burden posed on 

the sector. Such a burden definitely pertains to all 3,300 respondents and not just to the 

increment of 400 new respondents assumed in EPA’s ICR burden analysis. 

Response 12: This proposal only affects three segments of subpart W and there were 400 new 

reporters estimated at the time of proposal. Recordkeeping and reporting burden was calculated 

for the remaining segments during a previous subpart W rulemaking so the costs do not apply to 

all 3,300 respondents. 
184 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 33-34 

Comment 13: API finds EPA’s calculations as presented in Appendix B of the ICR Supporting 

Statement a bit confusing. EPA assumes that for each engineer hour there would be 0.10 hours of 

mid-level manager and 0.05 hours for high level managers as part of their review function. 

However, in the table that summarizes respondents’ burden EPA estimates that the total number 

of incremental hours spent per year by all respondents to include 70,917 engineers hours and 596 

technician hours and those technical hours are assumed to be accompanied by only 1,000 midlevel management hours and 500 high-level management hours. These values are inconsistent 

with EPA’s working assumption that mid-level managers’ burden and high-level management 

burden would consist of 10% and 5% of engineers’ burden, respectively. Based on EPA’s 

assumptions, the annual burden for mid-level managers ought to be taken as close to 7,000 hours 

and that of mid-level manager as 3,500 hours. Here again, EPA grossly underestimates the 

calculated burden by using exceedingly low values that negates its own assumptions. 

Response 13: According to Appendix B of the Supporting Statement, footnotes “c” and “d” do 

not apply to every activity listed, so the estimates quoted by the commenter are overestimates of 

the burden. 

The footnotes apply to 4A “Read Rule, Instructions, Guidance Documents,” 4E “Annual 

Compliance Reporting through e-GGRT,” and 5D “Recordkeeping.” The footnotes were 

inadvertently excluded from 4E and 5D. Also, footnote “d” was mistakenly listed with 4B 

“Onshore Petroleum and Natural Gas Production Facilities--Completions and Workovers with 

Hydraulic Fracturing of Oil Wells” but there is no burden associated with a Senior Manager. The 

three corrections have been made in the Supporting Statement and all affected Appendices. This 

change resulted in no changes to burden or costs. 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 12 

Comment 14: EPA has not considered the costs or the time needed to develop and 

implement a recordkeeping system to gather the latitude and longitude information for 

each blowdown at each individual location. INGAA members have approximately 200,000 

miles of pipelines. A single pipeline system of a few thousand miles could have at least 1,300 

locations (including de minimis) where blowdowns could occur or, by extrapolation, at least 

70,716 separate locations for 183 reporters. Pipeline transmission operators will need to survey 

their pipelines to determine longitude and latitude for each potential blowdown location. The 

upfront one-time cost to conduct this work is approximately $100 per location. These costs 
185 

amount to approximately $7.1 million (including de minimis facilities). If the de minimis 

facilities are excluded as proposed by INGAA, these costs would amount to approximately $4.3 

million will downs for the 183 reporters. These cost estimates far exceed the EPA estimates. 

Response 14: The proposed latitude and longitude requirements are not included in the final 

rule. See Section II.C of the preamble for more information about this change. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 28 

Comment 15: EPA’s assumption on the average reporter is inaccurate and unsubstantiated. 

In Appendix B of EPA’s technical support documents, EPA estimates large facilities have four 

centrifugal compressors and small facilities have two reciprocating compressors. GPA asserts 

that this assumption is inaccurate. Specifically, in the ONGGB sector there are only a handful of 

centrifugal compressors. The nature of centrifugal compressors does not yield themselves to the 

ONGGB industry segment. Centrifugal compressors have much less operational flexibility and 

do not yield themselves to changing loads, which makes them unsuitable for the ONGGB 

industry segment. GPA asserts that three to five reciprocating compressors is a more accurate 

estimate, with some facilities having one or two and some larger facilities at least 12 or more 

reciprocating compressors. 

EPA estimates that sites within the ONGGB industry segment have “two flare stacks per 

compression station and one per gas treatment facility.” 

While GPA acknowledges that the presence of flares at compression stations is becoming more 

common, it is inaccurate to assume that each compression station has two flares. In Table 1 of 

GPA’s comments, we assume that approximately 20% of compression sites have a flare, with 

some having none, and some having more than one. 

EPA estimates that at each gathering and boosting station has “one isolation valve/blowdown 

stack.” 

GPA states that this statement inaccurate. Due to safety considerations at each site the average 

compressor station has a blowdown valve at each station inlet and discharge. It should be noted 

that many sites may have more than one inlet per site. In addition each major piece of equipment 

on site, such as a compressor will have an individual unit blowdown. Depending on the size of 

the site this totals at least three or more blowdown stacks. 

Response 15: The EPA agrees with the suggested change to the number of flare stacks. The 

preamble to the final rule, the Supporting Statement, and the memorandum Assessment of 

Impacts of the 2015 Revisions to Subpart W have been updated to reflect that each compression 

site contains 0.2 flares rather than 2 flares per site. 
186 

To account for potential differences in Onshore Petroleum and Natural Gas Gathering and 

Boosting reporters that are not represented by GPA, the EPA maintained the assumption that 

centrifugal compressors are used at Onshore Petroleum and Natural Gas Gathering and Boosting 

reporters and made no changes from proposal. 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 29 

Comment 16: GPA wishes to reconcile the gap between EPA’s assumptions and the information 

contained in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990- 2012. 

In the inventory document EPA states that across the North East, Midcontinent, West Coast, 

Gulf Coast, and Rocky Mountain regions, combined, there are 35,930 small compressors and 

136 large compressors. This totals 36,066 compressors. If GPA uses EPA’s assumption of three 

compressors on average per site, this will total 12,022 sites. Using EPA’s assumption of eight 

compression sites per basin, GPA calculates that there are 1,502 basins that will be reported. 

Again, if GPA uses EPA’s assumption of one basin per reporter then GPA calculates that there 

will 1,502 reporters. 

Response 16: There are differences in coverage between the GHGRP and the Inventory. In 

many cases, the definitions of sectors and industry groupings in the Inventory and the GHGRP 

may be similar but not identical. Users should check the definitions of industry sectors in the two 

data sets before making comparisons. For example, emissions attributed to a particular industrial 

process in the GHGRP may instead be included under fossil fuel combustion in the Inventory. In 

other cases, the source category definition in the GHGRP may include emissions from different 

processes than in the Inventory and vice versa. These definitions are particularly important for 

understanding differences in emissions totals for refineries, iron and steel mills, and 

petrochemical plants. 

Generally, the GHGRP requires facilities that emit greater than 25,000 metric tons CO2e per year 

to report. The Inventory is a comprehensive accounting of all U.S. emissions from each source 

category and includes small emitters in its aggregate categorizations of emissions totals for the 

industrial, commercial and residential sectors. Industry types that have a large number of 

facilities that fall below the 25,000 metric ton CO2e reporting threshold include: landfills, 

industrial wastewater treatment, zinc production, glass production, petroleum and natural gas 

production, and emissions from general stationary combustion of fossil fuels. 
187 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 11 

Commenter Name: Mark F. Sutton 

Commenter Affiliation: Gas Processors Association (GPA) 

Comment Number: EPA-HQ-OAR-2014-0831-0132 

Page(s): 30 

Comment 17: Commenter 0132: In the Support Statement, section 4(b) EPA lists the activities 

that a respondent performs: 

The primary tasks that reporting program respondents perform include:

1. Implementing and updating, as necessary, appropriate monitoring plans for 

each affected source and each affected unit at a source, as applicable;

2. Conducting operation and maintenance activities associated with the 

monitoring, including quality assurance activities;

3. Ensuring data quality, preparing annual reports of emissions data, and 

submitting these reports to the EPA;

4. Potentially responding to questions or error messages from the EPA; and

5. Maintaining records for a minimum of three years.

However, in Appendix B of the Supporting Statement, only some of those activities were 

included, and the time estimates for those activities are much less than reality. It does not appear 

that EPA accounted for the time to implement and update monitoring plans, collect samples and 

conduct required analyses as needed, conduct quality assurance activities, ensure data quality, 

and respond to questions or error message from EPA. 

Commenter 0132: EPA’s impact and cost assessments completely fail to include time for 

training. Because blowdown reporting requires continuous monitoring, training operators or 

contractors on the requirements of the rule is essential. Due to staff turnover, training typically 

occurs at least once annually. Every operator/contractor will need to be trained. Often, 

operators/contractors will be responsible for multiple compressor stations, but there will be 

multiple operators/contractors in a crew, plus supervisors. For simplicity, we assume that there is 

one operator for every four sites, who completes two hours of training the first year with an 

additional half hour for years following. We also assume there is one person leading the training. 

For EPA’s model facility, this becomes an additional eight hours per year. 

Response 17: Conducting quality assurance activities, ensuring data quality, and responding to 

questions from EPA are included in the reporting burden allotment of 10 hours per year. 
188 

Implementing and updating monitoring plans are included in the 10 hours per year allotted to 

recordkeeping burden. 

Training is included in the 5 hours per year allotted to read the rule, any related instructions, and 

guidance documents. Respondents should not require 5 hours per year past the first year of 

implementation. These 10 total hours in the second and third year should allow for training 

activities. 

Sample collection is included in the estimates, as needed, for each appropriate equipment type. 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 12 

Comment 18: EPA estimates that there are only 72 occurrences per respondent per year. 

INGAA asserts that there are approximately 57,700 blowdowns per year (including those from 

de minimis facilities). This figure is based on 183 reporters using the EPA definition of facility.12

If the de minimis facilities are excluded as proposed by INGAA, there will be approximately 

3100 blowdowns for the 183 reporters. INGAA contends that the annual cost estimate for 

recording the blowdown information for the 183 reporters is $888,580 per year (including 

the de minimis facilities) and $47,900 per year if the de minimis facilities are not included.

Complying with the proposed rule is a two-step process. Company personnel must travel to the 

site to conduct each blowdown event and then record the additional information to track pipeline 

blowdowns. EPA makes reference in its supporting statement that natural gas transmission 

pipeline reporters would perform engineering calculations based on pressure, temperature, and 

volume of the pipeline segment rather than traveling to the site. However, this assumption is 

incorrect. Company personnel are physically on site to conduct each blowdown event. Personnel 

would make the calculation onsite and while the blow down occurred. Company personnel 

would also need to summarize this information annually for each blowdown location site. Not 

only should EPA factor in the costs for either company personnel or vendors to be on site to 

record the blowdown information but EPA should also consider the work needed on an annual 

basis to summarize and submit the data to the agency. 

Footnotes: 

12 See INGAA Comment 6 for an explanation of de minimis facilities. 

Response 18: In Comment 3 of Section 4.1 of this document, the commenter requested that 

smaller ancillary equipment located along pipelines be excluded from the definition of 

blowdown for the Onshore Natural Gas Transmission Pipelines industry segment. 

In Comment 16 of this section, the commenter further noted that the number of blowdowns 

assumed at proposal should be adjusted based on whether or not ancillary equipment is included 

in the count of blowdowns. The commenter suggested that including small ancillary equipment 
189 

results in a much higher number of blowdowns than proposed by the EPA (approximately 315 

blowdowns per respondent) and that excluding small ancillary equipment should result in a 

lower number of blowdowns than proposed by the EPA (approximately 17 blowdowns per 

respondent). 

The EPA agrees that the emphasis for this reporting segment is on capturing and reporting 

emissions from pipeline segments so the final rule clarifies that the focus of this segment does 

not include blowdown emissions from small ancillary equipment. Therefore, the EPA agrees to 

change the estimated number of transmission pipeline blowdowns from 72 per respondent to 17 

per respondent. 

 
190 

10.0 Advanced Innovative Monitoring Methods 

The EPA received the following comments in response to the request for comments on the 

feasibility, possible regulatory approaches, and provisions necessary to incorporate or allow the 

use of advanced measurement or monitoring methods in subpart W. The EPA is not including 

provisions related to advanced measurement or monitoring methods in this rule and is not 

responding to these comments in this rulemaking. Instead, following review of the data and 

information received in comments, the EPA may propose amendments related to the use of 

innovative technologies in reporting to the GHGRP in a future rulemaking. 

Commenter Name: Public Hearing: Karin Ritter 

Commenter Affiliation: Public Hearing: American Petroleum Institute 

Comment Number: EPA-HQ-OAR-2014-0831-0055-B 

Page(s): 26-28 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 24 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 13 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 17 

Comment 1: Commenter 0055-B: In the preamble to the proposed rule, the EPA discusses the 

potential opportunities for applying remote sensing technologies and other innovations in 

measurement or monitoring technology to identify and calculate emissions from affected sources 

under Subpart W. EPA’s stated objectives are to determine if new and innovative technologies 

could be applied to the reporting program to improve the overall accuracy of transparency of 

reported data in a cost-effective way. API views the introduction of this topic as totally 

inappropriate within the framework of the proposed revisions, which are intended to address the 

introduction of new reporting requirements for new segments and selected operations. The issue 

of using advanced monitoring techniques is pertinent to all the sectors that are subject to part 98 

and its various subparts and should not be constrained just within the Subpart W framework. API 

requests that EPA acknowledge upon promulgation that this discussion is premature for 

consideration under this rule and should defer the request for comments and information on the 

topic until after all the new 2015 reporting requirements are implemented. 
191 

Commenter 0137: API contends that this is not the appropriate platform to consider such 

methods and that this discussion is premature for consideration under this rule and EPA should 

defer the request for comments and information on this topic until after all the new reporting 

requirements are implemented. 

Commenter 0140: In the preamble to the Proposed Rule, the agency solicits comment on the use 

of advanced monitoring technologies and methods for estimating emissions.13 A discussion paper 

in the docket provides additional background. INGAA supports allowing access to technology 

advances and improved methods for estimating emissions. However, this rulemaking only 

addresses a subset of GHGRP sources and sectors, petroleum and natural gas systems under Part 

98, Subpart W. The use of advanced monitoring and methods would be applicable across the 

various sectors subject to the GHGRP, so raising this issue in a Subpart W rulemaking may not 

be appropriate. INGAA recommends soliciting comment on advanced monitoring and methods 

in a separate action that applies to all sectors subject to Part 98. 

Notwithstanding this concern, INGAA offers some initial feedback. The EPA should allow 

advanced monitoring and methods at the operator’s discretion as a replacement for current 

Subpart W requirements. INGAA is opposed to adding new, incremental requirements to Subpart 

W. Instead, the EPA should consider a review and approval process for advanced monitoring 

methods and technologies, and new technologies should be adequately demonstrated and 

verified. The discussion paper included in the docket explores some options, such as approaches 

for alternative monitoring approval in the General Provisions of Part 60 and Part 63. While a 

review and approval process for alternative monitoring technologies or methods analogous to 

those procedures would be appropriate, INGAA encourages a streamlined process to facilitate 

implementation and minimize the burden of case-specific reviews. INGAA will likely offer 

additional comments if the EPA solicits feedback in a future GHGRP proposal. 

Footnotes: 

13 See 79 Fed. Reg. 73148 at 73158. 

Commenter 0142: EPA proposes potential opportunities for applying remote sensing 

technologies and other innovations in measurement or monitoring technology to identify and 

calculate emissions from affected sources under Subpart W. EPA’s stated objective for this 

assessment is to determine if new and innovative technologies could be applied to the GHG 

Reporting Program to improve the overall accuracy and transparency of reported data in a costeffective way while still meeting the overall objectives of Part 98. 

Kinder Morgan questions the applicability and relevancy of the advanced innovative monitoring 

methods section of this proposed rulemaking. This proposed rulemaking primarily pertains to 

new reporting requirements for portions of the oil and gas industry, rather than changes to the 

monitoring and measurement requirements for equipment and facilities currently subject to the 

GHG Reporting Rule. 

However, Kinder Morgan supports EPA’s proposal to allow the use of advanced innovative 

monitoring methods to reduce the costs associated with the current Subpart W monitoring and 
192 

measurement requirements as a voluntary method. To clarify application of the advanced 

innovative monitoring methods, Kinder Morgan encourages EPA to implement a verification and 

approval process, similar to the previous BAMM or dispersion modeling approval processes, for 

development and implementation of advanced innovative monitoring methods. Through this 

verification and approval process, vendors or operators could request use of an advanced 

innovative monitoring method. EPA would then need to verify the technical feasibility and 

accuracy of an advanced innovative monitoring method prior to approval. Requests for 

evaluation of advanced innovative monitoring methods would need to be submitted and analyzed 

on a case-by-case basis. This verification and approval process is mandatory since any advanced 

innovative monitoring method must meet the compliance requirements of the GHG Reporting 

Rule. 

Commenter Name: Public Hearing: Thomas Bach 

Commenter Affiliation: Public Hearing: Kinder Morgan, Representing Interstate Natural Gas 

Association of America 

Comment Number: EPA-HQ-OAR-2014-0831-0055-A 

Page(s): 13-14 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management 

Comment Number: EPA-HQ-OAR-2014-0831-0061 

Page(s): 1-2 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 11 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 17-18 

Comment 2: Commenter 0055-A: INGAA supports EPA’s proposal to allow use of advanced 

innovative monitoring technologies and methods. However, EPA will need to establish some 

type of verification and approval process for these technologies and methods. Pipeline operators 

should be given the discretion to implement advanced innovative monitoring methods to replace 

existing Subpart W requirements rather than those methods being in addition to the current 

requirements. 

Commenter 0061: In its proposal, EPA seeks comments on the future use of advanced, 

innovative monitoring methods to improve the accuracy of reported emissions data from subpart 

W sources. although WM’s operations are not subject to the subpart W GHG Reporting Rule 
193 

requirements, EPA asked Waste Management to comment based on the extensive research we 

have conducted with the Agency, academia and other industry partners to apply advanced 

methane measurement techniques at MSW landfills. 

While the advanced monitoring techniques involve measurement of methane and CO2 emissions, 

we believe that the sources are sufficiently different that our experience with advanced 

measurement techniques at MSW landfills may not translate well to subpart W sources. MSW 

landfills are large area sources with fugitive emissions distributed over many acres. It is our 

understanding that oil and gas sites have emissions that emanate from leaks at point sources such 

as equipment, storage tanks, and production wellheads. A second, important difference is that 

WM has never employed advanced measurement techniques such as tunable diode lasers (TDL) 

or cavity ring-down spectroscopy (CRDS) as continuous emissions monitors (CEMS). WM has 

instead employed these techniques to estimate mass flux emissions of methane over a particular 

time period. We are not sure that some of the technologies listed in the Agency’s Discussion 

Paper would lend themselves to cost-effective continuous monitoring tools at this time. For 

example, the paper mentions differential absorption lidar (DIAL), but to our knowledge, very 

few DIAL units are available for commercial use. They are very effective, but expensive 

technology and in our view are not practical for continuous monitoring purposes. 

WM does not want to impede the oil and gas industry from voluntarily pursuing these tools if 

they lead to better data than emission factor calculations. However, a key issue with deploying 

any advanced measurement technique will be the standardization of methods and the definition 

of sufficient data. 

Commenter 0139: EPA has included a discussion paper in the docket for this rulemaking on the 

potential implementation of advanced alternative monitoring in the Reporting Program.55

Commenters support the agency’s efforts to gather information on the use of advanced 

measurement and monitoring methods and technologies to improve emissions inventories, and 

we urge EPA to adopt provisions incentivizing the use of alternative methods subject to the 

agency’s approval. 

In its discussion paper, EPA offers three potential approaches to implementing an alternative 

monitoring mechanism: (1) a detailed annual request; (2) a one-time detailed request; and (3) a 

public list of possible alternative monitoring technologies.56 Regardless of its form, such an 

approach should be consistent with the general principles of improved (real-time, transparent, 

and accurate) data quality, flexibility, innovation and continuous improvement.57 An alternative 

monitoring program should first be based on transparent, scientific data. Secondly, the program 

should ensure that data is available in sufficient, standardized detail and quantifiable measures to 

allow other groups to independently test the accuracy of the proposed method and compare it to 

data obtained or generated through other means. Third, EPA must not approve any alternative 

method that does not generate data that is at least as accurate and comprehensive as those 

produced by traditional monitoring methods. 

Footnotes: 
194 

55 EPA, Discussion Paper on Potential Implementation of Alternative Monitoring under the 

GHGRP, Doc. EPA-HQ-OAR- 2014-0831-0017 (Nov. 13, 2014). 

56 Id. at Appendix B. 

57 See id. at 4. 

Commenter 0142: Kinder Morgan disagrees with blanket approvals of advanced innovative 

monitoring methods, especially based on vendor claims that may not be verifiable or 

substantiated. Blanket approvals would mistakenly indicate to the public that such monitoring 

methods could be used in all circumstances, without accounting for differences in application, 

technical feasibility, and operational considerations, among others, at individual facilities. If 

EPA adopts any use of approved advanced innovative monitoring methods, EPA should make 

clear in the final rule that any advanced innovative monitoring methods are intended only for use 

in the Subpart W reporting program and shall not be used by EPA, states, or third parties in other 

regulatory contexts without further EPA review and approval in the context of a work practice 

standard, reference method, or similar official EPA regulatory analysis and review. Such terms 

are critical in order to avoid creating disincentives to operators in developing such monitoring 

methods. 

In addition, the use of any advanced innovative monitoring method must be at the discretion of 

the regulated community. Verified and approved advanced innovative monitoring methods 

should be implemented as a voluntary replacement for the currently required monitoring and 

measurement requirements under this GHG Reporting Rule, rather than being an additional 

requirement. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 21-22 

Comment 3: API views the introduction of this discussion topic as totally inappropriate within 

the framework of the proposed GHGRP 2015 revisions that are designed to address new 

reporting requirements for newly defined segments and other selected operations in the 

Petroleum and Natural Gas sector. 

In its discussion paper on alternate monitoring methods, EPA cites other examples of industries 

and applications where they have incorporated advanced innovative monitoring methods toward 

emission estimation. However, none of the examples cited are relevant to quantifying emissions 

from oil and gas production and gathering system sources. Due to the fundamentally different 

structure and complexity of the oil and gas industry, particularly the production sector, there are 

several reasons why advanced innovative monitoring methods are not suitable for this 

application. 

These include: 
195 

 Distributed nature and the large number of oil and gas facilities; 

 Remote location of most oil and gas wells and gathering system facilities – often with no 

access to electricity, reliable communications or other utilities; 

 Non steady-state nature of many oil and gas emission sources coupled with the number 

and unconstrained (no stack or single emission point) nature of emissions; 

 Uncertainty introduced by atmospheric dispersion and flux calculations; 

 Uncertainty introduced by source apportionment. 

Even if advanced ambient measurement techniques were feasible for application to Subpart W 

facilities, they would not be able to distinguish between specific emission sources at a facility or 

even which facility these emissions were coming from in the case of closely located or colocated facilities. Hence, such techniques could not meet the primary goal of the GHGRP of 

informing policy mechanisms, and from this perspective would be of little to no value. 

Commenter Name: Kathleen Sgamma 

Commenter Affiliation: Western Energy Alliance and American Exploration & Production 

Council (AXPC) 

Comment Number: EPA-HQ-OAR-2014-0831-0125 

Page(s): 5 

Comment 4: While we continue to investigate and search for innovative technologies and 

methods to increase accuracy and efficiency in our operations, the increased burden of expanding 

reporting data and elements reduces these efforts. We would like to continue to work with the 

EPA to determine ways to decrease the cost of current technology implementations before 

spending more time to focus on advanced methods. Although we support the EPA’s request for 

operators to research advanced monitoring methods, such as possible remote sensing, 

monitoring, we prefer the operators’ limited resources to be focused on identifying and fixing 

leaks, rather than quantifying the volume of the associated leaks. Furthermore, we feel resources 

should be focused on implementing current technologies that conform to the requirements of the 

rule, rather than allocating resources to future technologies. 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 13 

Comment 5: We note that EPA expressed interest in the concept of advanced alternative 

monitoring for a wide range of emissions sources, including those outside the oil and gas sector. 

We agree that this framework could help improve data and transparency across a wider range of 

sources covered under the Reporting Program, but respectfully suggest that the oil and natural 

gas sector is a good place to begin such a program. The Administration has committed to deploy 
196 

more transparent real-time monitoring tools and methods in the oil and gas sector, and innovative 

technology companies and federal agencies are working to develop and support the next 

generation of advanced monitoring technologies. In light of this dynamic landscape, advanced 

monitoring could play a particularly important role in improving the accuracy and transparency 

of data from the oil and natural gas sector. For these reasons, we urge EPA to consider deploying 

an advanced monitoring program for covered oil and gas sources even as the agency is working 

to develop a broader approach under the Reporting Program. 

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Commenter Affiliation: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and 

Natural Resources Defense Council 

Comment Number: EPA-HQ-OAR-2014-0831-0139 

Page(s): 11-13 

Comment 6: We support a streamlined application process for alternative methods and offer the 

following specific recommendations in response to EPA’s implementation-related questions in 

its discussion paper: 

 Who can apply: Applications to demonstrate the effectiveness of an alternative method 

should be open to reporting entities, technology developers, academic institutions, and 

any other qualified groups. An open program will promote innovation by increasing 

market participation in emerging monitoring technologies and allow reporters and 

technology developers alike to demonstrate the viability of a new methodology. 

 Submission period: We recommend there be a defined submission period for initial 

applications. Initially, the agency could request an annual call for submissions, with the 

option to accept bi-annual submissions depending on the resulting workload. EPA could 

style the initial submission period as an XPRIZE-type innovation competition to create 

added visibility and ensure evaluation of a rigorous pool of technologies and practices. 

 Focus on high-impact solutions: To ensure data integrity, EPA could approve a discrete 

number of alternative monitoring method submissions each year, representing the most 

promising approaches. 

 Phasing in alternative monitoring: Alternative monitoring should be phased into the 

Reporting Program so that data from these new methods and/or technologies can be 

compared to similar facilities using traditional monitoring techniques. 

 Clarity of data: The Reporting Program should make clear which facilities are using 

alternative monitoring and which are not. A clear distinction will allow for comparison of 

emissions data and continuous improvement in data quality from both alternative and 

conventional methods. 

 Quality of data: Only those methods that result in data that is at least as accurate and 

comprehensive as existing data should be approved. 

 Use of alternative monitoring at multiple facilities: Once an alternative method is 

approved, facilities in the same sector seeking to use the method for similar sources or 

facilities should not be required to demonstrate the method. EPA could qualify that an 

alternative method is only approved for sources or facilities similar to those used to 
197 

demonstrate the method and only after the agency is able to validate the reliability of the 

methodology against existing measures. 

 Limitations on site-wide measurement methods: For alternative methods that involve 

facility-wide measurement, EPA could consider allowing sources to submit facility-wide 

emission results in addition to granular, site-specific data, allowing for important 

verification of the granular data. 

 Public availability of alternative monitoring information: EPA should maintain a list of 

approved alternative monitoring methods along with approved demonstrations of those 

methods. Publically available information will enable outside groups to independently 

analyze the approved methods and allow reporters to consider the use of other alternative 

methods.58

Consistent with these suggestions, EPA could adopt a two-step approach to alternative method 

application and approval. First, a reporter or other organization or individual (e.g. equipment 

providers, technology developers, academic institutions, NGOs) could submit an application to 

EPA describing the method and a proposed demonstration for the method. EPA would then 

approve a demonstration of the method at a facility reporting under the Reporting Program. 

Second, the results of the demonstration would be submitted to EPA for review and approval. 

The entity submitting the demonstration results should be a reporter under the Program that 

intends to use the method at one or more facilities. Based on the results of the demonstration, 

EPA would then decide whether to approve the use of the alternative monitoring method by all 

entities subject to Subpart W, with appropriate conditions or qualifications as necessary. 

Footnotes: 

58 The U.S. Green Building Council’s LEED Pilot Credit Library is one potential model for a 

public database and open submission system designed for feedback on proposed methods and 

their demonstration. See USGBC, Pilot credits are the next big thing, 

http://www.usgbc.org/leed/tools/pilot-credits, (last visited Jan. 27, 2015). The Pilot Credit 

program allows Council members to submit online proposals for innovative green building 

technologies for potential accreditation. After evaluation of the proposal, it is placed in a public 

database for review and comments by other members and the public before final review and 

approval by the Council. Id.

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management 

Comment Number: EPA-HQ-OAR-2014-0831-0061 

Page(s): 2-3 

Comment 7: In the EPA’s proposed New Source Performance Standards for MSW Landfills, the 

Agency requested information on the potential to use alternative remote measuring and 

monitoring techniques for landfills. 79 Fed. Reg. at 41823; 79 Fed. Reg. at 41790. Hence, we 

have included those comments WM previously made to the Agency in response to this latest 

Agency request for information. 
198 

The methods cited in the preamble include radial plume mapping (RPM), optical remote sensing, 

Fourier Transform Infrared (FTIR) spectroscopy, cavity ring down spectroscopy (CRDS), 

tunable diode laser (TDL), tracer correlation, micrometeorological eddy-covariance, static flux 

chamber or differential absorption. The above list includes methods of chemical detection and 

analysis (FTIR, TDL, CRDS) as well as can be characterized as measurement techniques (RPM, 

optical remote sensing, tracer correlation, micrometerological eddy-covariance, static flux 

chamber) that are typically used to determine the mass flux emissions for a defined area. The 

measurement techniques typically utilize one or more of the formerly listed methods of 

detection. For example, radial plume mapping, which is a form of optical remote sensing, can be 

performed using a variety of open path instruments (e.g. FTIR, TDL). 

WM has experience with the application of these techniques to research landfill emissions and 

the results of those efforts have been reported (see list of references). As the majority of 

measurement techniques listed above are most commonly used to determine mass flux emissions 

they are not direct replacements for the current surface emissions monitoring method, which 

determines methane concentration five to ten centimeters above the landfill surface. 

Notwithstanding the costs of implementation, which are significantly higher than the SEM 

procedure in Subpart WWW and proposed in Subpart XXX, a horizontal RPM method or other 

open path method could conceivably be useful for hotspot detection. The technique can be used 

to produce a concentration map of the surface. However, in our experience with this approach, 

the instrumentation and retro reflectors are configured in a manner which results in 

measurements being made at approximately one meter above the landfill surface. We 

recommend that additional field validation of this method which includes a comparison to the 

surface scan method be conducted prior to consideration as an alternate method. One important 

part of the field validation would be to compare the path-integrated measurements produced 

from an HRPM with the point concentration data of the serpentine FID measurements. 

The methods of detection listed can detect minute quantities of methane and can have large 

dynamic measurement ranges making them useful when employed in optical remote sensing and 

tracer correlation work. The solid state nature of the laser systems such as TDL or CRDS make 

them reliable and relatively robust. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 23 

Comment 8: If well-pad or facility level emissions were to be quantified remotely, ambient 

monitoring devices would need to be placed some distance downwind of the source, or would 

need to be flown over facilities, as has been done by multiple research groups over the past 

several years. The dispersion of emissions from multiple sources coupled with flux calculations 

relying on meteorological data and inverse modeling or “box” calculations introduces significant 

uncertainty in emissions calculations5

. Due to the large numbers of wells and facilities, which 

emit similar gases, that are located in proximity to each other in a typical oil and gas field, 

determining a correct contemporaneous local background concentration to enable quantification 
199 

of emissions from any particular site is challenging and another source of uncertainty. 

Additionally, an important characteristic of oil and gas production emission sources is that there 

are several significant non steady state emission sources, and the variability introduced by 

episodic events such as tank flashing makes it very difficult to calculate annual emission 

estimates from short-term downwind ambient measurements6

. Researchers from EPA who have 

carefully developed, calibrated and tested an ambient emission rate technique for oil and gas 

sources (OTM 33A) describe their technique as having ‘screening level accuracy’ of +- 60%3

under ideal meteorological and topographical conditions. The relative uncertainty increases as a 

wider range of meteorological conditions are included, and this technique becomes unreliable 

when sources are located in complex topography or when other structures lie between the 

observation site and emission location. Screening-level accuracy is not suitable for regulatory 

purposes, and is not useful to quantify emission sources from oil and gas operations. 

Footnotes: 

3

http://www.phmsa.dot.gov/portal/site/PHMSA/menuitem.6f23687cf7b00b0f22e4c6962d9c8789

/?vgnextoid=a87 

2dfa122a1d110VgnVCM1000009ed07898RCRD&vgnextchannel=3430fb649a2dc110VgnVCM

1000009ed07898RCR D&vgnextfmt=print 

5

Thoma, E. D., et al. “Assessment of methane and voc emissions from select upstream oil and 

gas production operations using remote measurements, interim report on recent survey studies.” 

Proceedings of 105th Annual Conference of the Air & Waste Management Association, Control 

No. 2012-A-21-AWMA. 2012. 

6

Brantley, Halley L., et al. “Assessment of Methane Emissions from Oil and Gas Production 

Pads using Mobile Measurements.” Environmental science & technology 48.24 (2014): 14508-

14515. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 22-23 

Comment 9: There are about 1 million oil and gas wells producing in the U.S., thousands of 

central production facilities and compressor stations in the gas gathering and collection and gas 

transmission and storage segments, and hundreds of gas processing facilities. These producing 

wells and facilities are geographically dispersed in generally remote areas, often with no access 

to electricity or reliable communications. Weather conditions at many of these sites are harsh and 

no enclosures or protection for sophisticated instrumentation and data systems exist. Given the 

cost and complexity of installing, operating and maintaining the types of measurement devices 

discussed in the Proposed Rule Preamble and EPA’s memo (e.g., cavity ring-down spectroscopy 

(CRDS) or other tunable diode laser systems ), application to the facilities and sources under 

Subpart W is simply not feasible from either a technical or cost perspective. These types of 

devices are typically used for short-term monitoring and measurement studies, not as fixed 
200 

continuous monitoring systems. Should the efforts underway to develop low-cost methane 

sensors (e.g., the ARPA-E MONITOR program4) be successful, then the new sensor’s accuracy, 

repeatability, and sensitivity to interference by other compounds may add additional uncertainty. 

Footnote: 

4

 http://arpa-e.energy.gov/?q=arpa-e-news-item/arpa-e-announces-60-milliondisruptivetechnologies- cut-emissions-boost-energy 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Comment Number: EPA-HQ-OAR-2014-0831-0137 

Page(s): 24 

Comment 10: For greenhouse gases such as CO2 and CH4 there are large and potentially 

significant natural and anthropogenic sources that may be co-located with oil and gas operations. 

Emissions of CH4 from wetlands, ruminants, landfills and waste treatment can lead to very high 

concentrations of observed CH4 enhancement relative to background, and accurate source 

apportionment is difficult7. The typically complex intermix of oil and gas sources in a field/basin 

with wells, central production facilities, compressor stations, and non-oil and gas sources located 

in proximity to each other precludes attribution of ambient measured and flux calculated 

emissions to a particular well/site let alone to a specific source type. Uncertainty in the emission 

factors from non-oil and gas sources along with widely variable speciation of oil and gas 

emissions leads to significant uncertainty in source identification. Two recent papers using 

different techniques identified, for example, that ruminant emissions of methane were 40-100% 

higher than both the EDGAR and EPA inventories 8 9, while they disagreed on whether oil and 

gas emissions were higher than those same inventories. 

Given the unique characteristics of oil and gas sources, current advanced monitoring methods are 

not suitable for regulatory quantification of emissions. Direct emission measurement studies of 

individual sources (like those performed by Allen et al10 11 12) may lead to source specific 

emissions data that could potentially be used for quantifying CH4 emissions. 

Footnotes: 

7

 Kirschke, Stefanie, et al. “Three decades of global methane sources and sinks.” Nature 

Geoscience 6.10 (2013): 813-823. 

8

 Miller, Scot M., et al. “Anthropogenic emissions of methane in the United States.” Proceedings 

of the National Academy of Sciences 110.50 (2013): 20018-20022. 

9

 Wecht, Kevin J., et al. “Mapping of North American methane emissions with high spatial 

resolution by inversion of SCIAMACHY satellite data.” Journal of Geophysical Research: 

Atmospheres (2014). 
201 

10 Allen, David T., et al. “Measurements of Methane Emissions at Natural Gas Production Sites 

in the United States”, Proceedings of the National Academy of Sciences, 110.44 (2013): 17768-

17773. 

11 Allen, David T., et al. “Methane Emissions from Process Equipment at Natural Gas production 

Sites in the United States: Liquid Unloadings.” Environmental Science and Technology (2015) 

49 (1), pp 641-648. 

12 Allen, David T., et al. “Methane Emissions from Process Equipment at Natural Gas production 

Sites in the United States: Liquid Unloadings.” Environmental Science and Technology (2015) 

49 (1), pp 633-640. 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management 

Comment Number: EPA-HQ-OAR-2014-0831-0061 

Page(s): 4 

Comment 11: WM has invested significant time and resources in trying to resolve 

methodological uncertainties, and to develop best practices to make OTM 10 and CRDS 

practical tools for landfill emissions estimation. Nonetheless, we cannot recommend using 

direct measurement techniques such as OTM 10 or CRDS for regulatory compliance 

purposes, for calculating landfill gas collection efficiencies, or even for estimating whole 

landfill emission factors without first resolving these methodological problems. Before these 

techniques are used in these ways, best management practices and/or method protocols for using 

the technique at landfills should be developed and made publicly available for review and 

comment. We believe the technique is far better suited to researching emissions associated with 

small defined areas rather than measuring emissions for an entire landfill. 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management 

Comment Number: EPA-HQ-OAR-2014-0831-0061 

Page(s): 3-4 

Comment 12: Fundamentally, we do not recommend using direct measurement techniques 

such as OTM 10 with TDL or CRDS for regulatory purposes at this time. EPA has 

recognized that these methods as applied to landfills are still research methods and not 

appropriate for emission inventory purposes at this time. Per EPA’s Emission Measurement 

Center’s Interim Policy on Posting Methods, test methods are divided into four categories. For 

example, Category C: Other Methods includes test methods, which have not yet been subject to 

the Federal rulemaking process. Other Test Method (OTM)-10 and CRDS both have not been 

subject to the Federal rulemaking process; they are both still considered research methods. These 

methods have not been validated for measuring fugitive methane or other hydrocarbons at 

landfills and therefore should not be recommended as reliable methods at this time. 
202 

The use of the OTM 10 method to develop landfill methane emission factors requires the use of 

models to approximate the surface area contributing to flux (ACF) in order to develop mass 

emissions per time per unit area for multiple areas of a landfill. Two models have been 

developed to estimate the ACF for OTM 10 measurements, the multiple linear regression model 

described by Thoma et al. 2010 and the stability class model described by Abichou et al. 2010. 

The overall measurement uncertainty associated with the use of these models is estimated to be 

10-30 percent. 

From our perspective, emission factors would need to be developed for each combination of 

cover type (e.g. daily, intermediate and final) and gas collection condition present. The results 

from our study of 20 landfills indicate that emissions appear to vary by these operational 

characteristics as well as climate. Therefore, to develop a whole landfill emission estimate, each 

unit emission rate, in mass per time per unit area, would be extrapolated to like areas (according 

to cover type and gas collection status, etc.) and summed. Examples of this approach are shown 

in a paper on a method comparison study performed in 2008 in collaboration with Veolia 

(Babilotte et al. 2010) and a study using OTM 10 at three California landfills (Green et al. 2009). 

While these studies do derive whole landfill emission estimates from unit emission rates, there 

are significant uncertainties in using this approach. It has been our experience that OTM 10 

measurements practically can cover only 5 to 20 percent of the total landfill surface (Babilotte et 

al. 2010). Consequently, this technique is subject to some of the same criticism regarding spatial 

representativeness that has been leveled at the use of static flux chambers to determine emission 

rates. 

Additionally, after more than 50 weeks of measurement at 20 landfills, we are still unsure of how 

many measurements are required to capture accurately the temporal variability of emission rates. 

For example, we have observed that the unit emission rate calculated for a given cover type at a 

single landfill can vary by more than a factor of three over the course of several months. This 

temporal variation in observed emissions is linked to changing rates of gas production and 

collection, as well as to the extent of methane oxidation; all of which are also affected by climate 

(Chanton et al. 2010). 

As a practical matter, we are very concerned that only 31 percent of the 72,500 measurements 

obtained over 50 weeks data collected are usable (i.e., meet the quality assurance/quality control 

(QA/QC) requirements). The measurement technique is difficult to set-up and use due to the 

complex topography associated with landfills and the strong influence weather (e.g., wind 

direction and speed, precipitation, barometric pressure) plays on the ability to obtain usable TDL 

readings. The large source size, heterogeneous source area, and interference from proximate or 

distant sources of emissions (from an adjacent landfill cell outside the measurement area or a 

wholly separate site) can create very significant uncertainties in measuring methane flux. 

 
203 

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

Amendments 

Commenter Name: Kelly L. Guertin 

Commenter Affiliation: DTE Energy 

Comment Number: EPA-HQ-OAR-2014-0831-0135 

Page(s): 1-2 

Commenter Name: Theresa Pugh 

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

Comment Number: EPA-HQ-OAR-2014-0831-0140 

Page(s): 5-6 

Commenter Name: Thomas Bach 

Commenter Affiliation: Kinder Morgan, Inc. 

Comment Number: EPA-HQ-OAR-2014-0831-0142 

Page(s): 12 

Comment 1: Commenter 0135: DTE Energy strongly endorses comments by INGAA, which 

suggest the EPA work with the Pipeline and Hazardous Materials Safety Administration 

(PHMSA) in considering the drivers for blowdown emissions and to pinpoint areas where new 

technology could help to reduce emissions. 

Commenter 0140: EPA and PHMSA should work together to identify the various drivers for 

blowdown emissions prior to finalizing this rule. 

As EPA is aware, the 2014 GHG National Inventory1

, which displays methane emissions from 

natural gas transmission pipelines as well as compressor stations, indicates that pipeline 

blowdown emissions comprise about 9% of the total methane emissions from the natural gas 

transmission and storage sector. However, this estimate is based upon an emission factor 

developed by the EPA/Gas Research Institute (GRI) study2 conducted 20 years ago. The 

EPA/GRI study relied on limited data to develop the blowdown emission factor, and there are 

questions about whether the emission factor accurately represents current operations and 

activities related to pipeline blowdowns. 

In order to present a complete picture of the total methane emissions from the natural gas 

transmission sector and inform the cost-benefit analysis of reducing those emissions, the EPA 

should consider the current and future regulatory drivers for various emissions categories, 

including pipeline segment blowdowns. The blowdown of a pipeline segment is essential for 

certain pipeline maintenance, testing, and replacement activities. Pipeline operators must have 

the flexibility to blowdown pipeline segments to meet regulatory requirements, to conduct 

pipeline maintenance and repairs, to maintain safe operations of this critical national 

infrastructure. For example, pipeline operators are required by the PHMSA to blowdown pipe 

segments as part of the replacement process for a class location change, hydrostatic testing 

requirements (i.e., testing the strength of a pipeline by filling it with water under pressure as part 

of integrity assessments), and to assure pipeline integrity and safety. 
204 

The number of required blowdowns may increase as PHMSA publishes new pipeline safety 

regulations in response to Congressional mandates. However, other methods such as improved 

inline inspection technologies are available to help pipeline operators validate that their pipelines 

are safe without requiring an operator to blowdown a pipe segment. Although INGAA 

acknowledges that it is not within the EPA’s jurisdiction to determine when a pipeline blowdown 

is necessary, the Administration as a whole should consider policy, processes, and technologies 

that can minimize the need for blowdowns as part of its larger strategy for reducing methane 

emissions. Reducing unnecessary pipeline blowdowns by using equivalent or superior 

assessment and repair technologies presents an excellent opportunity to reduce methane 

emissions. 

Footnotes: 

1

 The U.S. EPA publishes an updated annual GHG inventory every April that includes a time 

series of GHG emissions from 1990. The April 2014 report added the 2012 inventory, “Inventory 

of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2012.” See 

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html 

2

 “Methane Emissions from the Natural Gas Industry” EPA/GRI Reports, April 1996. 

Commenter 0142: As a threshold matter, Kinder Morgan agrees with INGAA that in order to 

present a comprehensive picture of the total methane emissions from the natural gas transmission 

sector and to inform the necessary cost-benefit analysis, EPA should consider the regulatory 

drivers associated with certain emissions – including pipeline segment blowdowns. In short, 

pipeline blowdowns are not only an integral part of operations and essential for safety, but they 

are also required by law. Operators must conduct pipeline blowdowns to perform maintenance, 

testing, and pipe replacements to ensure safe operations. Additionally, the Pipeline and 

Hazardous Materials Safety Administration (“PHMSA”) requires pipeline blowdowns as part of 

the replacement process for class location changes (e.g., population increases in the vicinity of 

the pipeline above specified thresholds) and for hydrostatic testing (e.g., when an operator tests 

the pipe using water under high pressures). Furthermore, PHMSA can require pipeline 

blowdowns for other pipeline safety purposes such as repairing third-party or other pipe damage. 

Kinder Morgan continues to encourage the Administration to review existing and future pipeline 

safety regulations as a part of its broader strategy for reducing methane emissions. Specifically, 

Kinder Morgan encourages the Administration to revise the PHMSA regulations to allow the use 

of well tested Integrity Management Program (“IMP”) principles to address class location 

changes that, under the current rules, require pipe replacements causing pipeline blowdowns with 

unburned methane emissions. Using IMP principles in place of pipe replacement would address 

safety concerns while reducing the need for blowdowns and significantly reducing methane 

emissions from natural gas pipelines. 

Response 1: The EPA thanks the commenters for their input. The EPA does communicate and 

collaborate with other federal agencies, including PHMSA, on data and information related to 

methane emission sources and how the emission from these sources can be reduced. However, 

these comments do not specifically address the proposed rule and are beyond the scope of this 
205 

rulemaking. Therefore, the EPA is not specifically responding to these comments in this 

document.