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# 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 ad d calculation methods a nd reporting requirements for greenhouse gas emissions from gathering an d boosting facilities, completions and workovers of oil wells with hydraulic fracturing, and bl owdowns of natural gas transmission pipelines between compressor stations, a nd to add well identification re porting 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 or ganizations, and private citizens in response to the December 9, 2014 proposal. This document provide s the EPA’s responses to the significant public comments regarding these proposals. The verb atim 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 comm enter and the document control number (DCN) assigned to the comment letter are provided. Wh ere possible, the EPA separated comments on specific topics into their respec tive data categories. Within the data categories, similar comment excerpts from multiple commenters were combin ed 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 pote ntially affecting the in tended 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 generall y provided immediately following each comment. In some cases, the EPA provided responses to sp ecific comments or groups of similar comments in the preamble to the final rulemaking. Rather th an 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 organizati on who submitted the comme nt and included a list of commenters who indicated th eir support for that comment in a footnote to the List of Commenters. Copies of all comment letters subm itted 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 .................................................................................................................... i ii

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

List of Comme nters ......................................................................................................... vi i
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 Boosti ng 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 ..................................................................................................... 5 6 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 .......................................................................................... 10 3 4.2 Data Reporting Requirements ......................................................................................... 116vi 4.3 Blowdown Reporting Categories .................................................................................... 125 4.4 Supportive Comments ..................................................................................................... 1 28



### 5.0 Well Identification Numbers .................................................................................. 131
6.0 Compliance Date an d Best Available Moni toring 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 Mo nitoring Methods ........................................................ 190
11.0 Out of Scope Comments: General Co mments Outside of the Scope of the Amendments ....................................................................................................... 203vii 

### List of Commenters a

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-2014-0831-0060 b T. Cole None EPA-HQ-OAR-2014-0831-0061-A2 Kerry Kelly Waste Management EPA-HQ-OAR-2014-0831-0125-A1 Kathleen Sg amma 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. Su tton 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 Ritte r 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. W illiam 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

aThis 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).

dComment 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 Asso ciation (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

CH 4 methane

COC Code of Conduct

CO 2 carbon dioxide

CO 2 e 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 Re gulatory Commission FR Federal Registerx 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

N 2 O nitrous oxide

NESHAP National Emission Standard s 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 Ga s Gathering and Boosting PHMSA Pipeline and Hazardous Mate rials 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 assura nce/quality control REC reduced emissions completion

scf standard cubic feet

SO 2 sulfur dioxidexi 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 States1 

### 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, SierraClub, 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, SierraClub, 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 w ithout government regulations which keep them honest. I therefore support the propos ed EPA guidelines regulating methane.

Commenter 0131: I strongly suppor t the proposal from the Envir onmental Protection Agency to establish reporting guidelines of greenhouse gas emissions for petroleum and natural gas systems. Due to the impact of greenhouse ga s (GHG) emissions on environmental and public health sustainability, it app ears that the regulations are long overdue. In 2013, GHG emissions from petroleum and natural gas system s produced 224 million metric tons of CO 2e , second only to power plants in the United States (U.S . Environmental Protection Agency, 2014). The emission of greenhouse gases into th e environment creates an increa se 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 emissi on reporting guidelines, as they have been previously overlooked. In relation to other greenhouse gases, meth ane is a significant contributor to global warming and air pollution. Methane’s globa l warming potential is twenty times greater than that of carbon dioxide, and methane emi ssions 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 Dise ase Registry, 2010). Due to the volatility of methane, failure to calculate and record emissi ons could create occupational safety hazards and public health risks particularly when natural gas systems occur within community settings.

It is important to understand thatthe emission of these greenhous e gasses can take a serious toll on our society. By not recording these emissions, it is difficult to gauge th e effect it is having on environmental and public health. The data collectedcould be used to strengthen the President’s Climate Action Plan to reduce methane emissions that occur during anthr opogenic practices. Furthermore, the data could be used to enforce the need for a conservatio n approach to reducing greenhouse gas emissions.

References

Agency for Toxic Substances and Disease Regi stry. (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. Retrie ved 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 determ inations for the petroleum and natural gas systems component of the Greenhouse Gas Reporting Program (“Subpart W”). 1 We strongly support rigorous, timely, and transparent emission s reporting for the oil a nd natural gas sector. We urge the agency to promptly finalize str ong reporting requirements for the three emissions sources covered by this proposed rule, none of wh ich 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 producti on in tight-oil formations, like the Bakken and Eagle Ford, the already significa nt national network of gathering and boosting infrastructure, and the potential expansion of this infrastructure. Rigorous reporting will likewise3 help to enhance public transparency for communi ties in close proximity to this development while promoting accountability among operators.

Furthermore, transparent, accurate emissions dataare important to protect public health and the environment. As EPA summarized in the 2012 Ne w Source Performance Standards for the Oil and Natural Gas Sector,

[t]he data submitted under [Subpart W] w ill provide important information on the location and magnitude of GHG emissi ons from petroleum and natural gas systems and will allow petroleum and natu ral gas facilities to track their own emissions, compare them to similar f acilities and aid in identifying . . . opportunities to reduce emissions in the future . . . . 3

Gathering rigorous and transparent emissions inform ation from these segments is also consistent with commitments the Obama Administration ha s made in its Strategy to Reduce Methane Emissions (which directs EPA to “address potential gaps in cove rage” of regulatory requirements and to “ensure high qua lity 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 technolo gies to “improve the overall accuracy and transparency of reported data” 5 ).

Section 114 of the Clean Air Act provides EPA w ith clear authority to require monitoring and reporting of emissions data from sources in th e 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 indus trial 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 SCIE NCE 33-35 (2014) (suggesting emissions from the oil and natural gas sector may be greater than published inventorie s); 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. GEOP HYS. RES. ATMOS. 6836 (2014) (estimating emissions from oil and gas sources in the mo st densely drilled area in the Denver-Julesburg Basin in Weld County, CO may be 3 times hi gher 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: Strate gy to Reduce Methane Emissions, at 13 (Mar. 2014), available at http://www.whitehouse.gov/sites/default/file s/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 Emi ssions (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 a dded) [hereinafter Methane Announcement Fact Sheet].

Commenter 0139: Emissions reporting requirements for the sources included in EPA’s proposed rule will help create transparency for indivi duals living in close pr oximity to oil and gas development, protect public health and th e environment, and cr eate accountability among companies reporting emissions. We strongly s upport the agency’s proposed actions and respectfully urge it to pursue the additional improvements we ha ve described above to further enhance the rigor and transparen cy 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 du ring 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 Re porting Requirements

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and Natural Resources Defense Council Commenter Affiliation: Environmental Defense Fund, SierraClub, 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 propos al to extend reporting requirements to completions and workovers of oil wells with h ydraulic fracturing. Methane emissions from coproducing wells can be substantial and the agency’s efforts to gath er 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 h ydraulic fracturing with minor revisions. See Section II.A of the pream ble to the final rule for more information.

Commenter Name: Kathleen Sgamma Commenter Affiliation: Western Energy Alliance and Am erican 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 w ith the inclusion of “workovers with hydraulic fracturing.” It is ourunderstanding that the EPA is interpreting a workover as equivalent to a recompletion. A workover is an ope ration 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 rem oving or replacing production tubing, or cleaning out accumulations of substances that may inhibit pro duction. 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 pr oposed Subpart W Revisions the category for “workovers with hydraulic fracturin g.” 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 ar e operations on the well itself and generally involve major maintenance or remedi al treatments on an oil and/or gas well, like6 removing or replacing production tu bing, or cleaning out accumulati ons 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 fractur ing of different formations from the same wellbore.

Response 2: For the purposes of 40 CFR part 98, a “w ell workover” is defined in 40 CFR 98.6 of subpart A as follows:

Well workover means the process(es) of performi ng one or more of a variety of remedial operations on producing petroleu m and natural gas wells to try to increase production. This process also incl udes 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 ch aracteristics of both workovers and recompletions as described by the commenters. This defini tion 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 co mpletions,” to clarify that re-fracturing is a well wor kover but not a well completion. Ther efore, 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 repor ting is not required for oil well workovers (including “recompletions”) that do not involve hydrau lic 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 completi ons and work-overs with hydraulic fracturing, which are consistent with the current requirement s for gas well completions and workovers with hydraulic fracturing. The proposed provision applies expanded measur ement requirements to oil well completions with hydraulic fracturing that use flaring and reduced emission completions, or RECs. API notes that EPA assumes that operato rs know in advance whether a completion or7 workover will require flaring. In reality, it is not possible to de termine whether a well will clean up quickly with no need to flare or vent prior to beginning the actual flowb ack. 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. Beside s the obvious cost and burden implications of quadrupling the number of possible combinations requiring measurement or calculation in each county, this will be a sc heduling impossibility for operators. API is requesting that upon promulgati on, EPA establish only two categ ories for reporting emissions from completions and workovers with hydrauli c fracturing, namely venting without REC and vented with REC and flaring.

Commenter 0137: Expanding the well type catego ries 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 a nd without flaring, and w ith and without REC. There are up to 80 possible combinations each requiring separate measurements or calculations. API objects to expanding the number of measuremen ts and has demonstrated that two categories (with and without REC) with 20 possible measurem ent 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 (horizon tal or vertical) combinations for completions OR workovers to include with and without flaring, and with a nd without REC. There are now 40 possible combinations for completions and 40 po ssible 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 ac tual 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 th e obvious cost and bur den implications of quadrupling the number of possible combinations requiring measurement or calculation in each county, this will be a scheduling nightmare for opera tors – particularly since prior determination of whether a well will require flaring is not possible.

It appears that EPA is construc ting the reporting rule to align with the emi ssion categories used in the national GHG inventory. This is not necessary as there is sufficient information to inform the inventory without further e xpanding the reporting rule. Ambigu ity 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 reporte d 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 on8 estimating emissions using the choke flow equati on. 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 substantia l amount of information. Even with some ambiguities in the reported data, there is suffici ent information to develop emission factors. Table 1 compares the resulting emission factors fo r oil wells with hydraulic fracturing using the 4 data categories proposed by EPA for the na tional 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 emissi on data currently available show s that vented workovers and completions without REC have a distinctly higheremission 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 fact ors 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. AP I objects to the expans ion of the well type parameters. Additional granularity in the measur ement requirements is not supported by the data currently available, as demonstrated by revi ew 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 a nd reporting requirements that end up with redundant information and do not contribute to improved charac terization of GHG emissions from completions and workovers.

Table 1. Analysis of GHGRP Data for O il 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 w ith 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 maintain ing the requirement to measure emissions separately per sub-basin and well type combinati on instead of aggregations of these distinct9 operational practices. The disaggreg ated 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 itunlikely that a reporter would conduct drilling activities for a given sub-basin in all the di fferent 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 su bject to the monitoring and reporting requirements. Based on member expe rience, oil wells with GOR values less than 300 do not have sufficient gas to operate a separato r. In some cases, the separators are operated by using pumps to move the fluid out of the vess els or by adding make-up gas to the system to ensure the necessary gas pressure. Based on ope rational experience, API recommends that EPA establish a GOR threshold of 300. For completions or workovers at wells with GOR below this threshold, emissions should notneed to be reported.
Response 1: The final monitoring and reporting require ments 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 rese rvoir pressure has to be greater than the hydraulic pressure of the fluid column in th e well. Therefore, API proposes a simplified approach where a reservoir pressu re that is lower than the ver tical pressure gradient of 0.4645 psi/ft should be excluded from the monitori ng 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 ST AR Partners; Reduced Emissions Completions for Hydraulically Fractur ed 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, SierraClub, 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 reportin g emissions during completions with hydraulic fracturing

Pioneer operates wells in certain fields and opera tions 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 thresh old levels. The work involved in measuring the flowback and reporting of these minimal to n il emissions would outweig h any contribution of these emissions to the overall source category tota ls 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. Rath er, 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 Gatherin g and Boosting segment of Subpart W.11 Commenter 0139: EPA invites comm ent on whether to establish gas-to-oil ratio or minimum well pressure thresholds below which wells woul d 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 howe ver, the agency choses to establish such a threshold, it should ensure thatthe rules include all significan t 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 comm ents on whether EPA should establish a minimum GOR threshold such that oil wells w ith a very low GOR would not be subject to monitoring and reporting requirements for GHG em issions from completions and work overs with hydraulic fracturing or whet her EPA should establish a minimu m well pressure such that oil wells operating below a certain pressure woul d not be subject to monitoring and reporting requirements. See 79 Fed. Reg. at 73,152. Kinder Morg an agrees with and supports the use of a GOR threshold to determine whether direct measur ement 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 threshol d below which the gas flow is too minimal to operate a separator, thus maki ng direct measurement unachievable. In addition to the GOR threshold, Kinder Morgan supports establishm ent 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 suppor ts 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 w ould be dependent on the depth of the well in relation to the reservoir pressure , which would need to be greate r than the vert ical lift of 0.433 psi/ft of the fluid column. A hydr aulically structured well comple tion 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 th e 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 pre ssure 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 require ments do not apply to completions and workovers of oil wells with hydraulic fracturing that have a GOR of less than 300 scf/STB, but12 the final rule does not include a minimum well or reservoir pressure threshold for completions and workovers of oil wells with hydraulic fractu ring. See Section II.A of the preamble to the final rule for the EPA’s response to commen ts 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 N 2 , to compensate for the lack of reservoir energy. The current equation accounts for the nitrogen injected during hydrauli c fracturing for energized fracking through the term EnF s,p . API recommends the following change to the definition of EnF s,p to account for the N 2 injected to kick-off flowback:

EnF s,p = Volume of N 2 or other non-GHG gas inject ed 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 sta ndard conditions using paragraph (t) of this section. If the fracture process did not inject gas in to the reservoir or if the injected gas is CO 2 then EnF s,p is 0.

Response 1: The EPA agrees that the term “EnF s,p ” should include injection of nitrogen gas during flowback as well as during energized fracking. The term “EnF s,p ” is defined as follows in the final rule:

Volume of N 2 injected gas in cubic feet at st andard 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 purch ases that are used for the energized fracture job or injection during flowb ack. Convert to standard conditions using paragraph (t) of this sect ion. If the fracture process did not inject gas into the reservoir or if the injected gas is CO 2 then EnF s,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 producti on facility without individual well separation and production measurement. Although relevant fo r gas wells this type of arra ngement 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 (avera ge 30 day production rate in scf/hr) is not available where individual well prod uction of oil or gas is not measur ed on a continuous basis. In these cases, the rule should allow for usi ng 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 indi vidual well production test for a particular well is conducted in the first 30 days of production following hydraulic fracturing then the aver age of all individual well production tests should be used for the te rm PRs,p in the calcula tion of FRMs and FRMi.

Response 2: The EPA agrees with the suggestions ma de by the commenter, and these suggested changes are incorporated in th e final amendments for completions and workovers of oil wells with hydraulic fracturing. Note th at the operational practices for a “representative” well must be considered when determining if the well is co nsidered 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 FV s,p in Equation 10-B are inco rrect. This term should be expressed as a volume not as a flow ra te. 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 reco rding 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 work over 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 fo r oil well completions and workovers following hydraulic fracturing where there is no flow back to open tanks/pits and/or no flaring or venting once separation begins.

Equation W-10A:

If the term Tp,s is zero and th e 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 re porting is needed to accommodate this change.

If the term Tp,s is zero and th e term Tp,i is greater than zero then determination of the term ENFs,p should not be required. No change in repo rting is needed to accommodate this change.

Equation W-10B:

If the term FVs,p is zero (no vent ing or flaring after separation be gins), 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 specifi ed. 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 s hould 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 determin ed for one well, then for purposes of Equation W-10A, that well cannot be considered “represent ative” 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 consid ered representative). For example, if the term T p,i is zero and the report er cannot determine FRM i for a particular well, then this well cannot be considered “representative” of wells for which the term T p,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 pr oduced fluids or require a tempor ary 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 flow back to open tanks/pits, from when gas is first detected until suff icient 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 yea r. 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 fina l amendments for completions and wo rkovers 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 concurthat the proposed placement of the flow meter is appropriate; downstream of separati on 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 fl owback 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) cu rrently directs that, for gas wells completed with hydraulic fracturing, a “recording flow meter (d igital or analog) shall be inst alled on the vent line, ahead of16 a flare or vent” to measure the flowback rate. While Concho believes that EPA should either not adopt the Subpart W Revisions or should signifi cantly revise the proposed regulations, if the agency proceeds with the proposed draft, then Co ncho 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 possibl e to measure wells with a low GOR, we note that the EPA is finalizing a GOR threshold fo r reporting of emissions from completions and workovers of oil wells with hydraulic fracturi ng. 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 E quation W-12C to calculate, rather than measure, the value of PRs,p (the average gas pr oduction flow rate duri ng 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 produc tion flow rate.

Calculating the gas production based on GOR is le ss 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 me tered gas data are available for the first 30-days of production, then the measured rates sh ould 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 calculati on 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 discu ssed 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 genera l approach applies data from a s ubset 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 Ga s 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, SierraClub, 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 needto collect and quantify emissions from the Gathering and Boosting segment to achi eve 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 inve ntory and emissions tr acking obligations for gathering pipelines, separators, compressors, aci d gas removal units, dehydrators, pneumatic devices and pumps, storage vesse ls, engines, boilers, heaters, and flares, we are in general agreement that using methodologies already existi ng in the rule provide consistency and reduces the reporting burden.

Commenter 0139: We strongly support EPA’s propos al 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 Marc h 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 CO 2 e (using a 100-year GWP of 25). 6 Building on the ICF analysis, EPA calculates that total annual process and co mbustion emissions from the segment amount to approximately 43.5 MMT CO 2 e. 7 These emissions not only constitute significant greenhouse gas pollution, but also represen t a loss of large quantities of valu able gas. For instance, analysis conducted by Clearstone Engineering found that ga thering segment compresso r stations lost an average of 97 metric tons of ga s per year per facility, amounting to thousands of dollars in lost gas value from leaking components. 8 In addition, in a recently-rel eased 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 CO 2 e, 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 Industr ies, 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 gl obal 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 – w ith 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 Di rected Inspection and Maintenance Control Opportunities at Five Gas Pro cessing Plants and Upstream Ga thering Compressor Stations and Well Sites, at 28 (2006); see also EDF, Oil and Natural Gas Sector: Compressors, Peer Review Responses of Environmental Defense Fund, at5 (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 Plan ts: 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 gather ing and boosting as its own industry segment.

Gathering and boosting is a unique op eration with a unique purpose. Historical treatment of this industry segment – either including it with produc tion or processing – has led to confusion with20 understanding industry data. We encourage EPA to continue to dis tinguish gathering and boosting as its own industry segment in othe r 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 Ons hore 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 defi nition of the new reporting segment of onshore petroleum and natural gas gathering and boosting. AP I also supports the statement that this new reporting segment would not include equipment a nd pipelines that are reported under any other industry segment defined in Subpart W.

Commenter 0137: API appreciates th e fact that the EPA is citi ng API Recommended Practice 80 as a guide to the definition of the new reporting segment of On shore 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 a nd Boosting segment, which specifies that the facility does not include equipmen t and pipelines that are part of any other industry segment, is finalized as proposed. In addi tion, similar language is incl uded 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 ca tegory definition includes the phrase, “Gathering and boosting equipment include s, 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 Petr oleum 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 boos ting equipment includes, but is not limited
to , gathering pipelines, separators, compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, st orage 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, EP A explains that they are proposing to use current methods in Subpart W fo r 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, w ith 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 defini tion is comprehensive and consistent with reporting requirements under the existing i ndustry segments in Subpart W. Therefore, leaving this definition open-ended serves no purpose other than creating confusion.

Footnotes22 3 ld

.

4 79 Fed. Reg. 73,154 (Preamble discussion of Ons hore Petroleum and Natural Gas Gathering and Boosting segment)

Response 3: The Onshore Petroleum and Natural Ga s Gathering and Boosting segment is intended to include all equipment and sources of em issions that could exist in this sector that would not otherwise be included in the Onshor e Natural Gas Processing, Onshore Natural Gas Transmission Compression, or Ons hore Petroleum and Natural Gas Production segments within Subpart W, as defined in 40 CFR 98.230. The inclus ion 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 a nd Boosting segment. Th erefore, the EPA does not agree that the phrase “but is not limited to” cr eates unnecessary confusion.

The EPA also notes that inclusion of the phrase “but is not limite d to” in the segment description is consistent with other industry segments curre ntly reporting under Subpart W. For example, the Onshore Petroleum and Natural Gas Production se gment is defined as “...all equipment on a single well-pad or associated wi th a single well-pad (including but not limited to compressors, generators, dehydrators, storage vessels, engines, boilers, he aters, flares, separation and processing equipment, and portable non-self-pro pelled equipment, which includes well drilling and completion equipment, workover equipment, a nd leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilizati on, separation or treating of petroleum and/or natural gas (inclu ding condensate)” (emphasis added).23 Commenter Name: Kathleen Sgamma Commenter Affiliation: Western Energy Alliance and Am erican 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 Boos ting segment (hereinafter referred to as the “Gathering and Boosting segment”), as outlined below. First, we are concerned that the definition, as stated, would unint entionally require collecting a nd reporting data of petroleum gathering pipelines and other associatedequipment. The proposal defines [ section 98.230(a)(9) ] onshore natural gas gathering and boosting systems as:

“...gathering pipelines and othe r equipment used to collect petroleum and/or natural gas from production gas or oil we lls and used to compress, dehydrate, sweeten, or transport the gas to a naturalgas processing fac ility, a natural gas transmission pipeline or to a nat ural gas distribution pipeline.”

Petroleum gathering pipelines and equipment are not used to compress, dehydrate, sweeten, or transport natural gas. Therefore, we request “pet roleum and/or” be stricken from the definition.

Commenter 0132: GPA agrees with API that th e 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 equi pment that EPA lists in the proposed rule are synonymous with natural gas gathering and boos ting systems and not liquid and petroleum gathering systems.24 Commenter 0134: Pioneer agrees with the Associ ations that the word “petroleum” should be struck from the definition of the “Onshore Petr oleum and Natural Gas Gathering and Boosting” proposed source cate gory 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 ga thering and boosting segment and should not be included in the definition. We believe it was EPA’s intent to ap ply this segment to gathering and boosting of natural gas only and this is evident when reading the first part of the defi nition 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 we lls and used to compress, dehydrate, sweeten or transport the gas to a naturalgas processing fac ility, a natural gas transmission pipeline or to a nat ural gas distribution pipeline... 1

By specifically including “the ga s” in the latter part of the sentence above, it is clear that the leaks and resulting fugitive emissions EPA is aiming to quantify in th e 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 un der this segment were developed for gas lines and it would be imprudent and would result in in accurate 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 EP A states, “The emission factors that are being proposed...are whole gas emission fact ors based on the U.S. GHG Inventory)

Commenter 0137: In order to streamline the de marcation of boundaries an d reporting obligations between the Production and Gatherin g/Boosting segments and to ensure consistency between the new segment and the emissions sources alrea dy covered, API offers three refinements:

API requests renaming this segment “Onshore Na tural Gas Gathering and Boosting”. Removing “petroleum” from the segment name, as markedin the definition below, provides a clear demarcation between the production segment a nd the gathering and boosting segment. This revision does not exclude any emission sources and is consistent with emission sources associated with compressing, dehydrating, sweete ning, or transporting the gas to a natural gas processing facility, a natural gas transmission pipeline or to a natu ral gas distribution pipeline, as specified in the source category definition.

Section 98.230 Definition of the source category

(a)(9) Onshore petroleum and na tural gas gathering and boosting. Onshore petroleum and natural gas gathering and boosting means gathering pipe lines and other equipment used to collect25 petroleum and/or natural gas (including associatedgas) from onshore pro duction 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 distribut ion pipeline. Gathering and boosting equipment includes, but is not limited to gather ing pipelines, separators, compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, storage vessels, engines, boilers, he aters, 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 Am erican 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 se gment lack clear dist inction and create overlap into the existing Onshore Petroleum a nd Natural Gas Production segment. Confusion as to who needs to report, and under which reportin g 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) federa lly 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 particul ar segment. Data may be mistakenly excluded within a particular segment when reporting resp onsibility 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 boos ting 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 owners hip 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 A lliance member company has noted that certain gathering and boosting equipment operated by th e upstream production company is actually owned by a separate and distinct midstream entit y. Under the rule as proposed, it appears that this equipment would fall under both the pr oduction 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 entitie s’ 25,000 metric tons of CO2e pe r year reporting threshold (i.e.,26 inclusion of the emissions would require GHG reporting, but exclusion would place the facility(s) below reporting thre shold(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 betw een 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) federa lly 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 Petr oleum 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 Am erican 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 multi phase gathering pipelines be excluded from the gathering/boosting segment and be retained as part of the production segment.

Commenter 0125: We believe it wa s not the intention of EPA to include petroleum gathering pipelines since the emissions would be neg ligible. Moreover, the proposed 2.81 scf/hr/mile emission factor is clea rly only applicable to gas gathering lines.27 Commenter 0137: Gathering and Boosting Segmen t – API requests that this new industry segment should also exclude petroleum gather ing pipelines, which have no fugitive gas emissions.

Commenter 0137: In order to streamline the de marcation of boundaries an d reporting obligations between the Production and Gatherin g/Boosting segments and to ensure consistency between the new segment and the emissions sources alrea dy covered, API offers three refinements:

API requests that multi-phase flow lines from we lls to a centralized production facility where initial separation occurs be excluded from th e gathering and boosting segment, and remain included in the Onshore Petroleum and Natura l Gas Production segment. The proposed fugitive emission factor for gathering pipelines was deve loped 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 Ga s Gathering and Boosting segment is finalized to include gathering pi pelines that are not in the Onshore Petroleum and Natural Gas Production segment ( i.e. , on or associated with a single we ll pad), including petroleum and multiphase gathering pipelines with a GOR of 300 scf/STB or grea ter. See Section II.B.1 of the preamble to the final rule for the EPA’s rationa le for this decision. S ee 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 ga thering and boosting fa cility boundaries include dehydrators that are lo cated on onshore petroleum and na tural 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 se gment will eliminate the concern of having producers report third-party co ntractors’ emissions, whic h the producers cannot certify.

Comment 0137: Gathering and Boosting Segment – To resolve API’s previous concerns with reporting emissions from third pa rty dehydrators, API urges EPA to include reporting emissions from dehydrators, which are owned and operate d by a third party, under the new Gathering and Boosting Segment, even if these deh ydrators are located on a production pad.

Comment 0137: API requests that gathering an d boosting facility boundar ies include dehydrators that are located on Onshore Petroleum and Natura l 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 dehydr ators into this newly created segment rather than including them with the Onshore Petroleum and Natura l 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 3rdParty Dehydrator OnsiteThis diagram illustrates that the flow lines from the wells, which may be multiphase, remain part of the Production segment. The 3rdParty operated dehydrator at the gathering facility is part of the Gathering/Boosting segment.30Scenario B: Central Tank Battery or Booster Station with3rd Party Dehydrator Onsiteand a Well Pad Located OnsiteIn this scenario, the well pad located at the gatheringfacility is reported under the Production segment. The 3rdParty operateddehydrator at the gathering facility is part of the Gathering/Boosting segment.31Scenario C: Well Pad with3rd Party Dehydrator On-siteAPI requests in this scenario that emissions associated with the 3rdParty dehydrator be reported under the Gathering/Boostingsegment. This eliminates issues associated with the production operator obtaining, reporting, and certifying emissions data fromdehydrators that are owned and operated by 3rd parties.Commenter 0142: Kinder Morgan un derstands 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 produc tion segment. Kinder Morg an agrees with this approach only to the extent that such third pa rty equipment at onshore petroleum and natural gas production well pads are owned and operated by th e same exact entity from whom EPA requires reporting of emissions in the gathering and boosting segment.

Response 7: The EPA agrees with Commenter 0137 thatthe dehydrators in Scenario A and B should be included in the Onshore Petroleum an d Natural Gas Gathering and Boosting segment, because those dehydrators are associated with mu ltiple 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 w ith 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 Petrol eum and Natural Gas Production segment in “Response to Public Comments on Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality Determinations for Petroleum a nd Natural Gas Systems” (see Docket Item No. EPA-HQ-OAR-2011-0512-0102), which stat es that if reporters electto 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 respon sibility for reporting the emissions from the entire facility, and that this reporting paradigm is c onsistent 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 cons ider 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 poten tial overlap between production and gathering/boosting if EPA allows dehydrators ow ned 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 st ations. As detailed above, API requests that the name of the segment be changed to Natural Gas Gathering a nd Boosting. Also, as indicated previously, API requests that gathering and boosti ng facility boundaries include dehydrators that are located on onshore well pads and operated by a gatheri ng 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 requ ests that mulit-phase flow lines remain I the Onshore Petroleum and Natu ral 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 our33 position on multiphase flow lines. In addition, as stated in Res ponse 7 in this section, the EPA addressed the issue of third- party dehydrators in the Ons hore Petroleum and Natural Gas Production segment in “Response to Public Co mments 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 avai lable, we reserve the ri ght 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 comm only used in the natural gas industry, although not always consistently defined. Furthe rmore, “boosters” or “boosting systems” are typically referred to by industry as compressor stations. Kinder Mo rgan 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 furt her 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 a nd boosting means gathering pipelines and other equipment used to collect petroleum and/or natural gas (including associated gas) from onshore producti on gas or oil wells and used to compress, dehydrate, sweeten, or transport the gas to a natu ral gas processing facility, a natural gas transmission pipeline, or to a natural gas distribution pipe line. Gathering and boosting equipment includes, but is not limite d to gathering pipelines, separators, compressors, acid gas removal units, de hydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters, and flares.

See 79 Fed. Reg. at 73,175 (citing pr oposed 40 C.F.R. 98.230(a)(9)).

In its Technical Support Document, EPA identifie s 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); and34  Combustion sources (e.g., e ngines, 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; ProposedRule,” 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 unde rstand 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 currentuncertainty as well as other concerns, Kinder Morgan proposes the following revisions to EPA’s proposed definition.

EPA Proposed section 40 C.F.R. 9 8.230(a)(9): Onshore petroleum and natural gas gathering and boosting . Onshore petroleum and natural gas gathering and boosting means gathering pi pelines and other equipment used to collect petroleum and/or natural gas (i ncluding associated gas) from onshore production of gas or oil wells and usedto compress, dehydrate, sweeten, or transport the gas to the inlet (i.e., the fen ce-line) of a natural gas processing plant facility, a natural gas transmission pipe line, or to a natural gas distribution pipeline. Gathering and boosting equipm ent 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 dr ive compressors or generators, and flares. The gathering and boosting segment doe s not include compression, dehydration, and sweetening units located at onshore na tural gas processing plants. Gathering and boosting equipment shall not include equipment and pipelines that are reported under any other i ndustry segment defined in Subpart W (e.g., the onshore natural gas transmission pipe line industry segment).

Kinder Morgan also proposes the following re visions definition to th e onshore natural gas processing segment to clearly demarcate be tween gathering and boos ting 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 pr ocessing plant. Natural gas processing means the separation ofnatural 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 liqui ds, sulfur and carbon dioxide removal, fractionation of NGLs, or the capture of CO 2 separated from natural gas streams. This segment also includes all resi due gas compression equipment owned or operated by the natural gas processing plan t. Onshore natural gas processing plant means any process site engage d in the extraction of natu ral gas liquids from field gas, fractionation of mixed natural gas liq uids to natural gas products, or both. that fractionate gas liquids, and proce ssing plants that do not fractionate gas35 liquids but Only those onshore natural ga s processing plants th at have an annual average throughput of 25 MMscf per day or gr eater are subject to this Subpart W. A Joule-Thompson valve, a dew point de pression 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 propert y as an onshore natural gas processing plant as previously defined: comp ressor stations, dehydration units, and sweetening units. 1 Onshore natural gas processi ng plant shall not include pipelines or equipment thatis reported under any other industry segment defined in Subpart W.

Kinder Morgan believes implementation of th e above-stated revisions to EPA’s proposed definition of the “Gathering and Boosting Segm ent,” and onshore natura l 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 understandi ng of what sources and equipment are included under each segment; (2) en sures consistency for reporting of emission sources associated with compressi ng, dehydrating, sweetening, or tr ansporting the gas to the inlet of a natural gas processing fac ility, 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 repo rted under any other indu stry segment; and (4) eliminates duplicative reporting requirements. Kinde r Morgan also requests that in addition to the proposed changes above, EPA discuss in deta il 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-propo sed changes would clarif y 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 implementatio n 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 proces sing plants that do not fracti onate 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 98.23 0(a)(9) would be a helpful clar ification to the definition of the industry segment. Therefore, the last sentence of the fina lized 40 CFR 98.230(a)(9) reads: “Gathering and boosting equipment does not in clude 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 98.23 0(a)(9) is redundant with this last sentence; therefore, the EPA is not finalizing th at suggested change.36 See Section II.B of the preamble to the final ru le for the EPA’s response to the commenter’s suggested inclusion of the word “petroleum” and removal of th e 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 na tural gas processing f acility (e.g., the suggested addition of the term “fence-line”). As stated at proposal, th e EPA decided not to make any changes to the existing segment descriptions to provide consistenc y 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 confusi on 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 Natura l Gas Processing to be consistentwith the definitions in NSPS 40 CFR part 60, subpart OOOO, the EPA notes thatgiven this is a reporting rule and does not require reductions in air emi ssions, the EPA has determined that it is appropriate to use potentially different nomenclature, as deemednecessary, from existing or contemplated regulatory air programs. For all these reasons , no changes are being made to the existing definition in this final rulemaki ng. Instead, the EPA is reiterati ng the intention for the Onshore Petroleum and Natural Gas Gathering and Boos ting segment to encompass everything between the existing definitions for the Onshore Petrol eum 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 Dis tinction Between Onshore Natural Gas Processing and Onshore Petroleum and Natural Gas Gathering and Boosting Industry Segments.

CO 2 and sulfur dioxide (SO 2 ) removal cannot define both a gas processing plant and a gathering and boosting facility.

The definition of a gas processing plant is well es tablished in the contex t of the Clean Air Act (CAA) and it does not incorporat e stand-alone gathering and boosting systems. Gathering and boosting systems can share some similar equipmen t 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 th e 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 plan t. This is not consistent with the definitions of gas processing plants currentl y codified in 40 C.F.R. Part 60 Subpart KKK, 40 C.F.R. Part 60 Subpart OOOO, and 40 C.F.R. Pa rt 63 Subpart HH, which limits gas processing plants to those sites engaged in liqui d extraction and/or NGL fractionation only.37 Under the current definition in Subpart W, aci d 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 improv e consistency between CAA rules and to avoid confusing scenarios where a faci lity with sulfur and carbon dioxide removal could be applicable to both industry segments and result in dup licative reporting, GPA proposes modifying the

“ Onshore natural gas processing ” definition to exclude sulfur a nd carbon dioxide removal. This would alleviate confusion and potential duplic ative reporting and result in only those nonfractionating, non-liquids extracti on facilities reporting under th e 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 foll owing: forced extraction of natural gas liquids, sulfur and carbon dioxide removal, or fractionation of NGLs, or the capture of CO 2 separated from natural gas streams.

If EPA agrees to modify the onshore natural ga s processing definition in section 98.230(a)(3) to exclude sulfur and carbon dioxi de removal, GPA is supportive of retaining the annual average throughput of 25 million standard c ubic feet (MMscf) per day or gr eater 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 recomm ends removing AGRs from the ONGGB industry segment since they are alr eady monitored and reported under the Onshore Natural Gas Processing industry segment. In a ddition to the definition of onshore natural gas processing in section 98.230(a)(3), AGRs are spec ifically defined in section 98.238 as a process unit that separates hydrogen sulfide and/or carbondioxide from sour natu ral gas using liquid or solid absorbents or membrane se parators. Therefore, the inclusi on 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 emi ssion sources from the Onshore Natural Gas Processing segment. See Section II.B.1 of the prea mble 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 incorpor ating 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 threshol d value for non-fractionating pro cessing plants in both industry segments. This would allow for consistency be tween the industry segm ents, ease the reporting burden, and still capture necessary GHG data. S econd, GPA recommends th at non-fractionating processing plants always remain subject to on ly one industry segment for reporting purposes. It is not reasonable or logical to re quire a facility to change appli cable industry segments from year to year based solely on the annual natural gas throughput of the facilit y. 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 segm ent and AGRs located at a facility that extracts or fractionates NGLs would report unde r the onshore natural gas processing industry segment.

Commenter 0133: EPA specifically requested comments regarding th e categorization of Gathering and Boosting as a segment separate from the Production segment and the Processing segment and whether or not previous concer ns 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 st andard cubic feet per day (MMscf/day) being included in the Gathering and Boosting segm ent. 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 sp ecified in Subpart A. We agree that the proposed regulation is clear that the same processing f acility should in no way report under both segments of the rule in any given year.

Commenter 0142: Kinder Morgan also respectful ly requests that EPA make clear in the preamble to any final rule that EPA does not intend to obligate facilities and equipment to39 “switch” segments at any point in time. Instead, as Kinder Morgan has pro posed 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 Subpa rt W, while certain facilities that treat natural gas as part of the Gather ing and Boosting segment would be re quired to report as part of the Gathering and Boosting segment without rega rd to such individua l throughput thresholds. Implementation of a rule that could require opera tors 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 proces sing plants that do not fracti onate 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 th e provision that nonfractionating processing plants s hould not report in more than one industry segment in one reporting year. The EPA is not finalizing any sp ecific provisions re garding non-fractionating processing plants in the final rule. Non-fractiona ting 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 th e Onshore Petroleum and Natural Gas Gathering and Boosting segment. As stated at proposal and re iterated in the preamble to the final rule, the EPA is changing the segment description or re lated 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, SierraClub, 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 compre hensive data on gathering pipelines will help to further improve understand ing of emissions from these sources. The 2014 Greenhouse Gas Inventory estimates that ther e 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 Na tural Gas Association of America estimates that 16,500 miles per year of new gathering pipe lines will be required from 2011 to 2035. 13

Gathering pipelines in rural areas have not hi storically 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 separate40 requirements for this infrastructure. 15 As a result, companies have not generally been required to report the location and characte ristics of gathering pipeline s installed in rural areas. 16 A recent Government Accountability Office report r ecommended that the DOT and PHMSA move forward with a rulemaking to address gathering pi peline 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 mon itor operators’ safety practices is lacking.” 17

Accordingly, strengthened reporting requireme nts are essential to provide transparent information concerning emissions from existing in frastructure and recent ly increased pipeline mileage. 18

Compressors . Compressors in the gathering and boosting segment are also significant sources of emissions. According to independent analysis c onducted by ICF International, which analyzed available data from five states to devel op 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 source s 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 providi ng a deeper understanding of this significant source of emissions.

Storage Tanks . The ES&T Study also includes informa tion concerning emissions from storage tanks at gathering facilities. In particular, the study found s ubstantial venting from liquids storage tanks at approximately 20 percent of sampled gathering faci lities. 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 ta nk 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 Ga s 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, O il and Gas Transportation: Department of Transportation is Taking Actions to Address Rail Safe ty, 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 du ring 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, SierraClub, 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 reporti ng of GHG emissions from equipment used by gathering pipeline systems and natural gas proc essing plants, transmi ssion pipelines, and42 distribution pipelines. EPA proposes to define “facility” with respect to onshore petroleum and natural gas gathering and boosting as all gather ing pipelines and other equipment located along pipelines under common owners hip or control by a gatherin g and boosting system owner or operator and that are located in a single hydroc arbon 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 “f acility” could encompass thousa nds 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, a ll the way across south and southeast Texas, and on into the entire southern half of Louisiana, covering 104 coun ties 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 a nd 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 collect ed together and deemed, per EPA fiat, to constitute a single “facility” for purposes of determining the app licability 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 do es 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 gather ing and boosting sources for purposes of complying with Subpart W GHG emissions calcul ations 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 pe rson owns or operates in a single production basin is finite. In contrast, gatheri ng and boosting equipment, when a ssessed on a basin-wide basis, can entail hundreds or thousands of miles of pipelin es with multiple sites, including interconnects, meter stations, scrubber stations, pigging stations, compressor stat ions, and gas treating plants, composed of tens of thousa nds of individual components, i.e. a huge number of small emission43 points spread across vast areas of land. Just gathering an accura te 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 woul d 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 an d boosting systems in the Gulf Coast Basin in Texas, shows that the many sites and associated components that w ould 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 syst em 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 networ k of connections to meter stations, pigging stations, compressor stations, sc rubbers, and interconnects. (Not e: only compressor stations are noted on the map.) Along this system alone, ther e 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 infeasib le for the gathering and boosting sector, even if EPA has deemed it appropriate in the production sector.

In addition, the owner or opera tor of a gathering and boosting system would also have to undertake a huge effort simply to determine whether the proposed new re porting rules applied to the system in the first place. Every gathering sy stem would have to be evaluated to determine whether combined emissions from the multiple components in a single system exceed the 25,000 tpy CO 2 e reporting threshold. As an example of the burden that this would cause, one TPA member owns or operates eight se parate facilities in a single hydrocarbon basin, due to separate ownership structures. Within t hose eight facilities are 275 compressors and 2,179 separate pieces of equipment. This company would have to ev aluate 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 ju st to ascertain whether the repo rting 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 th e 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 justif y the use of that approach for sources in the gathering and boosting segment.

The basin-wide definition for “facility” is co ntrary to traditional notions of aggregation under the federal Clean Air Act.

In addition, under the proposed f acility definition there would be a substantial disconnect between the concept of a single facility in these Subpart W ru les 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 could44 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 th e 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 informedby the D.C. Circuit’s direction that a single source definition should approximate the comm on sense notion of a plant and should avoid aggregating pollutant-emitting ac tivities 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 adj acent” test, do not fit within the common sense notion of a plant, and ar e not even functiona lly inter-related.

EPA has repeatedly emphasized that the GHG reporti ng 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 collec tion efforts in a manner so very different from the structure traditionally used in other Clean Ai r Act programs, such as the PSD program. Clean Air Act program implementation and development ca nnot 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 (conti guous or adjacent; common sense notion of a single plant).

Indeed, EPA’s approach to aggregation in the current proposal is dire ctly contrary to EPA precedent. Specifically, EPA emphasized the inappropriateness of aggregation along long lengths of pipeline in the preamble to the 19 80 amendments to the final PSD rules:

EPA has stated in the past and now conf irms that it does not intend “source” to encompass activities that would be ma ny 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 a pproach, however, EPA’s cu rrently 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 Subpa rt W reporting context is not the same as the stationary source permitting contex t, but to do so represents a stark departure from EPA’s long-standing concept that a singl e source encompasses the commonsense notion of a plant. In fact, Congress also expressed its disapproval of overly br oad 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 pipeli ne 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 or45 production well (with its associated equi pment), such emissions shall not be aggregated for any purpose under this section. 7

Presumably this is why EPA stated, in the pr eamble 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 m eans any physical property, plant, building, structure, source, or stationary equipm ent located on one or more contiguous or adjacent properties in actual physical c ontact 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 establis h reporting thresholds at the fac ility 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 mu ch that a gathering and boosting facility would be a “facility” in name only – in the EPA defin itional sense only – not in the real world manner in which a facility has trad itionally been defined and unde rstood by the industry. The term “facility’’ should comport with real oper ations, and with the common and traditional understanding of what a facility ac tually is in the real world; and no reasonable or traditionally understood concept of the term “facility” in the gathering an d boosting industry can encompass myriad components stretching over multiple countie s and covering hundreds of square miles. An agency could inform Starbucks that reporting thre sholds 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 boostin g industry segment would not be reported because they would fall below the applicab ility threshold. Circumventing the 25,000 tpy CO 2 e 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 inconseque ntial sources to burdensome reporting requirements.

A basin-wide approach to fac ility definition would require re porting parties to measure and report emissions from myriad insignificant s ources which, when combined with other small sources, would in toto constitute a “facility” whose aggr egated emissions exceed the 25,000 tpy CO 2 e 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 expre ssly 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). 1046 The basis for establishing a reasonable repo rting threshold is to ensure that reporting requirements are not imposed on in significant sources of emissions. See 74 Fed. Reg. 16467 (April 10, 2009) (EPA states that the 25,000 tpy CO 2 e threshold is intended to gather useful information while minimizing reporting burden and excluding small sources of emissions). This is a logical and laudable goal, b ecause requiring reporting from insi gnificant sources is not costeffective, because little can be learned from re porting by small sources, and because it simply is not fair to impose the often-s ubstantial costs associated withthe GHG reporting rules on sources whose emissions are minimal. However, the la udatory 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 eliminat ed 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 CO 2 e threshold if EPA is then going to define the term “facility” so broadly that the intent of the threshold – to “exclude[] small emitters” – is comp letely undone by the same agency that set the threshold in the first place.

In addition, EPA’s proposed definition would resu lt 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 conten t of natural gas can vary widely in different parts of a gathering and boosting system, with s ubstantial 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 “faci lity.” 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 datathat is the product of default va lues is of far less value than data that is the product of actual measurement a nd calculation. Indeed, re porting of emissions via the use of emission factors would essentially be a report of an equipm ent count, as the total estimated emissions would simply be the produ ct of pieces of equipment multiplied by the emissions factor. When emissions data are th e 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 differe nces in operating practi ces 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 ne w and useful information for EPA’s use.47 Moreover, it should be noted that the proper colle ction of new and useful information for EPA’s use would involve monitoring and measurement, wh ich would dramatically further increase the burden on reporters. According to EPA, a fundame ntal goal of the GHG reporting system is to “[o]btain data that is of suffici ent quality that it can be used to support a range of future climate change policies and regulations.” 11 But defining a gathering and boos ting 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 Geologi sts, there can be substantial differences in gas composition, geological features, and operationa l 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 disparat e information within the same overall facility’s Subpart W reports. Such aggregated information, which w ould 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 fu ture EPA regulatory activities. Given the likelihood of significant differences in the c onditions under which reported emissions were produced, it would be difficult to draw meaningful conclusions fr om data generated under EPA’s proposed concept of “facility’’ in the gathering and boosting contex t. This fact, combined with the fact that EPA already has access to a s ubstantial amount of GHG reporting data from reporters in the oil and gas industry, shows thatthe potential regulator y benefits of these proposed new rules would be substantially outwe ighed by the additional burden that they would impose on companies in the natural gas industry.

EPA has not provided a reasoned justification fo r 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 mustreport under Subpart W only if combined emissions from all sources within that facility exceed 25,000 tpy CO 2 e. 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 wi ll be required of all of the sources grouped within the expansive concept of “faci lity”. EPA admits this to be tr ue, as the agency states in the preamble to this proposal that it expects the proposed new Ons hore 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-wi de facility definition is implemented: “[W]hen aggregated with the gathering pipelines and ot her 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 s ources in the gathering and boosting industry, what EPA has failed to do is provide a reasone d justification for why it is reasonable to aggregate gathering and boosting s ources 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 S ection 114 of the Clean Air Act, 13 which authorizes EPA to collect such information as may be “ reasonably require[d].” 1448 The fact that EPA’s data reque sts 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 requi rements against industry’s argument that they “fail[ed] to meet the standard of reasonablen ess applicable to reque sts 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 purpos e and were neither overl y 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 defe nds its proposed basin-wide approach on the ground that it w ould reduce the burden on reporters, 17 yet it is clear that the contrary is true, and that EP A’s proposed basin-wide aggrega tion 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 in significant sources of emissions, given that they would all be encompassed within EPA’s br oad concept of a gathering and boosting facility. Thousands of small sources would be covered and required to report b ecause they would be encompassed within a single artificially defined “facility” that, in toto , would exceed the 25,000 tpy CO 2 e reporting threshold because the threshol d would be measured based on combined emissions from a multitude of improperly grouped sources.

The proposed rules would thus impose costly and complex reporting ob ligations on entities operating countless numbers of components scattered over huge geographic areas. 18 In short, EPA’s proposal to define a facility in this manne r would result in a report ing 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 da ta of limited usefulness. Because the proposed definition would not meet the reasonableness lim itations placed upon EPA by the Clean Air Act, it would exceed EPA’s statutory authority under Secti on 114 of the Clean Air Act. At the very least, EPA should come forward w ith a reasoned justification for its onerous and costly reporting program that incorporates a radi cally new approach to aggrega tion in the gathering and boosting context and results in da ta of limited usefulness.

The definition of “facility” in the gathering an d 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 ba sin-wide approach to facility definition in the gatherin g and boosting reporting rules. We urge EPA to define “facility’’ in this context so that the facility does not extend beyon d the fenceline, as is currently provided in Subpart A of the GHG reporting rules and as ap plied 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 mo re 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 orcommon control, that emits or may emit any greenhouse gas. 1949 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 ons hore petroleum and natural gas production for purposes of reporting under this subpart and fo r 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 CO 2 EOR operations that are under common owne rship or common control including leased, rented, or contracted activities by an onshor e petroleum and natural gas production owner or operator and that are located in a single hydroc arbon 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 a ssociated 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 deci sions, including potential regulation under the CAA.”); 74 Fed. Reg. 16454 (April 10, 2009) (where EP A 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 th e 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 expa nsive definition of “facility” would be contrary to current federal practice and preced ent 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 unle ss they are physically adjacent within the normal meaning of the term, i.e. they are touching. That is the comb ined 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 Associ ation’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 prea mble to adoption of the initial GHG reporting rules, EPA explains that it chose a 25,000 tpy CO 2 e 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 t housands 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 au thority 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 natu re of the proposed rules is that they could require reporting of blowdowns from the gath ering and boosting industry segment, even though blowdowns likely account for less than one percent of overall CO 2 e emissions in this industry segment. It is difficult to see the justificati on for imposing reporting requirements for such an insignificant source of emissions.

19 40 CFR 98.6.

Commenter 0132: GPA commends EPA for recognizi ng 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 repor ting 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 gather ing 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 maintain s operations and moves gas within one basin. It51 is unclear why EPA is trying to place the gathering and boosting industry segment into a category that clearly does not f it 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 (CO 2 e) 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 su rvey of several GPA member companies indicates a threshold of 650 HP w ould reasonably represent 80-85% of member company facilities. This is consistent with EPA’ s desire in the original Subpart W Fact Sheet 5 to collect 85% of industry wide GHG emissions. In other words, emissions from only the equipment located within any individual gatheri ng or booster station with in a single county or parish that has at least 650 HP or HP equiva lent will be compiled and applied towards the 25,000 mt CO 2 e threshold. In doing this, EPA will significantly decrease the reporting burden placed on reporters and small businesses with small fac ilities. 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 petr oleum and/or natural gas from onshore production gas or oil wells and used to compress, dehydrate, sweeten, or transport the gas to a natu ral gas processing facility , a natural gas transmission pipeline or to a naturalgas distribution pipelin e. Gathering and boosting equipment includes, but is not limite d to gathering pipelines, separators, compressors, acid gas removal units, de hydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters, and flares.

Gathering and boosting equipment includes on ly 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. 152 Section 98.238 Definitions

Facility with respect to natural gas gathering and boosting for purposes of reporting under this subpart and for th e 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 t hat 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 boosti ng 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 ow ner or operator of the gathering and boosting system that contains the pipeline.

The facility does not include equipment and pipelines t hat are part of any other industry segment defined in this subpart nor equipment located at a gathering or boosting site (as provided in the definiti on of facility in Subpart A) with less than 650 manufacturer rated HP or manu facturer rated HP equivalent.

Footnotes:

2 EPA Climate Change Divisi on, Greenhouse Gas Reporting Rule: Technical Support for 2015 Revisions and Confidentiality Determinations fo r 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 (Tec hnical Support Document).

3 Id. at 13-15.

4 Id. at 13.

5 Proposed Rule – Mandatory Re porting of Greenhouse Gases from Petroleum and Natural Gas Systems – Subpart W; Fact Sheet: 2010 Pr oposed Rule – Subpart W, (Apr. 12, 2010) available

at

http://www.epa.gov/ghgreporting/docum ents/pdf/2010/Subpart-W_factsheet.pdf.

Commenter 0139: EPA proposes to define a gathering and boosti ng facility to include all gathering pipelines and other equipment unde r 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 conne ction points to natural gas and oil production and a downstream endpoint. 23 EPA requests comment on two alternative approaches to defining53 gathering and boosting facilities: 1) using the facility approa ch described at 40 C.F.R. 98.6, which would more narrowly define a gathering a nd boosting facility; or 2) separating gathering and boosting stations from pipelines, with the former reporting at a basin leve l and the latter at a national level. 24

We support EPA’s primary proposal to use a basin- level approach to repo rting in the gathering and boosting segment for both stations and pi pelines. This approach will facilitate straightforward implementation for reporters w ho can streamline reporting for all gathering and boosting pipelines and equipment in one basin an d will also clearly in tegrate 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 Am erican 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, ga thering and boosting systems may cross among multiple reporting basins. We are requesti ng 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 Petrol eum 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 determ inations to see if each basin’s emissions exceed the annual 25,000 metric tons of CO 2 threshold. We request that EPA consider allowing an operating company to submit one combined report, re gardless 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 emi ssion sources are located could be used in the emissions calculations in or der to ensure that geographi c variability is captured.

Commenter 0137: The rule proposes to define a f acility 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 ope rator and that are lo cated 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 f acility boundaries include dehydrators that are located on Onshore Petroleum and Natural Gas Pr oduction 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 a nd Natural Gas Production segment will eliminate the concern of having producers re port third-party contractors’ emissions, which the producers cannot certify.

API also offers language to address the situ ation where boosting and gathering systems extend beyond the boundaries of a single AAP G basin. For example, one gathering system spans across southwest Wyoming (Green River basin 535) and th e adjacent Central Wester n 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 petroleu m and natural gas gathering and boosting for purposes of reporting under this su bpart 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 syst em owner or operator and that are located in a single hydrocarbon basin as defined in this se ction. Where a person owns or operates more than one gatheri ng 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, includi ng leased, rented, or contracted activities, is considered to be under common control of the owner or operator of the gathering and boosting syst em that contains the pipeline. The facility does not include e quipment 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 basi n, 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 th ese 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 prov isions, Onshore Petroleum and Natural Gas Gathering and Boosting reporters should s ubmit 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 CO 2 e 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 em issions into one report. We request that the reportin g entity be based on operating company, which could be a subsidiary of a larger parent company. As stated previousl y, 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 re port to the FERC under the subsidiary name rather than the parent company name.
Response 1: The EPA is not finalizing any changes to th e proposed definitions as a result of this comment. If the “two separate operating entitie s” each meet the definition of “facility with respect to onshore petroleum and natural gas ga thering and boosting for purposes of reporting under this subpart and for the co rresponding 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 requ irements at 40 C.F.R. § 98.4 regarding “authorization and responsibilities of the designa ted 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 thei r 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 th ey 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 a nd boosting system, a natural gas transmission pipeline, or a distribution pipeline; or (2 ) is responsible for cust ody of the gas transported.

The purpose of including the last phrase of the de finition is to address ownership scenarios for vertically integrated companies for which cont racts are not needed to transfer gas from production wells to natural gas processing plan ts. The EPA requests comment on whether this phrase addresses that concern.

API proposes to confine the defi nition of a gathering and boosting system owner or operator to transportation of natural gas rather than petroleu m and natural gas. This is consistent with the emission sources associated w ith compressing, dehydrating, sweeten ing, or transporting the gas to a natural gas processi ng facility, a natural gas transmissi on pipeline or to a natural gas distribution pipeline, as specified in the sour ce 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 pe troleum and natural gas gatheri ng 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 me tric tons of CO 2 equivalent threshold for reporti ng associated with the gathering and boosting segment per the API proposed revisions to the source definiti on and facility definition provided below.

Section 98.231 Reporting threshold (a) You must report GHG emissions under this subpart if your fa cility contains petroleu m and natural gas systems and the facility meets the requirements of se ction 98.2(a)(2), exc ept for the industry segments in paragraphs (a)(1) throu gh (a)(4).

(1) Facilities must report emissions from the onshore petroleum and natural gas production industry segment only if em ission sources specified in paragraph 98.232(c) emit 25,000 metric tons of CO 2 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 CO 2 equivalent or more per year.

(3) Facilities must report emissions from the onshore petroleum and natural gas gathering and boosting industry segment onl y if emission sources specified in paragraph 98.232(j) emit 25,000 metric tons of CO 2 equivalent or more per year.

(4) Facilities must report emissions from the onshore natural gas transmission pipeline industry segment only if em ission sources specified in paragraph 98.232(m) emit 25,000 metric tons of CO 2 equivalent or more per year

Commenter 0142: Kinder Morgan supports th e use of the 25,000 metric tons of CO 2 equivalent threshold within a single hydrocarbon basin for reporting associated w ith 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 CO 2 e 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 Document 11 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 indi vidual 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 sh ould 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 th reshold, the burdensome task of cal culating physical blowdown volume by assessing block valve location a nd measuring all equipment and pi ping between block valves and documenting the results is not alle viated with a physical size th reshold. Prudent operators would not “eyeball” equipment to assess physical vol ume and records of applicability evaluations would be maintained.60 Gathering and boosting facilities are geographically dispersed a nd often unmanned. Pipelines are never manned.

As EPA recognizes in the Technical Support Document, ONGGB equipment is, like Onshore Production equipment, geographically dispersed a nd 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 Ons hore Production, but not for ONGGB. It is also unclear why EPA allows cert ain more “livable” approaches in the proposed rule for ONGGB due to the geographically disp ersed 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 include d in the ONGGB industry segment.

Just because an activity occurs and a calcu lation methodology exists does not mean it is necessary or should be used. In the Technica l 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 Inform ation on Greenhouse Gases Tool to evaluate emissions from over 125 facilities. In the curr ent rule, blowdown vent stack emissions are reported in three industry segments: Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, and LNG Import a nd Export Equipment. GPA only examined facilities that reported blowdown emissions, and at those faciliti es, the average contribution of blowdown emissions was just 1.8% of total facility CO 2 e emissions. The median contribution was just 0.2% of total facility CO 2 e emissions. GPA notes that th is does not even include the facilities that reported zero blowdown emissions (w hich 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 da ta to determine the contribution of blowdown emissions to total facility emissions. We exp ect 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 fi nds no reason to believe that the ONGGB industry61 segment would experience a significantly highe r 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 whic h 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 Segmen t – API requests that this new industry segment should exclude reporting of blowdown vent emissions, consistent with the exclusion of this source from the Onshore Petroleu m and Natural Gas Production segment.

Commenter 0137: API notes that blowdown reporti ng 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 th at emissions from blow down vents stacks are included in other Subpart W segments where th e blowdown vent stacks are at consolidated facility sites. This is not the case in the Ga thering and Boosting Segment where a facility is defined as operations across an entire AAPG ba sin and according to the TSD: “blowdown vent stacks are located at various points along a gath ering pipeline at some distance between the connection points for the various production fi elds and compression boosting stations.”

Response 2: The EPA is finalizing the requirements fo r blowdowns of equipment in the Onshore Petroleum and Natural Gas Gathering and Boosti ng 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 Am erican 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 gatherin g pipelines”, and s ection 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 blowdow n activities at “field” locations that are located outside the fence line of typical gather ing and boosting facilities (e.g., compressor stations, central tank batteries) woul d be excessive and infrequent. Moreover, the majority of blowdowns typically occur at ma nned or frequently visi ted facilities where information needed for GHG emissions calculations can be readily logged. Therefore, we request62 that blowdown events that occur outside the fenc e line of gathering and boosting facilities be excluded from GHG reporting.

Response 3: The commenter used the term “outside th e 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 th at this approach would define a “station boundary” in a ll 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 si gnificant source of emissions.

However, the EPA is aware that some gath ering 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 pres ent and during planned events. For some blowdown vent stacks, particular ly 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 (p sia) specify that engineering estimates based on best available information ma y be used for emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities. This clar ification specifically addresses the unique nature of the Onshore Pe troleum 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, SierraClub, 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 fo rms of venting and flaring that occur at gathering and boosting facilities ar e included in reporting requiremen ts 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 gather ing 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 Confid entiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule” (D ocket Item No. EP A-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 safety63 reasons, most unwanted associated gas at a central gathering point will be flared, and any flaring of associated gas that occurs at these centrali zed points would be includ ed in the gathering and boosting facility’s flare stack emissions. Similarl y, 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 gath ering point is expected to be mi nimal. 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 venti ng and flaring” as a specific emission source in the Onshore Petr oleum and Natural Gas Gathering and Boosting segment. We are clarifying with this response that because we ar e not separating out associated gas venting and flaring in the Onshore Petr oleum and Natural Gas Gathering and Boosting segment, then any flaring of associated gas that occurs at centralized poi nts 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 s hould 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 Pi oneer, approximately 600 m iles 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 effectand 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 th e proposed Gathering and Boosting segment of Subpart W.

Response 5: The EPA agrees with the commenter thatgathering 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 de scription 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 Ve nted Emissions equipment type for the Onshore Petroleum and Natural Gas Gath ering 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 ve ry burdensome and is not justified in the proposed rule or supporting materials.

 Annual tank specific data would be requi red for every single tank in the ONGGB industry segment.

 EPA underestimates that there are eight tanks per reporter.

 Additional tank specific data would be requi red for an unknown portion of tanks in the ONGGB industry segment.

 EPA estimates of burden do not account for a ll tasks and underestimate the burden of each task.

 Combining the requirements for storage ta nks in the ONGGB industry segment and the Onshore Production industry segment resu lts 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 pr ovide 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 sugg ested there are major differences between the segments but did not give specifi c examples where these differences would require that Onshore Petroleum and Natural Gas Gathering and Boosti ng storage tank emissions be calculated using a substantially different appro ach than Onshore Petroleum a nd Natural Gas Production storage tanks. Therefore, Onshore Petroleum and Natu ral Gas Gathering and Boosting facilities are required to report emissions from storage tanks using the same calculation methodologies as for Onshore Petroleum and Natura l Gas Production storage tanks.

The commenter identified specific concerns within each of the bulle ts 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 data65 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 ve ry burdensome and is not justified in the proposed rule or supporting materials.

 Annual tank specific data would be require d for every single tank in the Onshore Petroleum and Natural Gas Gathering and Boosting segment.

 The EPA underestimates that ther e are eight tanks per reporter.

 Additional tank specific data would be requi red for an unknown portion of tanks in the Onshore Petroleum and Natural Gas Gath ering and Boosting industry segment.

 The EPA estimates of burden do not account fo r all tasks and underest imate 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 Se ction 3.2.3 of this document for responses to comments related to Onshore Petroleum and Na tural Gas Gathering and Boosting “operating scenarios that are not contemplated by the curr ent 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 effo rt and reporting requirement hinges on emission estimates that EPA summarizes by saying, “[p]redi cting and evaluating non-flashi ng 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 Technica l Support Document at 134 (Apr. 12, 2010), available at66 http://www.regulations.gov/contentStreamer ?objectId=0900006480aae5ed&d isposition=attachm ent&contentType=pdf.

Response 7: The requirements for stuck dump valv es 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 de scribes the calculation methodologies for estimating storage tank emissions and is not re lated to stuck dump valves. As noted in Mandatory Greenhouse Gas Reporting Rule Subpar t 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. Th ere 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 Couns el on Environmental Quality indicate that sticking, leaking orvortexing through dump valv es is not an uncommon cause of excessive gas emissions from fiel d tanks. The fact that these emissions may go un-noticed or undetected fo r long periods in remote, un-manned operations suggests that basing tank em issions solely on separator liquid properties could significan tly 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 ex cessive emissions is occurring, and adjustment of liquid flashing emissions fo r 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, publ ic data on crude oil stock tanks...

“In today’s final rule, EPA does not requi re reporters to arbitrarily determine whether conditions in the tanks are actual ly 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 problemexists, more so in some fields.”

The commenter did not provide suffi cient rationale with respect to stuck dump valves to prompt the EPA to reconsider this jus tification. Therefore, stuck dump va lve 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” storag e tank is unclear. Is there a threshold pressure over which a tank is considered non atmo spheric? 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 ps i (11.2 oz/in2) for pressu re 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 w ould help us identify a nd characterize our tanks.
Response 8: As stated in 40 CFR 98. 233(j), subpart W includes “emissions from atmospheric pressure fixed roof storage tanks receiv ing hydrocarbon produced liquids from onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities.” Therefore, the Onshor e 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 Sectio n 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 whet her 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 atmos pheric storage tanks wi th 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 CH 4 , CO 2 , and N 2 O (when flared) emissions from atmospheric pr essure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore petrol eum and natural gas production facilities and onshore petroleum and natural gas gathering a nd boosting facilities...” Therefore, no further clarification regarding br ine 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 genera tors, steam boilers, and process heaters

. Response 10: The EPA thanks the commenter for their s upport. 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 us e of manufacturer data, test data, measurement and/or monitoring da ta 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 pres cribed in Subpart W and Subpart C for the ONGGB. As indicated above, a significant major ity of companies in the ONGGB segment have not been subject to an emissi ons inventory obligation and ther efore 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 seal s (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 re presentation 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 perfor mance specifications, etc.), emi ssions 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 “c riteria pollutant” emissions inventories in which an emissions reporting hierarchy is applied. The reporting hierarchy include s: (1) source-specific emissions testing, measurements, monitoring; (2 ) representative emissions based on testing, measurement, and/or monitoring of in-kind s ources; (3) manufacturer specifications; (4) emissions estimation tools (e.g. EP Tanks, Glycal c); (5) established emi ssions 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 acq uire sufficient data to revise the existing prescribed emissions factors (many of which ar e 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 comment s relate specifically to the emissions calculations and reporting component of the proposed rule. Southw estern Energy is supportive of the use of emissions factors to minimize th e burden of reporting entities. However, we recommend that the rule allow the reporting en tities to report their emissions based on data/information that provides the best represen tation 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 perfor mance specifications, etc.), emi ssions 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 “c riteria pollutant” emissions inventories in which an emissions reporting hierarchy is applied. The reporting hierarchy include s: (1) source-specific emissions testing, measurements, monitoring; (2 ) representative emissions based on testing, measurement, and/or monitoring of in-kind s ources; (3) manufacturer specifications; (4) emissions estimation tools (e.g. EP Tanks, Glycal c); (5) established emi ssions factors (e.g. AP42); and (6) engineering estimates.

We believe that by allowing the use of this da ta (or emissions reporti ng hierarchy), as an alternative to the prescribed emissions factors, the agency over time will acquire sufficient data to revise the existing prescribed emissions fact ors (many of which are based on studies that are almost two decades old). The use of better or more accurate emissions data will also allow70 companies (and the EPA) to more accurately refl ect 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 emissi ons reporting hierarchy should also be applied to the other sources subject to reporting under Subpart W ( but realize that the proposed rule revisions only addres s gathering and boos ter facilities).

Response 1: The EPA does not agree to allow repor ters to use any data they feel is representative of their emissions in this rule making, 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 calcu lating 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 firs t 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 de vices 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 re sults in confusing te rminology and unclear requirements.71 If EPA does not remove this equipment categor y entirely for ONGGB, GPA suggests that EPA create a new equipment category for storage ta nk emissions from the ONGGB industry segment that contains relevant term inology and avoids confusion w ith onshore production industry segment requirements. The proposed requirement is an expansion of an existing requirement that has language specific for the Onshore Produc tion industry segment. Tacking on ONGGB requirements to this language creates confusion about the applicable requirements. ONGGB sites do not operate the same way th at 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 wi thin the Onshore Petroleum and Natural Gas Gathering and Boosting segment. Storage tanks a ssociated 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 oper ation of storage tanks further downstream is different enough from tanks in the Onshore Pe troleum 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 addre ss that language and cl arify 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 th reshold for the November 30, 2010 final rule is specific to the onshore production industry se gment and bears no relevance on the ONGGB72 industry segment. 20 This threshold was developed such that 20% of emissions from storage tanks in the onshore production industry segment were captured with si mple emission factor methods. Therefore, analysis that EPA performed does not apply at all to the ONGGB industry segment. To justify an appropriate threshold for simplif ied emission factor estim ation techniques, EPA must perform an analysis to determine appropria te thresholds for stor age tanks in the ONGGB industry segment. EPA has provide d no justification or support for the proposed rule language.

ONGGB operators do not typically track separator throughput.

ONGGB operators do not track se parator throughput as a normal course of business. ONGGB operators track tank throughput, which is typicall y 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 greate r 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 Aspe nTech HYSIS or API 4697 E&P Tank on each tank with throughputs equal to or gr eater 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 specifie d in EPA’s National Emission Standards for Hazardous Air Pollutant s (NESHAP) (40 CFR Part 63, Subpart HH). Tanks with greater than or equa l 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 satis fies 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 emissi ons using the more rigorous tank flashing model methodologies. EPA has determin ed 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 Gath ering 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 se gment, supporting the use of the 10 bbl/day73 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 Ga s Gathering and Boosting segment will not be a significant emissions contributor.

Although the Onshore Petroleum and Natural Ga s Gathering and Boosting segment reporters may not keep track of separato r throughput to tanks on a continuous basis, they should be aware of the tank volumes on removal and the time elapse d 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 Emi ssions – 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 pr essure fixed roof st orage tanks. Evaluating every single tank to determine if it meets a threshold to perform mo re complex emissions estimates is a huge burden in and of itself. GP A requests that EPA provi de a simple emission factor method for all tanks, similar to Ca lculation 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 estimat es for all equation inputs.

Calculation Methods 1 and 2 are ve ry prescriptive in how data must be acquired. GPA fails to understand this level of prescriptiveness, when for dehydrators (which re quire 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 base d on a process simulation where gas composition and rates are known, and condensat e production (through pressure increases) is simulated. This type of analysis is performe d because pressurized condensate samples can be difficult to collect (or impossible to collect for grassroots facilities). GP A 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 variet y of wells that the gas is collected from and74 the operating conditions of the gathering lines and th e compressor station. It is not clear if or how this emission estimation technique is account ed 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 E quation W-15 in 98.233(j)(5) of Subpart W is the appropriate methodology. It is unclear from th e five methodologies lis ted 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 a nd Natural Gas Gathering and Boosting storage tanks are significant enough to require reporting methods th at 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 Calc ulation Method 1 for storage tanks is more prescriptive than dehydrators regarding the acquisi tion of parameter data. For dehydrators, 40 CFR 98.233(e)(1) states that the listed parameters must be dete rmined “by engineering es timate 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 asser tion 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 li quid at storage conditions.” If th e condensate requires pressure to remain in liquid phase, it is not a condensate as it pe rtains to this rule. (Note that the EPA has clarified previously that for this subpart, only emissions from atmospheric storage tanks with hydrocarbon liquids are re quired 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 (Novemb er 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 pe r day, reporters should use Calc ulation 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 pr ovision 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 confir mation that the same gui dance would apply to tanks within the Gathering and Boosting segment.

Q480. How should the daily oil thro ughput 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 decrease s 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 equipm ent threshold and use monitoring methods appropriately. For less than 10 barrels per day of oil throughput on an annual average daily basis, the reporter mu st 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 Producti on 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 an d Natural Gas Gathering and Boosting segment may be determined for an individual separator or other non-separator equi pment, as applicable, rather than an individual we ll pad. Second, 40 CFR 98.233(j) has be en 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 indus try 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 th roughout sections 98.233(j) and 98.236(j). Do all of these terms refer to the same type of equipment? GPA not es 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 se parator vessel at the inlet of the facility to separate liquids that condensed in the gas pipeline. The ga s proceeds through the compressor train, which typically also includes compressor interstage knoc kout drums, which are separators. In the rule language, in each instance where EPA uses the term s “separator(s),” “gas-liquid separator(s),” “wellhead separator(s),” and “wellhead gas-li quid separator(s),” is EPA referring the inlet separator and/or compressor interstage knockout vessels atONGGB compressor stations?

Commenter 0132: Proposed section 98.233(j) says, “ [f]or hydrocarbon liquids flowing directly to atmospheric storage tanks without passi ng 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 pipe line was from gas that passed through a wellhead separator. It would be impo ssible for an ONGGB facility ow ner/operator to acquire this information since gas is gather ed 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 opera ting conditions at the multitude of upstream wellhead gas-liquids separators would have no be aring 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 li quids 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 th e 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 fac ilities and all Onshore Petroleum and Natural Gas Gathering and Boosti ng 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 re sults in confusing te rminology 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 fac ilities and all Onshore Petroleum and Natural Gas Gathering and Boosti ng 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 re sults in confusing te rminology and unclear requirements.

Section 98.233(j)(1)(vii)(B) refers to “produced cr ude oil or condensate.” 18 Does this also refer to condensate that is generated by liquids conde nsing in gathering pipe lines? 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 condi tions.” If the condensat e in the gathering pi pelines is liquid at storage conditions, then it is c onsidered condensate for purposes of this rule. (Note that the EPA has clarified previously that for this subpart, on ly emissions from atmospheric storage tanks with hydrocarbon liquids are re quired 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 (Novemb er 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 re sults in confusing te rminology 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 th e ONGGB industry segment. The composition of condensate processed at an ONGGB compressor stati on 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.

Footnotes79 19 40 C.F.R 98.233(j)(1)(vii)(B).

Response 8: The EPA agrees with the commenter thatthe definition of “sub-basin category, for onshore natural gas production” is not releva nt 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 th at are not contemplated by the current language:

In Scenario A, a compressor station has atmos pheric fixed roof storag e tanks that receive condensate that has condensed in the gathering li ne upstream of the facili ty 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 Scenar io B, a compressor station has atmospheric fixed roof storage tanks that receive condensate th at is trucked in from other locations around the gathering system(s). How ar e 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 da ta from the gas-liquid se parator 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 gr eater 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 stab ilizers 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 woul d 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 Meth od 1 or 2. If the annual average daily throughput is less than 10 bbl/day, Calculation Met hod 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 scenario s that are not contemplated by the current language:

In Scenario C, the liquid from the inlet separa tor (and possibly compressor interstage separators) is routed through a condensate stab ilizer. The stabilized liquids are routed to the storage vessel. How are these Scenario C storage tanks trea ted under these calcul ation and reporting requirements, since there is nota 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 trea ted under these calcul ation 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 liqui d is routed to a “slug catcher” (a holding spot for the liquid that is typically not atmospheric). Liquid fr om the slug catcher is then routed to the atmospheric storage tanks, pos sibly 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 Calcula tion Method 1 or 2 should be used if hydrocarbon flow to the storage tank from non-se parator equipment is gr eater than 10 bbl/day (40 CFR 98.233(j)(1) or (2)(iii)). Non-separator equipment is in tended to include equipment other than separators immediately upstream of storage tanks, such as stabilizers and slug catchers. Therefore, in Scenario C, Calculati on Method 1 or 2 should be used unless the annual average daily throughput of the hydr ocarbon liquids through the condensat e 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 shoul d be used unless the annual av erage daily throughput of the hydrocarbon liquids through the slug catcher is less than 10 bbl/d ay, 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 sour ce 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 industr y segment), GPA requests that EPA determine appropriate emission factors fo r storage tanks in the ONGGB i ndustry segment. Regardless of the origin of the emission factor s, the language in the calculation method is not applicable to the ONGGB industry segment. Specifically, the terms “EF i ” and “count” are tailored to separators or wells. The ONGGB industry segment does not ha ve wells, and separator count and separator operation may have little to do with stor age tanks in the ONGGB industry segment.

Response 11: With respect to the comment about “l imited 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 Calcul ation 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 c ondensate tanks in natural gas systems. 1 The emission factor for methane from condensate tanks was based on da ta collected from condensate tanks in the production stage of natural gas systems; no conden sate tank emission factor was provided for the processing stage. The CH 4 emission factor for crude oil tanks and the CO 2 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 gravi ties of API 44 degree and higher. The crude oil tanks simula tion runs were for crude oil of different gravities less than 44 API degrees. The type of storag e tanks and the API gravities th at characterize crude oil and condensate are the same in both the Onshore Petroleum and Na tural Gas Production segment and the Onshore Petroleum and Natural Gas Gath ering 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 Natura l Gas Gathering and Boosting segment and the EPA is not revising the emission factor s in the definition of the term “EF i ” in Equation W-15.

The EPA does agree that Calculation Method 3 di d not account for flow to storage tanks from equipment other than separators or wells. Therefor e, 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 “EF i ” 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 ow ners 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 pre ssure to be known. Most operators use ProMAX or HYSYS to estimate flas h 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 revisi ons to the modeling software method (Calculation Method 1) in response to this comme nt. Subpart W does not re quire the calculation of storage tank working and breathing losses. Subpart W also does not require the use of a particular modeling software program for Calcul ation Method 1. Instead, the EPA allows the use of any process simulators that use the Pe ng-Robinson equation of state and meet the requirements under 40 CFR 98.233(j)(1). The comment er noted that many operators already use HYSYS, which is a modeling softwa re 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 alrea dy provided flexibility to reduce the burden associated with sampling to determin e 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 flar e or vapor recovery.

As proposed, EPA requires that additional comple x calculations must be performed on tanks whose emissions are routed to flare or vapor recove ry. For tanks that are rout ed to flare, the flare calculations must be applied to the tank emissions, and then thes e resulting emissions must be backed out of the flare equipment emissions. Fo r 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.” This83 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 ta nk) are not captured by vapor recovery, the negligible amount of carbon dioxide (CO 2 ) and methane emissions cannot justify the burden. Operators are essentia lly “punished” for controlling their tanks.

Why would EPA mandate more difficult and reso urce-wasting reporting requirements for owners and operators who are reducing their CO 2 e 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 un der the flare equipment t ype, and emissions that are routed to vapor recovery should not be calc ulated (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 Pe troleum 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 be ing captured. Therefore, the EPA has retained the requirement on all emissi ons 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 devel op the correction factor CF n in Equation W-16 was collected solely from onshore production sites, not ONGGB sites.

EPA used data from a Texas Commission on En vironmental 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 (s ee 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 estima te. 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 C ontract Reports: Emissions Inventory, https://www.tceq.texas.gov/airqua lity/airmod/project/p j_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 batte ries that service gas or oil wells. While tank batteries servicing gas or oil wells are most commonly found in Onshor e Petroleum and Natural Gas Production facilities, some of these tank ba tteries will be in the Onshore Petroleum and Natural Gas Gathering and Boosting segment instea d. Specifically, any tank ba ttery 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. Ther efore, a correction fact or 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, SierraClub, 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, SierraClub, 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 resp ectfully 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 stre ngthen reporting requirements for compressors in the gathering and boosting segment. EPA propos es 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 Subp art 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 compresso rs (notably, the failure to require emissions reporting of nonoperational pressurized mode ) that result in underreported emissions. 27 Accordingly, we respectfully ask that EP A require direct measurement for gathering85 and boosting compressors, consistent with Subpart W’s approach in the processing, transmission, and underground storage segments, and address some of the data gaps id entified 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, Co lorado 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 th e emissions factor for reciproc ating engines at Subpart C, 40 C.F.R. 98.33. Since most gathering and boosting f acilities use reciprocating engines, combustion emissions for this segment could be substantia lly underestimated with the use of the current emissions factor.

Response 1: The EPA considered requiring direct meas urement for compressors in the Onshore Petroleum and Natural Gas Gathering and Boosting segment, consistent with the approach for compressors in the Onshore Natural Gas Pr ocessing, Onshore Natural Gas Transmission Compression, and Underground Natural Gas Storag e 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 consequenc es of implementing direct measurement, the EPA revised the final rule to exclude direct measurement fo r compressors. As explained in the memorandum Compressor Modes and Thresholds , (Docket Item N o. 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 ha ve a high operating factor and because of their type and size, have smaller process emissions (vented and equipment leaks) primarily from rod packing. By c ontrast the processing, transmission, gas storage, LNG storage and LNG import/e xport terminal sectors generally have larger compressors within a single facil ity boundary or adjacent to that boundary. These large compressors are of different types (reciprocating, centrifugal wet seal and centrifugal dry seal). They are almo st always spared, and therefore have lower operating factors (more time in th e standby depressurized mode) and higher emissions, particularly fro m 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 Petroleu m 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 appro ach for reporting emissions from compressors in86 the Onshore Petroleum and Natural Gas Gather ing and Boosting segment in this rulemaking should be consistent with the approach for th e 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 populati on count method for estimating equipment leak emissions for the ONGGB industry segment. Howe ver, EPA has simply tacked on the ONGGB industry segment to the existing requirements fo r the onshore production industry segment. Due to limited time to provide comments, GPA was not ab le 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 a nd boosting compressor statio n that separate liquid by phases? As noted in previous comments, the high pressure separators and low pressure separators typically found at produc tion sites are not necessarily the same types of separators that are used at ONGGB compressor stations. ONGGB compressor sta tions 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 procee ds through the compressor train, which typically also includes compressor interstage knockout drums, which are separa tors. It is unclear if these interstage knockout separators should be in cluded 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/pip ing, 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 curre nt 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 ma jor equipment types currently used for the Onshore Production segment to the Gathering and B oosting 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 “limite d 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 exte nded the comment period to allow more time to comment (80 FR 6495 (Feb. 5, 2014)).

The EPA is finalizing the proposed population co unt method for equipment leaks in the Onshore Petroleum and Natural Gas Gathering and Boosti ng segment with a clarif ication 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 na tural 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 CO 2 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 us ing the same method as in th e Production segment: “Under the proposed approach, a reporter w ould need to establish an inventory of the components or equipment subject to the populat ion counts, apply the emission factors, and then update the inventory each year to account for ne w 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 atte ntion; however, that component counts within the gathering and boosting system w ould require a significant effort and expense not only at the outset but potentially on an annual basis. Give n the similarities betw een 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 e quipment 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 repres entative component counts for each type of equipment and extrapolate that value across th e 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 calculati on 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 petrol eum and natural gas gathering and boosting operations in the facility perform the following activities:

(A) Count all major equipment lis ted 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 ga s gathering and boosting; and Table W-1C of this subpart fo r onshore oil production. Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. accord ing 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 Tabl e 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 m odel number of equipment in the onshore89 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 th is 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 si gnificant undertaking and unnecessary burden for operators. Kinder Morgan believes the above -proposed language re solves 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 s uggestion to include a Component Count Method 3 to develop representati ve component counts for each sp ecific manufacturer make and model number of equipment. The EPA determined that this approach is not necessary, because Onshore Petroleum and Natural Gas Gathering a nd Boosting facilities are not required to use Calculation Method 2 only. Calcul ation 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 c ounting individual components. Se ction II.B.6 of the preamble to the final rule and the final amendments provide clarification regarding ho w 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 th e 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 Producti on segment and proposed for the new gathering and boosting segment. In the Proposed GHG Re porting Rule, EPA states the following:

EPA Proposed 40 C.F.R. § 98.233(a)(2) : For the onshore petr oleum 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 4090 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 facili ty. 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 engineeri ng 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 cale ndar year period.

This approach is consistent with the exis ting approach in the Production segment where operators “have the option in th e 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 blee d) 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 gr anted with respect to certain components located within the Production segmen t. EPA should allow three years rather than two years to complete the initial component c ount because the gathering and boosting segment is new and operators will have to invest significan t 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 count s for a period of time (e.g., three-years) prior to requiring another updated co mponent 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 fo r operators to satisfy emissions calculations obligations.

Footnotes:

4 See also 40 C.F.R. § 98.233(o)(1)(i)(C) (with respect to centrifugal comp ressors, the operator must “measure the compressor as specified in para graph (o)(1)(i)(B) of this section at least once in any three consecutive calendar years, pr ovided the measurement can be taken during a scheduled shutdown.”).

Response 3: As noted in Response 2 in this sect ion, Onshore Petroleum and Natural Gas Gathering and Boosting facilities are not required to use Calcul ation Method 2 only. Calculation Method 1, in which a reporter counts major equipm ent types and multiplies those counts by the number of components in Table W-1B, is provide d as a less burdensome alternative to counting individual components. Therefore, the EPA is not providing additi onal time to develop component counts for equipment leaks from Ons hore 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, SierraClub, 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, equipmen t leaks would be calculated using population counts and the applicable emissi on 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 facilitie s. 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 a nd number of sources. 32 Subpart W should also require at least annual direct le ak detection and monitoring for well production sites for the same reasons cited here for requiri ng leak detection in gathering and boosting. Even so, the gathering and boosting segment is not co mparable to the production segment in the way the proposal suggests. In fact, estimates suggestthat the gathering and boosting segment more closely resembles other segments for which leak detection surveys are re quired. For instance, the Greenhouse Gas Inventory estimate s that there are approximate ly 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 di rect leak detection surveys under Subpart W. 34 We urge EPA to adopt a requirem ent for comprehensive, frequent, and direct leak detection and quantification in both the produc tion segment and gathering and boosting segment, as direct inspection methods ar e low-cost and availabl e and result in more accurate and transparent emissions data.

Direct and frequent monitoring of leaks in th e gathering and boosting segment would promote transparency and accountability for existing s ources. Leaks are the single largest source of fugitive methane emissions from the oil and gas sector 35 and are a significant source at gathering facilities, accordi ng 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. 3792 Direct leak inspection and reporti ng 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 meth ane 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 re alizing that commitment by establishing such requirements. 38

Requiring direct measurement, inspection, and repor ting 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 re cently finalized leak detection and repair requirements at compressor stations at or ups tream of natural gas processing plants. Under Colorado’s tiered leak detect ion and repair approach, the frequency of mandatory leak inspections depends on the size and emissions poten tial of the facility and ranges from one-time to monthly inspections. Colorado allows insp ection 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 mo dified facilities located in the Upper Green River Basin Nonattainment Ar ea that have the potential to emit at least 4 tons per year of volatile organic compounds from fugitive source s 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 exis ting 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 Ga s Production Facilities: Chapter 6 Section 2 Permitting Guidance (June 1997, Revised Sept. 2013).93 41 Wyo, Dep’t of Envtl. Quality, Draft Nonattain ment Area Regulations, at Ch. 8 (June 4, 2014), available at http://deq.state.wy.us/a qd/proposedrules_files/Chapter%208%20- %20Nonattainment%20Area%20Regulations - Oil%20and%20Gas %20draft%206-4-14.pdf.

Commenter 0142: Kinder Morgan supports EPA’s propos al not to require annual leak surveys at gathering and boosting facilities because su ch 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 Gatheri ng 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 ga thering and boosting segment, Kinder Morgan supports EPA’s sugges tion that the “populati on 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 Na tural 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 Am erican 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 determin ing the gas gathering pipeline distances when utilizing this emission factor, such that these di stances do not need to be explicitly measured by94 field surveys which would be prohibitively expensive (upwards of $9,000 per mile surveyed 1 ). 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 thatdata collected annually unde r PHMSA pipeline regulations for pipeline length be used to report gathering pipelin es 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 dist ances 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 gath ering pipeline segments, EPA is proposing to use a factor of 2.81 scf gas/hour/mile. The AP I 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 (di fferent standard conditions and CH 4 contents). However, both emission factors are developed from data fo r 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 co mpany 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 inform ation on the type of gathering pipelines. The Pipeline and Hazardous Materials Safety Administration (PHMSA) reports the annual miles of gather ing pipelines by material type. 3 API suggests updating the GRI/EPA emission factors on the basis of the cu rrent gathering pipelin e material type. The derivation of a more current emission f actor is provided in the Table below.

Applying a sumproduct of columns A and B results in a weighted average CH 4 emission factor of 1.76 scf CH 4 /mile-hr. This is converted to a gas ba sis consistent with the units for EPA’s proposed emissions factor by dividing by the CH 4 content from the GRI/EPA study of 78.8%, resulting in an emission factor of 2.23 scf gas/ mile/hr. API requests th e use of this emission factor which represents current occurrence of ga thering 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 Pipelines 1 Derived GRI/EPA Emission Factor: ScfCH4/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/P HMSA/menuitem.6f23687cf7b00b0f22e4c6962d9c8789/ ?vgnextoid=a872dfa122a1d110VgnVCM1000009e d07898RCRD&vgnextchannel=3430fb649a2 dc110VgnVCM1000009ed07898RCR D&vgnextfmt=print

Response 3: The EPA agrees with the commenter thatthe emission factor should be revised from proposal, and the final rule provides gathering pipeline emissi on 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, SierraClub, 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, SierraClub, 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 resp ectfully 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 pipelin e leaks and to use this data to develop facility- and material-96 specific pipeline emissions factors (as has been d one in the distribution segment). The currently proposed per-mile emission factor could be used wh ile this data is being collected. The emission factors used in the GHG Inventory (from the GR I/EPA study) were based on measurements of local distribution mains, not gathering pipeline s. As EPA illustrates in its Technical Support Document for the proposed rule, gathering pipelin es generally differ from distribution mains in material, size, and maximum operati ng pressure and there is varia tion even within the gathering and boosting segment in material, size, and pressure. 29 Despite the adaptation from distribution emissions factors, the existing emissions factor s may not accurately represent emissions from these sources. 30 We therefore urge the agency to upda te the emission factor based on direct measurement of gathering pipeline leaks. We also recommend that the agency investigate alternative methods such as leak detecti on 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 Boosti ng segment. As the commenter noted, the EPA has used the best data available to apply the distribution mains emissi on factor to gathering pipelines. The EPA is currently considering othe r 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 report ers 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 operato rs of boosting stations with emissions exceeding 25,000 mt CO 2 e to calculate and report combusti on emissions using methods listed in97 Subpart C of this part. Many owners and operato rs who would be require d to report under the new ONGGB industry segment have already been reporting combustion em issions, for sites in the same industry segment, under Subpart C of this part. Requiring these same reporters to now

use a different calculation methodolo gy sets an unfair precedent, and imposes additional reporting burdens by deviating from previous ly 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 be tween fuel types used for combustion sources within the gathering and boosting industry segment is expected to result in minor differences in GHG emissions. GPA doe s 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 f it all. What works for the Onshore Petroleum Natural Gas Production will not work necessa rily 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 dist inction is warranted. Depending on fuel type, there coul d be anywhere from a 0-15% difference in emissions between the calculation methodologies. In th e overall inventory this is neg ligible and does not justify the additional substantial burden that would be impos ed. Additional fuel sample analyses would be required and current environmental management systems would have to be reprogrammed. In addition, there would be a signifi cant new cost for training asso ciated 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 da ta. 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 sett ing a precedent by requiring facilities in the Onshore Petroleum and Natural Gas Gathering and Boosting segment th at 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 faci lities 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 changi ng the calculation methods for combustion sources in an Onshore Petroleum and Natural Gas Gather ing and Boosting facility, but ultimately this change is expected to reduce the burden by c onsolidating reporting. In addition, owners and operators of Onshore Petroleum and Natural Ga s Gathering and Boosti ng facilities will be allowed to use BAMM for the first year of reporti ng, 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, SierraClub, 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, SierraClub, 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 resp ectfully offer several specific recommendations to further strengthen the proposed rule:

 Require more granular, site-specific info rmation for gathering and boosting facilities within basin-level reports.

Commenter 0139: While we support basin-level re porting, 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 site s in each basin-level facility, the non-pipeline emissions attributable to each site, and the type s and number of equipment in each site. Under this approach, EPA could provide further gu idance 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 gath ering pipelines in a system, including material, diameter, and maximum pr essure 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 boosti ng sites within the larger basin facility. Source emissions within the larger facility could thenbe grouped by site identifiers within basin reports. This would help to maximi ze the data collected for a single gathering and boosting facility by providing valuab le site-specific information for sources within that facility.

Moreover, many owners and operators will likely colle ct this data at the level of the individual site (rather than for the entire ba sin), and providing the data in th at form would enable detailed analysis and verification of the emissions from th is 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, re quiring 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 “gat hering & boosting equipment on a single property.” The ES&T Study found that gathering and boosti ng 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 reporti ng 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 Boos ting segment will result in improved knowledge of the gathering and boosting industry, which will be useful to support ve rification 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 notunderstand how this data element differs from Subpart C. Subpart C contains extensive re porting requirements that are tailored for various fuel accounting systems. This data element is red undant 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 allo ws, 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 a nd 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 a nd Natural Gas Production fa cilities, at Onshore Petroleum and Natural Gas Gathering and Boosti ng facilities, and at Natural Gas Distribution facilities will be reported according to the re quirements 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 also100 reporting under subpart C. For example, a facility that is classified as a compressor station may currently be reporting only under subpart C, but wh en these amendments take effect, the facility may become subject to subpart W under classifi cation in the Onshore Petroleum and Natural Gas Gathering and Boosting segment. In that ca se, the facility woul d 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 elemen t in section 98.236(10)(aa)(v), “[t]he quantity of gas flared, vented a nd/or unaccounted for in the cale ndar 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 assu rance, calculation, and reporting requirements of Subpart W is to consis tently 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 guida nce or standard methods. This also undermines the equipment specific provisions to ease re porting burden, such as the excl usion 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, a nd petitioner negotiations.

Prior to the proposed rule, “unaccounted for” gas has been specifically exempted from reporting in Subpart W.

For natural gas distribution, se ction 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 in clude 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 distribut ion 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” ga s means. GPA assumes this means the difference between the quantities of gas measured at the in lets 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, and101 measured process gas). “Unaccounted for” means ju st 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 flar ed, 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 balan ce be reported on each ONGGB facility, which EPA has defined as all ONGGB equipment within a basi n. 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 ope rators 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 si gnificant 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 equivale nt), measured fuel use, measured gas from production sites or upstream ONGGB compressor st ations, 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, a nd not all operators will perform it the same way. For example, some condensate that is pr oduced in ONGGB (from gas condensing into condensate) is “credited” to the producer, and di fferent operators may account for this credited condensate differently; some will vi ew it as “lost” gas. Also, this data element may unfairly disadvantage owners and operato rs who do not have extensive measurement networks. This reporting element will make it look like those comp anies “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 Ons hore Production industry segment, but they are not relevant to the ONGG B industry segment.

In section 98.236(aa)(10)(i), EP A requests “[t]he quantity of produced gas throughput in the calendar year.”

How is this “produced gas” distinct from “nat ural gas” which is the term used in section 98.236(aa)(3)(i) for natural gas processing? The ga s 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), EP A 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 quantit y of produced condensate throughput in the calendar year.”

As noted in an earlier comment, GPA does not typical ly consider the condensate that formed in the gathering pipeline to be “produced condensat e.” 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 owne r or operator would re port here. Oil is not produced in the ONGGB industry segment. Th is 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 preambl e to the final rule for more information.103 

### 4.0 Natural Gas Transmission Li nes 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 requestto clarify the scope of “intrastate pipelines” that would be c overed by the proposed requirementto report emissions from blowdowns, so that it is clear which intrasta te pipelines are incl uded and which ones are excluded.

We are not sure whether the pr oposed regulatory language would ex clude intrastate transmission pipelines that offer only intrastate service. The regulatory text requi res the reader to consult with an attorney who has a th orough 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 (F ERC) under section 311 of the Na tural Gas Policy Act. To avoid misunderstandings, AGA requests that EPA make a simple clarification in the definition of transmission pipeline owner and operator, and prov ide a clear, “plain English” explanation in the preamble to the final rule.

EPA is proposing to require reporting of blowdo wn emissions from interstate transmission pipelines and from certain intrastate transmission lines . Many AGA member gas utilities operate high pressure intrastate transmi ssion pipelines to transport natura l 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 inte rstate pipelines or to other distribution utility companies, and thus are not required to obtai n 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 in trastate pipeline s that provide interstate transportation service are required to file a Statement of Oper ating Conditions with FERC. However, it takes a close reading of the proposed regul ations 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 comm unity and enforcement personnel unless EPA provides a less obscure explanati on in the preamble to the fina l rule, as discussed below.104 AGA Supports Exclusion of Intrastate Tran smission 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 a nnual carbon dioxide and methane emissions from “each separate transmission pipeline blowdown event” and the location of each blowdown.

To find out whether a utility-opera ted 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 na tural gas transmission pipelines, as defined in [the existing Subpart W rule] owned and operated by an onshore natural gas transmission pipeline owner or opera tor as defined in this section.”

 Existing definition: “ Transmission pipeline means a [FERC] rate-regulated Interstate pipeline, a state rate-regulated Intrastate pi peline, 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 intras tate pipelines, the person identified as the owner or operator on the transmission pipe line’s Statement of Operating Conditions under section 311 of the Natural Gas Policy Act.”

Although it requires close reading of the regulatory text to fi nd 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 identifie d in any Statement of Operating Conditions under NGP A section 311. AGA supports this exclusion, but we urge EPA to clarify the proposed definition as s uggested 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 lin es of natural gas before performing repairs or replacing pipe. In large transmission pipelines thatprovide interstate service, these events are likely to be connected with large projects thatare 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 inters tate pipelines in a single reporting segment under Subpart W. However, utility-operated intrasta te 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 projec ts that drive much of the need for blow down
events.

Moreover, AGA and its members are currently wo rking 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 w ith the program. AGA supports this effective, voluntary initiative, and we support EPA’s proposal to exclude intras tate transmission lines from the mandatory blow down reporting requirementthat 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 Transmi ssion Pipeline Owner or Operator

Section 98.238: To ensure that the regulated commun ity and enforcement personnel understand who is – and is not – required to report blowdow ns under Subpart W, we urge EPA to revise the proposed definition of “Onshore natural gas tr ansmission pipeline owne r or operator” in 40 C.F.R. 98.238 to insert the word s “providing interstate natural gas transportati on service” as follows:

“ Onshore natural gas transmission pipeline owner or operatormeans, for interstate pipelines..., or, for intrastate pipelines providi ng more than a de minimis amount of interstate natural gas transportation service, th e 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 blowdo wn emissions applies only to certain types of intrastate transmission pipelines that have file d a Statement of Operating Conditions with FERC to provide interstate natural gas transportati on 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 dist inction of which intrastate pipelines are affected by the Proposed Rule.

EPA proposes that its rule apply only to intrastate pipelines that are identi fied in connection with Section 311 of the Natural Gas Policy Act of 1978 (NGPA). However, the Federal Energy Regulatory Commission (FERC) re gulates these particular pipelines on a limited basis because such pipelines have a statutory ex emption to engage in interstate transactions (transportation or storage) without the entity being subject to the full scope of regulation pu rsuant to the Natural Gas Act. 15 U.S.C. 717(f)-(w). Consequently, intr astate pipelines that perform NGPA Section 311 transportation do not represen t the full universe of intrastate natura l gas transmission pipelines. Therefore, INGAA asks EPA to clarif y why the agency decided to limit its reporting requirements only to the Section 311 intrastate pi pelines rather than all intrastate pipelines.

Commenter 0142: EPA proposes to define the onshore natural ga s transmission pipeline owner or operator based on whether the transmission pipe line 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 sh ould be the operator iden tified on the pipeline’s Statement of Operating Conditions prepared fo r 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 pipeli ne or local distributi on company without prior106 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, wh ich 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 wi th 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 pi pelines, the person identified as the owner or operator on the transmission pipeline’s Statement of Operating Conditions under section 311 of the Natura l Gas Policy Act, unless the owner or operator does not provide services unde r 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 report s with the appropriate state agency.

With the above revision, Kinder Morgan would be comfortable with EPA’s proposed definition of onshore natural gas transmissi on 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” specif ies 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 prea mble 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 bl owdown emissions for all company-owned or operated transmission pipelines into one repor t, regardless of location or connectivity.107 Facility with respect to the onshore na tural 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 de fined in this section.

Onshore natural gas transmission pipeline owner or operator means, for interstate pipelines, the person identifiedas 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 St atement of Operating Conditions under section 311 of the Natural Gas Policy Act.

Combining all company-owned or operated pipelin es 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 comp any 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 Regul atory Commission (FE RC) Code of Conduct (COC) operating entities with different Designated Represen tatives under the EPA Greenhouse Gas Reporting Program. In addition, both entities report to the FE RC under the subsidiary name rather than the parent company name. Therefore, we request pr ovisions that would a llow for EOG and DTI to each file their own separate reports.

Commenter 0140: INGAA supports reporting pi peline 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 segmen t as “the total U.S. mileage of natural gas transmission pipelines...owned and operated by an onshore natural gas transmissi on pipeline owner and operator” 3 The EPA further defines “onshore natu ral gas transmission pipeline owner and operator” for interstate pipelines as “the pers on identified as the transm ission pipeline owner or operator on the Certificate of P ublic Convenience and Necessity issued under 15 U.S.C. 717(f)” 4 For pipeline companies that operate under a pare nt 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 multip le pipelines in the U.S., the facility would be considered the aggregate of those pipeli nes, even if they ar e not interconnected.” 5 This statement could be interpreted as requiring operators to submit one consolidated figure for the corporate parent company. INGAA does notsupport this aggregated approach. The Final Rule108 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 th at interstate pipeline op erators 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 pi peline owners and operators. The definitions of “facility with respect to the onshore natural gas transmissi on 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 th e preamble to the final rule.

The EPA also notes that the use of the term “en tity” 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 th at 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 re vised 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 rule s 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 tota l annual emissions of methane and CO 2 , natural gas transmission pipeline reporters w ould also report the methane and CO 2 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 orno 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 pream ble’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 ou t to calculate the length and diameter of the pipe for the entire flow scheme of the pipeli ne 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 whic h reporting of transmission pipeline blowdowns wo uld not be required.

Footnotes:

22 79 Fed. Reg. 73157 (Dec. 9, 2014).

Commenter 0133: We appreciate th e inclusion of the current ex emption that excludes reporting if the physicalvolume of the equipment blown down is less than 50 cubic feet. Additionally, we110 request that EPA include a specifi c reference to metering and regul ating stations and distribution piping as exempt equipment. These areas fall within a de minimis category regarding gas volumes. In addition, there are often different owne rs/operators for these assets, complicating the tracking and reporting process.

Commenter 0140: EPA should consider certain excl usions for transmissi on pipeline blowdowns.

INGAA believes that the EPA should consider a de minimis exclusi on for transmission pipeline blowdowns. Section 98.233(i) incl udes exclusions and de minimis thresholds for reporting blowdowns. Those criteria, however, were deve loped for other source categories such as compressor stations. It does not appear th at 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 fr om equipment with a physical volume less than 50 ft 3 . For transmission pipeline blowdowns, equi pment 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 substantiv e events. For example, the physical volume of a metering run blown down for maintenance could exceed 50 ft 3 , but those emissions would not be a significant contributor to to tal annual pipeline blowdowns. I NGAA believes that the proposed 100 ft 3 reporting threshold for transmission pipeline blowdowns is not adequate. This threshold would likely cover filter/separator s at meter stations, pipeline he aters, 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 facili ties 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 interco nnects (single or multiple pipeline connections) and the volumes of gas being received or delivere d. Therefore, it is not feasible to establish a specific de minimis volume threshold. However, emissions from maintenance activities at any of these individual ancill ary facilities would be consider ably less than the 25,000 ton CO2e threshold established for compressor stations.

INGAA recommends exclusions fo r ancillary equipment to redu ce 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 pre ssure control, desiccant dehydrators, etc. For transmission pipelines, INGAA recommends excluding blowdown reporting for ancillary pipeline equipment including metering and/or re gulating stations, pipeline interconnects, valve assemblies or valve body cavities, and pig la unchers and receivers. If a blowdown of a transmission pipeline section occurred at one of these ancillary facili ties, the blowdown volume and purpose would still be reporte d 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 tran smission pipelines for the purpose of reducing system pressure or complete depressuriza tion.” 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 impor tant that reported blowdowns be limited to blowdowns of the pipeline. Pipe line 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 w ithout 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 definitio n 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 Morg an recommends excluding blowdown reporting for ancillary pipeline equipment including meteri ng and/or regulating stations, pipeline interconnects, remotely operated valves, and pig la unchers and receivers th at does not result in any blow down of the transmission pipeline. This a pproach 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 cu rrent existing exclusions in section 98.233(i) for blowdowns resulting from over-pressure relief, ope rating pressure control, desiccant dehydrators, etc. See 40 C.F.R. 98.233(i). 5 Additionally, exempting ancill ary equipment would avoid a significant unnecessary burden fr om tracking emissions from normal operation and maintenance from the ancillary equipment. Importantly, a ny blowdown of a transmission pipeline segment that potentially would occur at these ancillary equipment (e.g., metering and/or regulating stations, pipeline interconnect s, and pig launchers and rece ivers) 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 e ffectively manage multiple regulatory regimes.

New Proposed Language to 40 C.F.R. 98.238: Blowdown means the release of gas to the atmosphere from transmissi on pipelines for the purpose of reducing system pressure or complete depr essurization. Blowdown does not include blowdowns of ancillary pipeline equipm ent, 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 comple te depressurization. Blowdown does not include any blowdown of ancillary pipelin e equipment, including metering and/or112 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 blowdow ns along a pipeline or through pipeline ancillary equipment. Rather, a threshold related to the natural gas vo lume released to the atmosphere reflects the intentions of the GHG reporting rule and crea tes consistencies with existing reporting requirements.

Response 3: The EPA is finalizing the reporting threshold of 50 ft 3 of physical volume for blowdowns in the Onshore Natural Gas Transmi ssion Pipeline segment as proposed. In addition, the final rule clarifies that facilities in th e Onshore Natural Gas Transmission Pipeline segment report pipeline blowdown emissions from blowdo wn 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 th e 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 th e atmosphere via a stack. In comparison, the definition of “blowdown” and “blowdown vent stack” in the general de finitions section of Subpart A 14 implies that blowdown emissions othe r 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 em issions source, which would require revising the title to section 98.233(i) and references to this emi ssions 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 requi rements related to the113 transmission pipeline segment as not all bl owdowns from pipelines will occur through vent stacks. Use of the term blowdown vent stacks inreference to the transmission pipeline creates confusion and does not accurately re flect the operational realities.

Response 4: As Commenter 0140 noted, the terms “blo wdown” and “blowdown vent stack” are defined in subpart A; 40 CFR 98.6 states that “Blowdown vent stack emissions mean natural gas and/or CO 2 released due to maintenance and/orblowdown operations including compressor blowdown and emergency shut-down (ESD) system te sting.” Because this term is not defined in subpart W, the definition in s ubpart A applies to subpart W.

The EPA disagrees that any clarif ications to this definition are necessary for subpart W. While the chosen term may imply the presence of a physic al stack, the definitiondoes 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 re porting 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 vers us blowdowns that occu r outside the station boundary.

INGAA recommends that the EPA retain the re porting approach currently applicable to transmission compressor stations but add clarifyi ng amendments to the reporting obligations for transmission pipeline blowdowns. For tran smission compressor stations, blowdown event categories are identified in sect ion 98.233(i)(2) and incl ude “pipeline venting” for lines outside the compressor station if the venting occurs within the facility boundary.

Regarding sections in Subpart W that addre ss categorizing of Blowdowns as “facility” or “pipeline” emissions, some text is provided:114 To categorize blowdown emissions orig inating 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 type s of events that apply to transmission compressor stations. Comment 5 provide s additional INGAA recommendations on the event categories that s hould 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 incorpor ated within transmi ssion pipeline segment.

Response 5: The EPA understands the commenters’ concerns about separating transmission pipeline segments from compressor stations. Howe ver, compressor stations are already reporting facilities in the Onshore Natural Gas Transmi ssion Compression segment as defined in 40 CFR 98.230. As stated in the preamble to the proposed rule, the intent of th e Onshore Natural Gas Transmission Pipeline segment is to capture emissions from blowdowns between compressor stations, and the EPA decided notto 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 pipe line blowdowns is addr essed 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 requireme nts 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 de finition for the “transmission pipeline” source category included in the Proposed Rule and the existing definitions for “transmission compressor station” and “underground st orage 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 re lated definitions in section 98.238. The agency already has definitions in the existing rule fo r transmission compressor station and underground storage facilities. While it appears that the EPA in tends to create clear lin es of demarcation for the three source categories, the EPA should includ e additional details in the proposed definitions to avoid confusion.115 Facility definition

Subpart W “transmission pipeline” sources are inte rspersed with compressor stations and storage facilities along an interstate natural gas transmissi on pipeline. This characteri stic is unique to the Subpart W source categories. For ex ample, a pipeline “fac ility” stops at the in let to a compressor station and re-starts at the ou tlet of the facility. To improve clarity, INGAA recommends a revision to the proposed definition of “facili ty” for the natural ga s transmission pipeline segments, as follows:

“ Facility with respect to the onshore nat ural 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 on shore natural gas transmission compression source category identi fied in section 98.230(a)(4), the underground natural gas storage source category identified in section 98.230(a)(5), and the LNG storage segmen t identified in section 98.230(a)(6). ”

Response 6: The final definition of “facility with re spect 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, Re presenting 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 spa tial data. EPA proposes that pipeline blowdown data will be reported by the specifi c 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 needto be revised to address these new reporting requirements. There are significant implementation and timing costs as sociated with those efforts.

In addition, EPA has not explaine d 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 or117 state aggregate basis. Reporting at the natio nal 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 pipelin e blowdowns between comp ressor stations in a new Onshore Natural Gas Transmission Pipeline industry segment. 20 Among the information that EPA seeks in the proposed rule s is the precise lo cation of each blowdown event along the pipeline system. Specifically, EP A would require reporters to pr ovide “[t]he location of the blowdown, in latitude and longitude in decimal degree format...” 21 This is information that pipeline operators have not traditionally maintain ed, and to comply with this requirement would necessitate a significant amount of expense, effo rt, 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 al l blowdown events along domestic transmission pipelines.

TPA questions the need for, and potential be nefit of, the proposed longitude / latitude requirement for blowdown locations. We do not belie ve 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 reporte rs without any ascert ainable 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 incl usion of location data for each blowdown: The location of the blowdown, in latitude and longitu de in decimal degree format provided as a comma-delimited ‘“latitude, longitu de’” coordinate pair reported in decimal degrees to at least four digits to the righ t of the decimal point. We believe that this doe s 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 ev ent 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 wh ere 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 w ithout producing data th at 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 le vels. The need for such localized data is unclear because greenhouse gas emissions and meth ane 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 loca tion where a blowdowns occurs.

Footnotes:

10 Id

. Commenter 0142: Kinder Morgan strongly oppos es 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 eliminat e 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 wh ether 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 even t type for any blowdown vent stacks, then you must report the information specifi ed 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 pipeli ne segment, you must also report the information in paragraph (i)(3) of this section.

... (3) Onshore natural gas transmission pipeli ne segment. Report the information in paragraphs (i)(3)(i) to (i)(3)(iii) for eachseparate 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 pa ir 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 resu lts 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 loca l level does not improve the quality of data or provide relevant information re garding ambient air quality levels at the location of the blowdown event. If EPA does not finali ze the preferred national approach regarding blowdown emission reporting, Kinder Morgan w ould support as an alte rnative, reporting blowdown emissions on a state basis by each owner or operator.

Response 1: The EPA is not finalizing the requiremen t 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 Secti on II.C of the preamble to the final rule for additional discus sion 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 Re lated to the Transmission Pipeline Facility

In section 98.236(aa)(11) of the proposal, EPA identifies related “facility” reporting requirements for pipelines and includes segreg ation of natural gas volumes into different categories as follows:

“11) For onshore natural gas trans mission 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-syste m 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 transferre d 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 re quire thousand standard cubic feet (mscf or mcf) as th e reporting unit. When reporting to EPA under the proposed rule, we would assume one Dth is equivalent to one th ousand cubic feet (mcf) of natural gas, based on an approximate heat value of 1,000 British th ermal units (Btu) per cubic foot, and would therefore make a one to one conversion.

Commenter 0140: INGAA opposes EPA’s proposal to re quire pipelines to re port 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 thatpipelines report the following data:

For onshore natural gas transmission pipeline f acilities, report the qua ntities specified in paragraphs (aa)(11)(i) through (a a)(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 withdraw n 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 thous and standard cubic feet.

(vi) The miles of transmission pipeline in the facility. 6121 While INGAA’s members are committed to addressi ng the data gap for pipeline blowdowns, the reporting requirements must provide valuable in formation. 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 vol umes by comparing pipeline injections versus withdrawals.

Nonetheless, pipelines already report publicly th e 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 EP A 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 accountabl e for reducing the burden of Federal paperwork on the public...” 8

As the EPA is aware, in order to obtain O ffice 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 re quirements 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 eliminat e the proposed Section 98.236(aa)(11) reporting requirement since the data is duplic ative 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 finalizedas 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, SierraClub, 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, SierraClub, 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 resp ectfully offer several specific recommendations to further strengthen the proposed rule:

 Require leak reporting from transmission pipelin es and coordinate with data reported to the Pipeline and Hazardous Materials Safe ty 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 ur ge 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 fugiti ve 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 f ugitive 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 incorpor ate 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 unde rscore the need for robust reporting standards under Subpart W. The 2014 Greenhouse Gas Inve ntory estimates that there were over 300,000123 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, w ith approximately 2,000 miles of new natural gas pipeline added between 2010 and 2012. 50 Accidental leaks at these f acilities can be a significant source of methane emissions, and those at remote locations may not be noticed or repaired immediately. Indeed, a PHMSA-commissioned st udy found that the volume of natural gas released from large leaks and ruptures in tran smission lines is approximately 1.3 billion standard cubic feet annually, over ten times greater than the estimated tran smission 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 emissi on 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 ma in leaks in the EPA/GRI (1996) study and is adjusted based on specific characteristics of tran smission pipelines. We urge EPA to update this emission factor based on direct measurem ents of transmission pipeline leaks.

The reporting required under other federal progr ams does not provide comprehensive data on transmission pipeline leaks. PH MSA requires incident reporting of accidental leaks resulting in the release of 3 million cubic feet or more of natural gas – le aks large enough to pose safety risks. 53 PHMSA’s obligations therefore extend to onl y 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 reportin g of leaks from distri bution mains, and the proposed rule includes requireme nts for leak reporting from gath ering lines, even though these facilities are also subject to PHMSA’s incident reporting requir ements 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 propos ed rule. EPA reporting requirements could therefore play a distinct role and we encourag e 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 es tablish 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 Ga s 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 Detec tion Study – DTPH-11-D-000001 , at 3-27, PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (2012), available at http://primis.ph msa.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 l eak reporting. In the preamble, 17 EPA stated that it is no t 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 re porting of fugitive leaks between compressor stations “due to the dispersed nature of the f ugitive 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, SierraClub, 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 gr anularity and usability of reported data and would comport with the state-spec ific information owners and ope rators are already reporting to the EIA.
Response 4: The EPA is requiring reporters to ag gregate blowdown emissions by state and report the number of blowdowns a nd 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 blow downs. 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 retaini ng the existing categories for blowdowns that occur at compressor stations:

1. Pipeline integrity work including, but not lim ited to, the preparati on work of modifying facilities, assessments, maintenance or mitigation and traditional pipeline maintenance and post-maintenance commissioning 2. Equipment replacement or repair 3. Pipe abandonment126 4. New construction, or modification of pipe lines 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 fo r water removal, drop blowing, hydrate blockage, removing of stuck pigs) 8. Other

Commenter 0140: The EPA should deve lop pipeline blowdown categorie s, rather than relying on the seven event categorie s listed in section 98.233( i) that were develope d for compressor station blowdowns.

When the EPA added blowdown reporting for transm ission pipelines in the Proposed Rule, it did not revise the estimation methods to reflect th e activities that resu lt in blowdowns along a pipeline. Consequently, the proposed rule w ould apply the methods developed for tracking compressor station blowdowns. The EPA should devel op 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 compresso r stations. The value of the data generated from pipeline blowdown reporting woul d significantly improve if th e 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 pipe lines including commissioning and change of service 6. Pipeline incident (as defined by PHMSA) management and repair 7. Operational precaution during activitie s (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. Si milarly, tracking pipeline blowdowns by these categories would provide more valuable informati on 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 categor ies 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 in corporates by refere nce INGAA’s comments that suggest EPA develop pipeline blowdown cat egories (and require reporting by category),127 rather than relying on the seven event categories listed in sect ion 98.233(i) that were developed for compressor station blowdowns. The value of the data generated fr om pipeline blowdown reporting would significantly improve by identifyi ng 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 categorie s specific to blowdowns in the Onshore Natural Gas Transmission Pipeline segment. See Sec tion 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 groupe d into the following seven categories: facility piping (i.e., pipi ng within the facility bo undary other than physical volumes associated with distribution pipelines ), pipeline venti ng (i.e., physical volumes associated with distribution pi pelines vented within the facility boundary)...” [Emphasis added]

This reference was not included or explained in the proposed ru le issued in March 2014. This new terminology is unclear and should be revised or clarified. A compresso r station is usually associated with “transmission” pipelines, so refere nce to “distribution” pi pelines is confusing. In addition, the distribution s ector 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 secti on 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 categorie s specific to blowdowns in the Onshore Natural Gas Transmission Pipeline segment, a nd 40 CFR 98.233(i)(2) speci fies that the other blowdown categories do not apply to the Onshor e Natural Gas Transmission Pipeline segment. Therefore, the reference to distribution pipeli nes 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 natura l gas transmission pipeline owner or operator.” See 79 Fed. Reg. at 73,156. Kinder Morgan agrees w ith EPA’s approach and specifically agrees with EPA’s rationale:

After comparing the options, the EPA conc luded that requiring reporters to file separate reports for each portion of the syst em in any one segment, state, or basin would impose higher evaluation and repor ting 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 transf er points with specific geographical segments. Instead, the reporte rs 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 Kinde r Morgan’s extensive gas pipeline network, Kinder Morgan supports EPA’s national approach w ith respect to the defi nition of “Facility” in the new Transmission and Pipeline segment. In addition, Kinder Morgan agrees with reporting emissions from the Transmission and Pipeline se gment 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, SierraClub, 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 reporti ng requirements for emissions from natural gas transmission pipeline blowdowns between compressor stations. 42 EPA proposes defining the facility for the Onshore Natural Gas Transmissi on Pipeline segment as an owner or operator’s total mileage of natural gas transmission pipelines in the U.S. 43

Commenters strongly support thes e proposed requirements along w ith EPA’s proposed facility definition. A national approach to reporting in this segment ensu res 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 cu rrently do not utilize flow meters on our blowdown vent stacks, we appreciate the opt ion to use this method in the future.

Commenter 0142: EPA proposes that pipeline oper ators would use the methods in 40 C.F.R. 98.233(i) to calculate or meas ure 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 isolatio n valves that is blown down and the pressure and temperature of the gas within the pipeli nes. 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 meas ures primarily because operators do not always have a flow meter at the location where the bl owdown 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, SierraClub, 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 “provi de such other information as the Administrator may reasonably require.” 60

Reporting well identification numbers will significan tly enhance the potential uses and analysis of emissions data by facilitating cross-referenc ing among production segment data and will help ensure the transparency of repor ted data. Collected data that in cludes well identification numbers will also allow policymakers to understand whic h 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. Accordingl y, 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 CO 2 e threshold and requested a lower threshold. Comments of Clean Air Task Force, Colorado Environmental Coalition, Environmen tal 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 re quirements for wells but not for other emission sources. See Section II.D of the preamble to the final rule for additiona l 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 im prove data quality by en abling identification of wells associated with different sources. The EP A claims that these identification numbers are readily available and do not require any a dditional data gathering or calculation.

API contends that this requirement is an overr each of EPA’s authority fo r the reporting program, and the information requested is extraneous a nd not needed to validate emissions data. The requirement is inconsistent with the aggregation of equipment a nd 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 attemp ting to construct a comp rehensive 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 re quirement will impose only a small additional burden of 10 hours per reporter per year to report the well ID numbers lacks a ny rational basis and is arbitrary. In addition, EPA ignores the burden associated with mapping and maintaining the well ID database that could change throughout th e 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 al so notes that EPA has other ave nues at its disposal to acquire the well information data, such as commercial data systems like the D I-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 requireme nt does not have any influence on the final emission calculations and only serves to detract fr om the resources needed to manage and report the emissions data.

Commenter 0134: Requiring the reporting of well identification numbers c ould result in negative consequences for operators and the public, and th is requirement should be stricken in the final rule

Pioneer is concerned that EPA’ s proposed requirement for operato rs to report well identification numbers associated with the reporting of emissi ons data could result in negative consequences for both operators and the public. Oil field wells and operations are far-fl ung 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 in terests of the public. Therefore, Pioneer requests that the reporting of well identification numbers not be a re quirement in the final rule.

Commenter 0137: Reporting the well ID number fo r all wells associated with each emission source is a significant expansion of burden with out any impact on the accuracy of reported GHG emissions. This requirement is also in direct c onflict with the previous ly established policy of aggregating emissions data at the basin a nd sub-basin level. API strongly opposes this requirement.

Commenter 0137: At the outset, EPA lacks the legal authority to require faci lities to report well ID numbers. In the proposed Subpart W revi sions, EPA relies on Section 114 of the Clean Air Act as the source for its legal authority. EPA’ s use of Section 114 hi storically has been appropriately limited to issuing Information Coll ection Requests (ICRs). ICRs are limited to collecting data from specific sources over a discre te period of time, usua lly relying upon existing data or a subset of the universe of sources, orboth. Section 114, however, does not provide legal authority for an economy-wide, ongoing reporting ru le requiring all affect ed entities to submit data annually with new, onerous, and ever-c hanging monitoring and measurement processes. Thus, the broad, pervasive, and ongoing inform ation collection obliga tions under the GHGRP exceed the limits of Section 114.

In addition, EPA’s authority under Section 114 is directly limite d by a reasonableness requirement. See 42 U.S.C. section 7414(a)(1)(G). Here that reasonableness standard is provided134 by the 2008 Consolidated Appropriations Act, which authorized a one-time funding “for activities to develop and publish a draft rule not la ter 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 emi ssions 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 “emi ssions” 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 th an GHG emissions to be reported.

The proposal to require faciliti es to report well ID numbers exceeds this limitation and would unlawfully require facilities to report information that is unrelat ed to actual emissions of GHGs. By defining the relevant Ons hore 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 broade r than an individual well, maki ng the identification of specific wells within a given basin i rrelevant for purposes of calcu lating and reporting GHG emissions. Indeed, EPA’s proffered justifications for re porting well ID numbers do not suggest that GHG emissions data cannot be accurately measured a nd 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 explanati on for its action including a rational connection between the facts found a nd 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 r easoned decision-making announced in St ate Farm is that ‘an agency changing course...is obligated to supply a reasoned analysis fo r the change.’” (alteration in original) (citations omitted); Dillmon v. Na t’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 s ector or from its commitment to work with industry to complete an accurate GHG inventory w ith a manageable reporting burden.

When EPA first finalized re porting requirements for Onshor e Petroleum and Natural Gas Production under Subpart W, it electe d to require reporting at an a ggregate basin-wide level. API supported EPA’s conclusion that GHG emission datashould be aggregated across multiple well sites with similar characteristics. EPA justified this aggregated reporting approach as striking an appropriate balance between accuracy in emi ssion data and burdens imposed on reporting entities. See Mandatory Greenhouse Gas Reporti ng Rule Subpart W – Petroleum and Natural135 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 repor t 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 definiti on 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 emi ssion reporting thresholds in a manner that would unduly impact small businesses.

Nothing in the proposed rule provides a reasonedbasis for deviating from the approach adopted by EPA in the original Subpart W rule. EPA doe s 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. In stead, without providing an y basis at all, EPA appears to have abandoned the former goal of ba lancing 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 holisti c approach to gathering any and all industry related data using an aggregated basi n-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 atthe well-pad level. But the genera l 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 caprici ous 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 ba sin level as it has been doing since 2011, and changing its approach to the we ll ID level will add significantl y 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 Pr oposed Subpart W Revisions, EPA proposes to “amend 40 C.F.R. 98.236 to add reporting requir ements for well identification numbers to improve data quality by enabling identifica tion of wells.” 79 Fed. Reg. at 73,157. EPA thus proposes to require reporting of well identification numbers “asso ciated 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 inconsis tent with the aggregat ion of equipment and emissions authorized under Subpart W. For example, Section 98.236(j)(1)(iii ) requires reporters136 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 identif ication numbers to improve data quality by enabling identification of wells. ... This approachwould 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 identifi cation number reporting requirements for wells but not for other emission sources. As noted by Commenter 0055-B, well identification numbers are available via “commercial datasystems like the DI-Desktop or the EIA’s information,” which should lessen the industry’ s burden related to gath ering well identification numbers. See Section II.D of the preamble to th e 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 number s 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 identificati on number reporting requirements fo r previous years. See Section II.D of the preamble to the final rule for additional information regarding well identification number reporting for fu ture 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 we ll 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 storag e 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 th at, for the onshore petroleum and natural gas production industry segment, reporters would have to provide a “list of the well ID numbers137 associated with flare stacks in each sub-basi n.” 79 Fed. Reg. at 73,186. Similarly, the Proposed Subpart W Revisions would add new subparagra phs to section 98.236(j) requiring reporting of the following information for “each sub-basin:”

(ii) A list of the well ID number(s) asso ciated with the tanks that controlled emissions with flares (for the onsho re petroleum and natural gas production industry segment only)

(iii) A list of the well ID number(s) associ ated with the tanks that did not control emissions with flares (for the onsho re 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 th e 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 loca ted in a different sub-basin (county). In such cases, it is not clear whether Concho would be required to report onl y the well ID number for wells within the same sub-basin as the tank batte ry or whether it would be obligated to list the well ID number for all wells that had product de livered to the tank batt ery 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 fromthe 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? W ould Concho be required to report all wells that delivered product to the tank batt ery at any time during the repor ting year or would only those wells that had product present in the tank battery at the time th e flare operated be “associated with” the flare stack?

Given the inconsistency with ot her provisions of Subpart W, a nd the recordkeeping burden and practical and compliance problems described ab ove, 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 fo r only wells within the same sub-basin as the location of a tank battery or must instead list the well ID number for al l wells that had product delivered to a given tank battery during the reporting year, regard less of the sub-basin in which the well is located, and (3) dele te proposed section 98.236(n)(13).

Response 4: The EPA is finalizing the well identifi cation number reporting requirements for wells but not for other emission sources. See Secti on II.D of the preamble to the final rule for additional discussion res ponding to this comment.
The EPA is not finalizing the proposed require ments to report a list of well identification numbers for storage tanks and flare stacks; as such, proposed 40 CF R 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 requ irement for blowdown locations. ... If EPA intends to retain this proposal, then we would urge the agency to at least provide pi peline operators more time to comply with the requirements of the new rule s pertaining to Onshore Natural Gas Transmission Pipelines, so that the precise bl owdown locations can be ascertainedin the requisite detail and reported accurately. We believe that it would be appropriate to ex tend the effective date for the new rules by six months, so that they would ta ke effect on July 1, 2016, rather than on January 1, 2016.

Commenter 0133: We agree thatreporting 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 pipe line blowdown volumes, including categorizing them into the seven categories established in th e most recent rule revision (effective January 1, 2015). Although we have been voluntarily trackin g and reporting blowdown emissions for some of our operations under the EPA Natural Gas St ar Program, the proposal will increase these obligations significantly. Therefore, we request that re porters be provided a dditional time to set up adequate internal processes to comply.

Response 1: The EPA is not finalizing the requiremen t to report the emissions or latitude and longitude for each individual blowdown, so extendi ng 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, Re presenting 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 Am erican 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 Am erican 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): 4140 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, SierraClub, 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 Mon itoring Methods, otherwise known as BAMM. EPA proposes to allow operators to use preapproved BAMM fr om January 1 through March 31, 2016, to implement the systems necessary for the proposed reporting. INGAA believes that this is insufficient time for gas tr ansmission 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 de veloped BAMM provisions for the initial implementation of the proposed amendments, w ith the ability for ex tension requests through December 31, 2016. However, the proposed vast e xpansion of the rule to include oil well completions and workovers with hydraulic fr acturing, coupled with two completely new segments, creates great challenges in being inclus ive of all segments with regard to monitoring methods.

Commenter 0125: We request that EPA automa tically allow BAMM for the newly required elements to be extended to December 31, 2018. No te that EPA allowed 3 years of BAMM when Subpart W was originally proposed for the produc tion 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 wi th the rule. This would allow reporters sufficient time to get the additional data collection, mana gement, and reporting systems in place for the newly required data elements. This will take a significant amount of time and effort. Operators141 that may have common ownership in more th an one segment will be required to follow monitoring methods from each segment.

Commenter 0130: We urge EPA to revise the propos ed rules relating to the use of best available monitoring methods (“BAMM”) to provide more flexibility and a grea ter 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 exte nded), 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 b ecause the proposed rule s would not only subject entirely new industry segments to the reporting re quirements, but the proposed rules would also cause a huge number of additiona l facilities and indivi dual sites and equipment components to become covered by the reporting requirements. This problem would be espe cially acute in the gathering and boosting industry segment, as e xplained above. It woul d take a significant implementation effort to institute protocols needed to report emissi ons 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 substantia l 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 pre ssure and would allow covered en tities the opportunity to design and implement needed systems in an orderly, systematic, and efficient manner.

Commenter 0132: Automatic BAMM is needed fo r 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 origina lly allowed one year of BAMM.

Subpart W became effective in 2011, and automa tic BAMM was allowed for all of reporting year 2011. 9 There is no reason data collection fo r the ONGGB industry segment should be treated differently. Entirely new industry se gments are being added to reporting, which will require a significant implementation effort.

New requirements represent a substantial increa se in the number of reporting facilities.

Even according to EPA’s underestimated impact an alysis, this proposal re presents at least an estimated threefold increase in the number of reporting compressor stations when based on the number of processi ng 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 sign ificant 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 inthe 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 re port under the Onshore Production industry segment. Thus, implementing this rule is not just a matter of expandi ng current practices to additional facilities. Understandi ng the final rule requirements, pr eparing applicability analyses, developing and implementing recordkeeping tools, conducting training, collecting data and data quality assurance/quality control (QA/QC) activi ties 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 a nd 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/contentStream er?objectId=0900006481948b3c&disposition=attachm ent&contentType= pdf. EPA estimates three compre ssor 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 f acility 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 th at 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 th e first three months of 2016 and requires submittal of a request by January 31, 2016, if BA MM 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 new143 reporting requirements within the timeframes re quired, but foresee that additional time may be necessary to complete all the co mponent counts, tank inventories, and to ensure that records of all blowdowns from transmission pipelines a nd from the new Gatheri ng 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 flexibi lity needed, and eliminate additional burdens upon reporters and the EPA for addr essing extensions of BAMM.

Commenter 0134: Pioneer agrees with GPA th at BAMM for the new Gathering and Boosting Segment should be automatically available for th e first reporting year, as opposed to only three months as proposed, with an op tion 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, a nd 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 th e same methodologies from the Onshore Production and Processing se gments are to be applied, data collection procedures and methods for emission sources in th is 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 approva l 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 beli eve that there will never be a situation where BAMM may not be required beyond the first ye ar 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 approva l is fair, appropriate, and cons istent 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 BA MM periods that EPA provi ded for other sectors when they were first included in the reporting rule.

Commenter 0137: API appreciates EPA’s recogniti on in the proposed rule that a transitional BAMM period is necessary to ensure that the propos ed 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 transitiona l BAMM for select facilities a ffected 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 emissi ons under the proposed rule. Thus, we urge EPA to extend the BAMM transitional pe riod from three months to one year and to144 make BAMM available for every new reporting oblig ation 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 obliga tions for the first time with respect to the newly acquired equipment.

Providing a one-year transitional BAMM period fo r all facilities subject to new reporting obligations under the proposed revisions to Subp art W will provide necessary flexibility to reporters and also accommodate the inevitable i ssues that will arise regarding situations beyond the companies’ control while new monitoring, r ecordkeeping, and reporting protocols are being implemented. Based on prior years of experien ce in implementing new requirements under the GHGRP, EPA’s proposed three-month transitional pe riod 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 tr ansitional period represents a reasonable balance between EPA’s goals of full compliance with the reporting re quirements 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 be lieves that a one-year transitional period is necessary and critical to resolving any additi onal issues that may arise from the ultimate finalization of this rule.

API’s position is supported by past experience, where BAMM has proven cri tical 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, EP A stated that “EPA does not anticipate a need for Best Available Monitoring Measurem ents (BAMM) beyond 2011.” But EPA found that further extensions were n ecessary in limited circumstan ces. In March 2011, BAMM was automatic, meaning that no request or appr ovals 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 regulati ons, and BAMM would be automatic ally 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 re porting year for which BAMM is be ing sought. See Subpart W: Best Available Monitoring Methods, Greenhouse Gas Reporting Program, March 2012. In 2013, BAMM continued to be available and, in f act, EPA revised the deadline by which BAMM requests must be submitted to the Admi nistrator. See 78 Fed. Reg. 11585 (Feb. 19, 2013).

Likewise, API’s members have found, over the c ourse 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 ne ver been subject to federal or state mandated reporting. BAMM has been critical in those cases. This is particularly true where ther e is limited lead time from the finalization of reporting requireme nts and the implementation in th e following calendar year. For example, with respect to natural gas actuate d pneumatic devices, providing a transitional BAMM period was essential in allowing member companie s 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 field145 survey to collect accurate data. While this re gulatory burden ultimately was not insurmountable, the additional time afforded by a transitiona l BAMM period was essential to the eventual reporting of accurate and stratif ied data on natural gas actuated pneumatic devices. Likewise, certain event-driven data colle ction contemplated by Subpart W required member companies to create and implement new data collection syst ems and new training programs to accurately collect and report the data identified by EP A. 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 bl owdown venting. These examples cited above are unequivocal su ccess stories that demonstrat e how important BAMM is as a transitional tool under the GHG re porting 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 fu ture, it is imperative that EPA continue to provide at least a one-year transitional BAMM pe riod to ensure that reporting entities have alternative options for reporting as they develop the tools and cap acity 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 r ecently 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 strict ly limit the use of BAMM to the 2016 reporting year.

Footnotes:

63 Id . at 73,158.

64 Greenhouse Gas Reporting Rule: 2014 Revision s 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 s hould allow operators to use BAMM for the entire 2016-reporting year without the need fo r 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 tracki ng 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 requi rements. This one-year waiver would also reduce the costs of compliance with the pr oposed regulation. If EPA does not agree with146 INGAA’s recommendation and BAMM is only allowe d for three months, many operators will likely submit BAMM requests by the January 31 d eadline. 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 cannotreasonably be obtained. Per EP A’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 re porting 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 sin ce 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 BA MM, 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 methodol ogies 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 sec tion. Starting no later than April 1, 20167, you must discontinue using best av ailable 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 Morg an proposes EPA strike all of the proposed 98.234(g)(6) which discusses “Requests for extensi on 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 reporti ng year to accommodate the time needed to integrate new technology and data collection an d 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 emissi on sources included in this rulemaking. See147 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. Howeve r, EPA should retain their ability to review BAMM requests and decide whether approval is gr anted. GPA also reminds EPA that the ability to grant BAMM requests for compressor monitori ng was critical during the period of rule reconsideration for that equipm ent type. Should an analogous situ ation 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 pr oposed 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 3 1, 2016 without seeking prior EPA approval; reporters could also requ est 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 reporte rs 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 be yond 2016 would not be a possibility under any circumstance. See

, e.g. , 79 Fed. Reg. 73151 (stating that “[f]o r 2016 emissions only, the EPA is proposing to allow the use of short-term tr ansitional BAMM”). We believe, however, that circumstances could arise well beyond 2016 that c ould make the use of BAMM appropriate. For example, a transaction could occur after 2016 where by assets that were not previously subject to the reporting rules were acquired by and added to a larger syst em, making the acquired assets subject to reporting for the first time. In sucha 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 situ ation, the acquiring company should at least have the opportunity to ask EPA for permission to employ BAMM. We see no r eason to finalize rules that could eliminate the possibility to use BAMM, with EPA’s pe rmission, 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 f acilities, they must be incorporated into existing facility reporting. In another scenario, two small non- reporting assets may be combined and trigger the reporting threshol d. 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 anothe r facility that was not previ ously subject to Subpart W. However, this is not adequate for ONGGB dive stiture and acquisition. For example, if an acquisition closes on December 1, the provision s of sections 98.235(e) and (f) only cover January through June (the first six months of requ ired data collection). Th ere 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 th e previous owner or operator, GPA notes that there is no distinction in the leve l of effort required to integrate newly acquired sources into an existing reporting program whet her 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 pr eviously reported by another company. As a practical matter, ther e is no distinction in the level of effort required to integrate a newly acquired well into an existing reporting program ba sed 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 S ubpart W reporting requirements, each well is unique and companies must have th e 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 pe rmanent 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) a nd (f) already provide for the use of engineering judgment during the fi rst 6 months of data collect ion. This ensures consistency between the new segments and the emissions sour ces already covered. See Section II.E of the preamble to the final rule for additional discussi on of transitional BAMM that is being finalized in this rulemaking.150 Commenter Name: Kathleen Sgamma Commenter Affiliation: Western Energy Alliance and Am erican 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 re questing 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 tim e to incorporate and re-evaluat e the methods of monitoring on a corporate, grand scale. This is necessary for operators to ensure the implementation of monitoring methods can be efficien tly applied and integrated acro ss 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 reque sts 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 transi tional 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 ex isting BAMM programs that can be implemented by new in-scope facilities, providing such data woul d give facilities a means of scaling up certain emissions data. Such an approach to supplem enting existing BAMM procedures would have the benefit of reducing inconsistencie s in BAMM data reported by diffe rent 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 inco rporated into the s ubpart W requirements; BAMM is reserved for reporters that are reasonably unable to follow the subpart W requirements. Therefore, outside of the transi tional BAMM provisions being finalized in this rulemaking, the EPA does not agree to allow report ers 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 calcu lation 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 in tends for the new Subpart W provisions to become effective on January 1, 2016. 23 However, given the substant ial logistical issues that would be involved in complying with the new ru les 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 ur ge EPA to extend the e ffective date until then in order to allow reporters a reasonable amount of time to iden tify affected sources and to develop and implement reporting systems need ed 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 de tails, see Section II.E of the preamble to the final rule.152 

### 7.0 Disclosure Concerns Rela ted 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 irreparabl e 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 confid ential business informati on (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 ar eas 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 or der 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 sp ecifically allow companies to designate as “confidential” data obtained from exploratory wells, particularly wells in ne w discovery areas, or areas that are being explored for development. The original intent of state oil and gas commissions and federal offici als 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 experi menting with new to ols and techniques.

Releasing data to the public regarding operating characteristic s of such wells, including postflowback flaring/venting volumes, could cause co mpetitive harm if made publicly available too early. Industry makes substantial investments in exploration and develo pment projects in new153 areas. These investments in expl oration are long-term and it take s a long time for companies to characterize the magnitude and pot ential production charac teristics of prospective resources. In some areas, companies may spend hundreds of m illions of dollars per ex ploration project, in addition to the hundreds of millions of dollars inve sted to acquire leases. These costs consist of testing the prospective area via drilling, anal yzing field and laboratory information and determining whether it is a viable commercial pl ay. Releasing data to th e public too soon on such wells through the GHGRP – despite the fact that they are held confiden tial 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 info rmation on new wells, internally developed assessments of geologic prospects, drilling plan s and interim results. Competitive harm may occur if the public can obtain detailed high re solution 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 publ ic 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 m onths during the same year.

In light of these concerns, API is encouraged by EPA’s recognition in the pr oposed 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 fo r 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 ta nks: 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 e xploratory 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 ra tio 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 dr illed 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 natural154 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 y ou used Equation W-10B to calculate annual volumetric total gas emissions for completions that vent ga s to the atmosphere, th e flow rate at the beginning of the period of time when sufficien t quantities of gas are present to enable separation, in standard cubic feet per hour, fo r each well in the sub-basin (“FRp,i” in Equation W-10B).

 40 CFR 98.236(g)(7) – For ea ch 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 ea ch oil well completion or workover and well type combination, annual CO 2 emissions, in metric tons CO 2

.

 40 CFR 98.236 (g)(9) – For ea ch oil well completion or workover and well type combination, annual CH 4 emissions, in metric tons CH 4

.

 40 CFR 98.236 (g)(10) – For each oil well completion or workover and well type combination, the total N 2 O emissions, in metric tons N 2 O, 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 de ferred for a period of two year s. While providing significant protection to our members, such an approach wi ll 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 e xploratory 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 in clude it in its public data release for at least two years. This can be accomp lished 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 wi ll not require case-by-case review of companies’ information, and they are c onsistent 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 sp ecific 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 th e 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 a pplies to all situations that involve multiple non-exploratory wells or a mix of ex ploratory and non-exploratory wells.

The EPA foresees no disclosure concerns with the inputs identified by the commenter beyond the 2-year delay in reporting provide d in the proposed rule. The co mmenter has previously noted that information related to exploratory wells is made available by state agencies after 2 years. The commenter did not specify thei r disclosure concerns, nor did th e 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 repo rting for these inputs as proposed.156 

### 8.0 Confidentiality Determinations an d 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 repor ting element in section 98.236(aa)(10)(i), “[t]he quantity of produced gas th roughput 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 proces sed (residue) gas leaving gas plants as confidential. ” 30 The EPA should allow businesses to dete rmine the confidentiality of the gas received because ONGGB companies have contract agreements with produ cers 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 th e company operating the gathering and boosting system . . . ” 31 The GPA questions the phrase “is not likely.” The ma in scope of the GHG inve ntory is to provide information concerning the greenhouse gases on an annual basis at a faci lity or facilities and should not involve publiciz ing the input values.

Footnotes:

30 Greenhouse Gas Reporting Rule: 2014 Revision s 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 S ection 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 repor ting 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 Confidentia l 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 th e 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 cont ract may be established for long periods of time, contracts at other stations ow ned 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 co uld lead to a compe titive disadvantage in negotiating any open contracts within or outside of that basin.

Additionally, EPA is also requesting the data el ement section 98.236(aa)(10)(i) “[t]he quantity of produced gas throughput in the calendar year, in thousand standard cubi c feet.” If both the throughput and the fuel use are pub lically 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 th e reporting threshold. Indeed, even if this fuel efficiency was av ailable for every single ONGGB owner and operator nationwide, this would result in competitive information that w ould not be publically available otherwise, and this could a lter how contracts are negotiate d. 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 th e reporting facility. As previ ously 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 elemen ts in 40 CFR 98.236(aa)(10) for the final rule. See Section III of the preamble to th e 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, SierraClub, 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 ag ency’s determination that these data are not confidentia l business information, and, accor dingly, will be made publicly available. Transparency is of the utmost impor tance to the integrity and usefulness of Reporting Program data. It is especially important to have reliable information about facility characteristics158 and operations in order to understand the driver s of emissions and opportunities for reductions, as well as to verify the accuracy of emissions reporting. This informa tion also has important market uses, allowing investors and purchasers to factor in em issions 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 Institut e, Unlocking the econo mic potential of North America’s energy resources, at 10-11 (June 2014) (concluding that uncertainty about environmental impacts and regulatory policie s 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 Am erican 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 informa tion, are not essential to the emission calculations required under the GHG em issions reporting rule. These added data elements do not embody the purpose of the GHG emi ssions reporting rule a nd, in being mindful of limited resources and challenging economic times , should not be required of the regulated community. For instance, EPA has added many repor ting 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 nu mber of tanks in a basin or subbasin is not used in calculat ions 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 releva nt 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. Wh ile 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 in formational benefit to EPA and may detract for reporting entities’ ability and focus to provide ti mely 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 (G HGRP) and the original intent of Subpart W.

GPA understands that the onshore natural ga s gathering and boosting (ONGGB) industry segment was included in the original Subpart W proposal. GP A also understands that there currently is a data gap in GHG reporting without this industr y segment. However, in the preamble, EPA states “[t]hese pr oposed 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 info rmation from the largest sources contributing to approximately 80% of the emi ssions from each industry segment. 7 This rationale explains why EPA does not require all possible emitting equi pment to report in each industry segment. However, in this proposal, EPA provides no eval uation of which emission sources contribute to 80% of emissions from the ONGG B 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 goa ls for collecting the GHGRP data considering the extremely labor intensive data collection e fforts (for example the thousands of direct measurements from compressors which were ha rdly discussed in the EPA Compressor White Paper). GPA supports informed data collection, bu t with shifting goals and unclear intended uses for the data to be collected, GP A cannot endorse collection of data merely because the equipment type can be found within an industry segmen t. We do not support the notion that the GHGRP was intended to collect 100% of available emissi ons 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 colle ction efforts that GPA considers unreasonably burdensome.

Footnotes:

6 Proposed Rule at 73,151.

7 Mandatory Reporting of Greenhouse Gases: Petr oleum and Natural Gas Systems, 75 Fed. Reg. 18,608, 18,614 (Apr. 12, 2010).161 Commenter 0132: Blowdown vent stack reportin g requires continuous data collection, which requires extensive training, pers onnel 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 mu st involve field operators tr acking every si ngle blowdown. Training every operator in a company to eval uate blowdown events, document the results, determine if they should be reported under S ubpart W (including evaluating and documenting physical volume), maintain the proper record s, and transfer the records to the GHGRP coordinator is overly burdensome.

Commenter 0141: The Proposed Subpart W Revisi ons would impose on the oil and gas industry a number of unnecessary, costly, and burdensome monitoring, da ta 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 a nd gas industry (e.g., the recent am endments to 40 C.F.R. Part 60, Subpart OOOO) and the recently announced proposal to adopt methane regulations tailored to that industry. Moreover, the Pr oposed 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 prom ulgation of other oil a nd gas industry specific regulations, creates regulatory uncer tainty and does not provide i ndustry adequate time to adapt monitoring, recordkeeping and reporting systems to the constantly changing regulatory requirements. EPA should either not adopt or sh ould delay adoption of the Proposed Subpart W Revisions.

Commenter 0141: Many of the data elements th at the Proposed SubpartW Revisions would require be gathered and reported are not releva nt to the emission calculation methods employed in the regulation and should not be part of th e 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 ta nks in a sub-basin is not used to calculate emissions under Subpart W. The requirement to in clude 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 a nd elements reduces efforts to find innovative technologies to increase accuracy and efficien cy in operations. EPA should reconsider the addition of data elements to report in this rule making, particularly those that do not pertain to emission calculations. EPA should only require repor ting of emissions calculation “value added” information.

Commenter 0142: Due to Kinder Morgan’s extens ive natural gas pipelin e network and sizable number of facilities providi ng natural gas transmission, storag e, and processing services on a continuous basis, Kinder Morgan has a large nu mber of facilities tr iggering GHG reporting and monitoring. In fact, Kinder Mo rgan’s monitoring a nd reporting alone has resulted in the162 collection of thousands of data inputs over the last four (4) years. EPA indicates that the Proposed GHG Reporting Rule is intended to “enhan ce 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 da ta 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 overa ll annual burden to be assumed by operators as a result of the Proposed GHG Reporting Rule – partic ularly during the initia l reporting year, which will require substantial start-up costs to devel op data collection and management programs and train personnel for newly designated source cate gories. Kinder Morgan respectfully requests EPA consider the impacts of these burdens on operat ors 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 benefi cial, cost-effective, and feasible mechanisms related to reporting requiremen ts and the development of n ecessary GHG emissions data.

Response 1: The EPA appreciates the commente rs’ 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. Secti on 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 es timate 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 pipe line operators under regulation by OPS. OPS estimated that 50% of these operators are poten tially 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 400163 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 re late to rule applicability. If an ONGGB facility is aggregated across a county or a basin, it is more likely th at 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 Natura l Gas Processing industry segment will total 291 reporters. GPA wishes to point out that by th e nature of the industry, any company with a processing plant will most likely also have an as sociated gathering system subject to reporting, therefore the number of repor ters in the ONGGB i ndustry segment will total 291, at minimum, but potentially more.

Response 2: The EPA disagrees with the suggested ch ange to the number of reporters in the Onshore Petroleum and Natural Gas Gathering a nd 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 docu ments 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 Tran smission Pipeline facili ties. 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 co mplete a PHMSA annual report (PHMSA F-7100-2) or are regulated by FERC unde r 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 cha nge 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 comm ents, which outlines the cost estimates GPA believes are associated with the proposed rule.164165166167 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 gather ing 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 cont ent and dry gas water content require sampling Sampling labor includes travel to and from the booster station

Blowdown Vent Stacks Includes training to ensure consis tent 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 b ooster 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 consis tent 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 samp le, 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 “ass igned” 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 me thodology for this industry segment

Data Management Assume data management system exists, require s modifications for Subpart W reporting

Reporting and Compliance Management Costs based on individual booster station costs168 Response 4: All burden estimates in the commenter’s Table 1, except for Gathering Pipeline Fugitives, Storage Tanks, and Combustion, are al so 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 Na tural Gas Gathering and Boosting segment or reporters that are currently subj ect to the Onshore Natural Gas Pr ocessing segment. As discussed in Section IV.B of the preamble to the final ru le, 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 th at “[n]o centrifugal compressors [are] used for gathering.” According to an April 2013 article about gatheri ng 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 Gatheri ng and Boosting segment are expected to have centrifugal compressors, and these should be incl uded in the Onshore Petroleum and Natural Gas Gathering and Boosting facility where they exist.

Also, it is not clear whether the estimates are base d on an average of multiple reporters or a highend estimate, which could determine whether th e assumptions should be applied differently based on the size of the reporter.

Unfortunately, for the above reasons, the comm enter 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 al ready subject to subp art W of Part 98.

Without more detailed citations or support, there is no justif ication 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 Am erican 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 Am erican 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 Am erican 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 th at the newly proposed requirements pose an especially high burden on the industry sect or. 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 incremen tal 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 reporti ng burden estimated by EPA fo r the newly defined reporting segment of Onshore Petroleum and Natura l Gas Gathering and Boosting is grossly underestimated. Based on API’s members’ experi ence 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 cost s for setting up the reporting and recordkeeping systems for this newly defined segment.

For the onshore petroleum and natural gas produc tion segment, EPA states in its own assessment that the proposed reporting amendments woul d impose an additional annual burden of 57,963 technical hours for the production segment, wh ich API contends is also underestimated.

API maintains that EPA’s estimate is highly unrea listic since it would mean that the increased annual burden for implementation of the new repo rting requirements for the production segment would amount to only 29 hours per response, which is totally unrealistic, es pecially in view of the extent of the new data collection a nd measurements required for implementation.

So, for example, the inclusi on of reporting requirements fo r blowdown vent stacks for the gathering and boosting segment will be quite burdensome for unmanned sites. The EPA Technical Support Document justifies using de fault emission factors for quantifying fugitive emissions associated with the gathering and boos ting segment, quote, because, as in the onshore petroleum and natural gas production segment, th e equipment is often geographically dispersed and may be visited only intermittently, end of quote.171 For this same reason, EPA should exclude the re porting of emissions from blowdown vent stacks for gathering and boosting segment, similarly to its exclusion from th e 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 me ter installation and recalibra tions that would be required due to the inclusion of completi ons and workovers of oil wells w ith hydraulic fracturing and the two newly proposed segments will significantly incr ease the efforts and costs of compliance. The applicable elements of Subpart W are spread out over very large geogr aphical regions. The mobilization man-hours and associatedcosts need to be factored into the overall cost impact of the amendments. The availability of not only th e meters, themselves, but also the contractors needed to perform the installati ons and calibrations is unknown. Furthermore, if liquid and/or gas compositional data are required for calibrations, mo re contactors will need to be hired to properly gather and analyze the samples. S ecuring 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 expa nsion of oil wells completed with hydraulic fracturing and the addition of the two new reporti ng 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 associatedwith 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 previous ly were not required to be re ported under the cu rrent Subpart W rule. 2 Based on Alliance members’ experience, EPA va stly 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 impl emented. This process includes:

1. Developing new processes and creating or m odifying software to collect the required information 2. Updating monitoring plans 3. Conducting training for persons responsib le for collecting and reporting data 4. Auditing new data elements for accuracy 5. Revising reporting processes and upd ating 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 segm ents). 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 su ch items as conducting site-specific inventories, gathering and analyzing oil or gas samp les, 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 ex isting 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 th e associated amendments.

Footnotes:

2 Operator-provided Alliance member estimate th at the number of sources that would require evaluation and potentially be reported under th e gathering and boosting segment would increase 112% compared to the current number of s ources reported for the production segment.

Commenter 0125: In the very least, we urge EP A to recalculate compliance and implementation dates for the proposed rules in light of the si gnificant man-hours that will be required to implement the proposed data additions and changes to calculation methodologies.

Commenter 0132: According to Appendix B of th e Supporting Statement, it appears that EPA estimates there are eight tanks per reporter. With EPA’s estima ted 200 reporters, this yields a total of 1,600 tanks. GPA estimates that there ar e several thousand tanks in the ONGGB industry sector, if not tens of thousands. Just on e 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 proposedamendments to subpart W are not expected to significantly increase burden.” We respectfully di sagree and believe the proposed rule is very expansive and burdensome as written. As demonstr ated 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 downstr eam of gas treatment). This estimate is low, but even still, this means that for each gas processing plant, there is a threefold in crease 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 syst em associated with those compressors stations.

Without looking at any other numbers, this inform ation alone is enough to realize this rule, as proposed, will be a very significant increase in bu rden; therefore, we ask EPA to implement the many suggested revisions to signific antly reduce the compliance burden.173 Commenter 0132: EPA’s estimate of total responde nt time is significantly underestimated and unreasonable.

Section 6(a) states that the to tal annual burden to all affected entities is 63.4 hours per year. We urge EPA to reevaluate this determ ination. It is not reasonable to assume that it would that it will take a reporter just eight business days to: revi ew the rule; understand the rule; develop training materials; train all affected personnel; develop a budget; hire and schedule contractors where needed; evaluate facili ty applicability; update the monitoring plans; develop recordkeeping systems; collect all the data; coll ect 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 co rrect reporting form (which can include XML programming); and review the final re ports 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 estima ted time. Due to staff turnover, nearly none of these requirements is a “one-time only” requir ement. Reading and understanding the rule and training personnel are ongoing task s. According to Appendix D of the Supporting Statement, EPA estimates the total time burden for ONGG B to be 9,297 hours for 200 reporters, which is just 46.5 hours per reporter – or just six business days. EPA s hould revisit and revise these inaccurate time estimates. We believe that se veral 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 th ese 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 require ments 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 ta nks within the Gatheri ng and Boosting segment for our two affected business units . Next reporters must determin e whether or not the tanks are considered “atmospheric”. Then, reporters must determine daily oil/cond ensate 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 through put is greater than or equal to 10 bpd.

Conducting a full inventory, including characteri zing the type and amount of fluids passing through each tank daily, is a daunting task. Ot her 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 requir ed by the proposed rule on all fluids tanks is not currently available.174 Commenter 0133: Determining whethe r 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, EP A proposes that the Gathering and Boosting segment blowdown emissions be reported accord ing to the current ru le, with the expanded blowdown event categories that became effec tive on January 1, 2015. These categories include planned or emergency shutdow ns 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 Ga thering and Boosting segment. Th e EPA states in the preamble that the exemptions should alle viate any concerns with the burden of calculating emissions from small gathering pipelines. Neverthe less, reporters still will need to conduct an inventory of all pipeline and equipment measurements to charac terize 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 im plement these new requirements within the proposed timeframe, but believe it will be a substantial effort.

Commenter 0134: With the expansion of oil well s 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 majo rity of cost, time and efforts are associated with gathering and documenting required data under the regulation. A lthough considered, EPA has vastly underestimated the amount of time that is needed in order to modify data collection and management and update reporting systems a nd 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 ac cessed, how it can be integrated into the current data management systems and processes, and ho w it can be recorded into existing raw data reporting formats. This process will take addi tional man-hours per data element, and based upon Pioneer’s historical/previous repo rting experience, vastly more than EPA has estimated in its technical documents supporting this rule, especially dur ing the initial implementation of data gathering and reporting of th e 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 curre nt data management systems in place in determining compliance and implementation dates.

Commenter 0137: EPA has significantly underes timated the level of effort for reporting emissions associated with the newly define d Gathering and Boosting segment, reporting emissions for oil well completions and workove rs, 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 opp ortunities for reducing the reporting burden without compromising data completeness and accuracy.

Commenter 0141: EPA has significantly underestimat ed the amount of time that will be required to modify data collection, management, and re porting systems to comply with the Proposed Subpart W Revisions. To compile the numerous categor ies of data that would need to be reported175 to comply with the Proposed Subpart W Revisions, operators and producers will need to evaluate whether such data points are alr eady being collected, where the da ta can be accessed or how it can be collected, how the data can then be integr ated into current data management systems and processes, and how it can be integrated into ex isting raw data reporting formats. This process will require extensive coordination among field opera tions, third parties, IT staff and others. The total time to develop compliant data compilation and reporting systems will be significantly greater than the EPA estima te 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 da ta collection activities.

Regarding Commenter 0132’s comment on time a llowed 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 blow downs 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 blowdow n event in an entire year at an ONGGB compressor stat ion is unrealistic.

A more reasonable estimate for one compressor station is 24 blowdowns per compressor, 12 blowdowns from filter/strainer opening, four othe r blowdowns for routine maintenance, and one pipeline blowdown within the fenceline. Assumi ng 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 98.2 33(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 mi nutes x 200 reporters)/ 60 min/hr = 18,987 hours, compared to EPA’s estimate of 213.3 hours. To cal culate 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 Prot ection Agency--Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule (40 CFR Part 98, subpart W), Ap pendix B at note j, Do cket 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, th e EPA disagrees with changing the number of blowdowns at Onshore Petroleum and Natural Ga s 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 Assessm ent 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 th e implementation of this burdensome reporting requirement for the ONGGB industry segment. It is unreasonable for EPA to include this burdensome requirement without justifying the needfor 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 “separ ators” and separator throughput). While this data is usually availabl e 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 least177 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 es timated and is at least an order of magnitude higher.

Additional tank specific data w ould 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 pressu res 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, EP A 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 ta sks and underestimate the burden of each task.

For tanks, EPA estimates “1 minute per separator fo r 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 es timated 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 th e 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 re porting 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 samp les of pressurized liquid must be planned to ensure that the task is completed in a safe and correct manne r (without depressurizing the liquid). Additionally, the sample containers must be prepared and obtained, the task planne d and coordinated with other site activities, which ma y involve a safe work permit, the sample taken, the sample transported or shipped to the lab, analysis comp leted, laboratory report pr epared, results provided to the company, data entered in a centralized da tabase, and emissions determined for subsequent reporting. For unstabilized condensat e liquids entering a tank, the sample must be taken at the separator, which may not contain liquid when th e operator arrives to pull the sample. This could add even more time to this task.

Fourth, EPA’s assessment of 30 minutes to pe rform 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 r un 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, EP A 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 perfor m simulation run.” This dump valve task certainly takes time, and this time must be accounted for in EPA’s co st analysis. Like blowdowns, this piece of information requires continuous data collection, so every operator, a nd 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 al ready do), but most importantly, they will need to be trained to document any issu es, maintain the proper r ecords, and transfer the records to the GHGRP coordinator. It is difficult to assess an appropriate amount of time to assign because this is a conti nuous 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 ou t of the total site flare emissions. This is a complex set of calculations and EPA should estima te 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 w ith the requirements for storage tanks in the Onshore Petroleum and Natural Gas Production se gment. 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 subjec t to subpart W of Part 98, including the burden estimates related to storage tanks. Therefore, th e burden estimates presented here are appropriate for storage tanks in the Onshore Petroleum a nd 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 deta iled information, there is no justification for changing the proposed estimates.

For stuck dump valves, the EPA requires the de tection 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 insp ection procedure to detect stuck dump valves, the rule does not require any “continuous data collection effo rt” for stuck dump valves. Therefore, the commenter provides no justifi cation 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): 18179 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 do cumentation 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 methodol ogies for the source category.

Response 8: For Onshore Petroleum and Natural Ga s Gathering and Boos ting, 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 Fina l 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 mete r 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 fo r 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 change s 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 informati on, there is no justification for changing the proposed costs related to the above data collec tion 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 arbitrar y and capricious because it significantly underestimates the data collection and reporting burdens that will be imposed on regulated180 entities in the oil and gas sector. In imple menting the GHG reporting program, EPA cannot simply operate with the assumption that more datais 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 co llecting more data simply cannot be justified based on the limited new information that can be gl eaned from collecting more data. In order for regulated entities, the general pub lic, and, if necessary, the courts , to appropriately weight the benefits and burdens of additional data reporti ng, it is essential that EPA accurately report the costs and benefits of its proposal in the admi nistrative 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 creat ed the risk that the public will support ever expanding reporting obligations without fully unde rstanding the regulato ry burden associated with each incremental piece of information sought by EPA.

For example, for onshore petroleum and natural gas production, EPA proj ects 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 ma y face new obligations related to completions and workovers of oil wells with hydraulic frac turing. 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, th e 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 ba sis. The justificati on of these additional obligations is significantly diminished if the full implementation costs are considered.

Likewise, EPA’s burden estimates for Petroleu m 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 50 0 hours per year. Even the lowest estimates are an order of magnitude higher than EPA’s projec tions. Again, these drama tically different cost estimates call into question EPA’s assertions that the costs of th e proposed rule are justified by the regulatory benefits. Hence, EPA would have to demonstrat e that the propos ed rule would lead to substantially higher re gulatory 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 assura nces, the public cannot fill its critical role of reviewing a nd providing substantive comments on EPA’s proposed rules in order to provide constructive feedback that improve s the rulemaking process and the Agency risks misleading the public regarding the costs and bene fits 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 es timated for existing reporters related to completions and workovers of oil wells with h ydraulic fracturing. As shown in Appendix B of the Supporting Statement, there are 246 existi ng 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 mist akenly 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 th at are expected to report comp letions 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 fi rst 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 th e 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 esti mates 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 requi re reporting of well ID numbers is arbitrary and capricious because the burdens associat ed with collecting and reporting this data far outweigh any minimal benefits in data quality that EPA asserts ma y be provided. In the technical support documents accompanying the proposed rule, EPA assumes that “[well ID] numbers are readily available and do not re quire any additional data gath ering 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 additi onal burden and costs (beyond the additional182 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 atan aggregate basin le vel, 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 we lls 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 cost s 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 re porting 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 signifi cantly higher than what EPA estimates. In particular, data estimates for the first (and possibly seco nd) 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 sign ificant. In light of the limite d 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 facilitie s to report Well ID numbers exceeds EPA’s established requirement of re porting GHG emissions at the basi n 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 speci fic wells within a given basin irrelevant for purposes of calculating and reporting GHG emissions.

Furthermore, as already discussed above, API be lieves that EPA’s propos al to require reporting of Well ID numbers is arbitrary and capricious because the burd ens associated with collecting and reporting this data far outweigh any minimal be nefits in data quality that EPA asserts may be provided. Such a requirement would merely pose a substantial reporting burden without impacting the quality or substan ce of the reported GHG emissions.

API strongly objects to EPA’s prem ise that the burden of incor porating Well ID information is very low and view it as uninforme d. The reality is that the burden for accounting for differential183 mapping of Well IDs per the require ments for each of the specified data elements amounts to a burden that is at least one order of magn itude, or more, higher for each respondents in comparison with the extremely small burden assumed by EPA.

 From data received from API members onshor e operations in five almost all gas producing basins in the lower 48 (represen ting about 9,000 gas produc ing wells in a mix of tight formations; shale; coal bed meth ane; 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 stre amline 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 about200 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 re porter 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 identific ation number reporting requirements for wells but not for other emission sources. See Secti on II.D of the preamble to the final rule for additional discussion res ponding 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 recordkeepi ng and reporting into e-GGRT amounts to only 10 hours each does not withstand any reality check wh en 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 assu med in EPA’s ICR burden analysis.
Response 12: This proposal only affect s three segments of subpart W and there were 400 new reporters estimated at the time of proposal. Re cordkeeping and reporting burden was calculated for the remaining segments during a previous su bpart 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 presen ted 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 ma nagers as part of their review function. However, in the table that summarizes responde nts’ burden EPA estimates that the total number of incremental hours spent per ye ar by all respondents to in clude 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 manage ment 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 e ngineers’ burden, respectively. Based on EPA’s assumptions, the annual burden for mid-level mana gers ought to be take n 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 Suppor ting Statement, footnotes “c” and “d” do not apply to every activity liste d, so the estimates quoted by the commenter are overestimates of the burden.

The footnotes apply to 4A “Read Rule, Inst ructions, 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 F acilities--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 Supporti ng Statement and all affected Appendices. This change resulted in no cha nges 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 th e 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 c ould 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 costs185 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 requi rements are not included in the final rule. See Section II.C of the preamble fo r 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 ha ve 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 compresso rs 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 i ndustry segment have “two flare stacks per compression station and one pe r gas treatment facility.”

While GPA acknowledges that the presence of fl ares at compression stations is becoming more common, it is inaccurate to assume that each comp ression station has two fl ares. 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 boostin g station has “one is olation 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 stat ion inlet and discharge. It should be noted that many sites may have more than one inlet pe r 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 rath er than 2 flares per site.186 To account for potential differences in Onshor e 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 Pe troleum 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 acros s the North East, Midcontinent, West Coast, Gulf Coast, and Rocky Mountain regions, co mbined, there are 35,930 small compressors and 136 large compressors. This totals 36,066 compresso rs. If GPA uses EPA’s assumption of three compressors on average per site, this will tota l 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 basi n 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 indus try groupings in the I nventory 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 u nder fossil fuel combustion in the Inventory. In other cases, the source categor y definition in the GHGRP may in clude 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 CO 2 e 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 resi dential sectors. Industry types that have a large number of facilities that fall below the 25,000 metric ton CO 2 e reporting threshol d include: landfills, industrial wastewater treatment, zinc producti on, glass production, petr oleum and natural gas production, and emissions from general st ationary 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 necessa ry, appropriate monitoring plans for each affected source and each affected unit at a source, as applicable;

2. Conducting operation and maintenance ac tivities associated with the monitoring, including qua lity assurance activities;

3. Ensuring data quality, preparing a nnual 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 Stat ement, only some of those activities were included, and the time estimates for those activitie s are much less than rea lity. It does not appear that EPA accounted for the time to implement a nd update monitoring plans, collect samples and conduct required analyses as n eeded, conduct quality a ssurance activi ties, ensure data quality, and respond to questions or error message from EPA.

Commenter 0132: EPA’s impact and cost assess ments completely fail to include time for training. Because blowdown reporting requires continuous monitoring, training operators or contractors on the requirem ents 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 supe rvisors. For simplicity, we assume that there is one operator for every four sites, who complete s 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 become s an additional eight hours per year.

Response 17: Conducting quality assuran ce activities, ensuring data quality, and responding to questions from EPA are included in the reporting burden allo tment of 10 hours per year.188 Implementing and updating monitoring plans are in cluded in the 10 hours per year allotted to recordkeeping burden.

Training is included in the 5 hours pe r year allotted to read the ru le, 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 seco nd 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 minimi s facilities are not included. Complying with the proposed rule is a two-step process. Compa ny personnel must travel to the site to conduct each blowdown event and then reco rd the additional information to track pipeline blowdowns. EPA makes reference in its support ing statement that na tural gas transmission pipeline reporters would perfor m engineering calculations base d 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 informati on annually for each blowdown location site. Not only should EPA factor in the costs for either co mpany 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 Tr ansmission 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 sugge sted that including sma ll ancillary equipment189 results in a much higher numb er of blowdowns than proposedby 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 pipe line blowdowns from 72 per respondent to 17 per respondent.190 

### 10.0 Advanced Innovative Monitoring Methods

The EPA received the following comments in re sponse to the request for comments on the feasibility, possible regulatory ap proaches, and provisions necessary to incorporate or allow the use of advanced measurement or monitoring me thods 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 rulemaki ng. Instead, following review of the data and information received in comments, the EPA ma y 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 th e proposed rule, the EPA discusses the potential opportunities for applying remote se nsing technologies and other innovations in measurement or monitoring technol ogy to identify and calculate em issions from affected sources under Subpart W. EPA’s stated objectives are to determine if new and innovative technologies could be applied to the reporti ng program to improve the overall accuracy of transparency of reported data in a cost-effective way. API view s the introduction of th is topic as totally inappropriate within the framewor k of the proposed revisions, wh ich are intended to address the introduction of new reporting requirements for ne w segments and selected operations. The issue of using advanced monitoring techniques is pertinen t to all the sectors that are subject to part 98 and its various subparts and should not be constr ained 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 th e new 2015 reporting requirements are implemented.191 Commenter 0137: API contends thatthis is not the appropriate platform to consider such methods and that this discussion is premature for consideration under th is 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 Ru le, 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. I NGAA supports allowing access to technology advances and improved methods for estimati ng emissions. However, this rulemaking only addresses a subset of GHGRP sour ces 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 raisin g 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 so me initial feedback. The EPA should allow advanced monitoring and methods at the operato r’s discretion as a replacement for current Subpart W requirements. INGAA is opposed to addi ng 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 incl uded in the docket explores some options, such as approaches for alternative monitoring approval in the Gene ral Provisions of Part 60 and Part 63. While a review and approval process for alternative moni toring technologies or methods analogous to those procedures would be appr opriate, INGAA encourages a stream lined 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 monitori ng technology to identify and calculate emissions from affected sources unde r Subpart W. EPA’s stated objective for this assessment is to determine if new and innovati ve 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. Th is 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 equi pment 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 cu rrent Subpart W monitoring and192 measurement requirements as a voluntary method. To clarify application of the advanced innovative monitoring methods, Kinder Morgan enc ourages 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 proces s, 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 monito ring 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 ap proval 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, Re presenting 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, SierraClub, 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 s upports 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 th ese technologies and met hods. Pipeline operators should be given the discretion to implement a dvanced innovative monitoring methods to replace existing Subpart W requirements rather than t hose methods being in a ddition to the current requirements.

Commenter 0061: In its proposal, EPA seeks co mments on the future use of advanced, innovative monitoring methods to improve the accura cy of reported emissions data from subpart W sources. although WM’s operati ons are not subject to the subpart W GHG Reporting Rule193 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 CO 2 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 emi ssions distributed over many acres. It is our understanding that oil and gas site s have emissions that emanate fr om leaks at poin t sources such as equipment, storage tanks, and production we llheads. A second, important difference is that WM has never employed advanced measurement t echniques such as tunable diode lasers (TDL) or cavity ring-down spectrosc opy (CRDS) as continuous emissions monitors (CEMS). WM has instead employed these techniques to estimate ma ss flux emissions of methane over a particular time period. We are not sure that some of the technologies listed in th e Agency’s Discussion Paper would lend themselves to cost-effective continuous monitoring tools at this time. For example, the paper mentions differential absorp tion lidar (DIAL), but to our knowledge, very few DIAL units are available for commercial us e. They are very effective, but expensive technology and in our view are not practic al for continuous monitoring purposes.

WM does not want to impede the oil and gas in dustry from voluntarily pur suing 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 alte rnative 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 technol ogies to improve emissions inventories, and we urge EPA to adopt provision s incentivizing the use of altern ative methods subject to the agency’s approval.

In its discussion paper, EPA offers three potenti al approaches to implementing an alternative monitoring mechanism: (1) a detailed annual requ est; (2) a one-time detailed request; and (3) a public list of possible altern ative monitoring technologies. 56 Regardless of its form, such an approach should be consistent w ith the general principles of imp roved (real-time, transparent, and accurate) data quality, flexibility, innovation and continuous improvement. 57 An alternative monitoring program should first be based on transp arent, scientific data. Secondly, the program should ensure that data is availa ble in sufficient, standardized de tail and quantifiable measures to allow other groups to independent ly 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 Implemen tation 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 th e public that such monitoring methods could be used in all circumstances, without accounting for differences in application, technical feasibility, and operational consideratio ns, among others, at individual facilities. If EPA adopts any use of approved advanced i nnovative monitoring methods, EPA should make clear in the final rule that any advanced innovative monito ring methods are intended only for use in the Subpart W reporting program and shall not be used by EPA, st ates, 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 adva nced innovative monitoring method must be at the discretion of the regulated community. Verified and appr oved advanced innovative monitoring methods should be implemented as a voluntary replacement for the currently required monitoring and measurement requirements under this GHG Reporti ng 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 to tally inappropriate within the framework of the proposed GHGRP 2015 re visions that are desi gned to address new reporting requirements for newly defined segmen ts and other selected operations in the Petroleum and Natural Gas sector.

In its discussion paper on alte rnate monitoring methods, EPA cite s 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 s ector, there are several reasons why advancedinnovative monitoring methods are not suitable for this application.

These include:195  Distributed nature and the large nu mber of oil and gas facilities;

 Remote location of most oil and gas wells a nd gathering system facilities – often with no access to electricity, reliable commun ications 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 atmospheri c dispersion and flux calculations;

 Uncertainty introduced by source apportionment.

Even if advanced ambient measurement technique s were feasible for application to Subpart W facilities, they would not be able to distinguish between specific em ission sources at a facility or even which facility these emissions were comi ng 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 pe rspective would be of little to no value.

Commenter Name: Kathleen Sgamma Commenter Affiliation: Western Energy Alliance and Am erican Exploration & Production Council (AXPC) Comment Number: EPA-HQ-OAR-2014-0831-0125 Page(s): 5

Comment 4: While we continue to investigate a nd 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 im plementations before spending more time to focus on advanced met hods. Although we support the EPA’s request for operators to research advanced monitoring methods, such as possible remote sensing, monitoring, we prefer the opera tors’ limited resources to be focused on identifying and fixing leaks, rather than quantifying the volume of the a ssociated leaks. Furthermore, we feel resources should be focused on implementing current technologi es that conform to the requirements of the rule, rather than allocating re sources to future technologies.

Commenter Name: Environmental Defense Fund, Sierra Club, Clean Air Task Force, and Natural Resources Defense Council Commenter Affiliation: Environmental Defense Fund, SierraClub, 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 re spectfully suggest that the oil and natural gas sector is a good place to begin such a pr ogram. The Administration has committed to deploy196 more transparent real-time monito ring tools and methods in the oi l and gas sector, and innovative technology companies and federal agencies ar e working to develop and support the next generation of advanced monitoring technologies. In light of this dynamic landscape, advanced monitoring could play a particular ly important role in improving the accuracy and transparency of data from the oil and natural gas sector. For these re asons, we urge EPA to consider deploying an advanced monitoring program fo r 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, SierraClub, 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 pro cess 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 pr ogram will promote innovation by increasing market participation in emerging monito ring technologies and allow reporters and technology developers alike to demonstr ate the viability of a new methodology.

 Submission period: We recommend there be a defined submission period for initial applications. Initially, the agency could reque st an annual call for submissions, with the option to accept bi-annual submissions depe nding on the resulting workload. EPA could style the initial submission pe riod as an XPRIZE-type innova tion competition to create added visibility and ensure evaluation of a rigorous pool of technologies and practices.

 Focus on high-impact solutions: To ensure da ta integrity, EPA could approve a discrete number of alternative monitoring method s ubmissions each year, representing the most promising approaches.

 Phasing in alternative monitoring: Altern ative monitoring should be phased into the Reporting Program so that data from these new methods and/or technologies can be compared to similar facilities usi ng traditional mon itoring techniques.

 Clarity of data: The Reporting Program shoul d make clear which facilities are using alternative monitoring and which are not. A cl ear 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 da ta 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 requi red to demonstrate the method. EPA could qualify that an alternative method is only appr oved for sources or facilities similar to those used to197 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 consid er 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 outsi de groups to independently analyze the approved methods and allow reporters to consider the use of othe r alternative methods. 58

Consistent with these suggesti ons, EPA could adopt a two-step approach to alternative method application and approval. First, a reporter or other organizatio n or individual (e.g. equipment providers, technology developers, academic instit utions, NGOs) could submit an application to EPA describing the method and a proposed de monstration for the method. EPA would then approve a demonstration of th e method at a facility repor ting under the Reporting Program. Second, the results of the demonstration would be submitted to EPA for review and approval. The entity submitting the demonstration result s should be a reporter under the Program that intends to use the method at one or more facili ties. Based on the result s of the demonstration, EPA would then decide whether to approve the use of the alte rnative monitoring method by all entities subject to Subpart W, with appropriate conditions orqualifications 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/p ilot-credits, (last visited Jan. 27, 2015). The Pilot Credit program allows Council members to submit on line proposals for innovative green building technologies for potential accredi tation. After evaluation of the proposal, it is placed in a public database for review and comments by other memb ers 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 Perf ormance Standards for MSW Landfills, the Agency requested information on the potential to use alternative remote measuring and monitoring techniques for landf ills. 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), tra cer correlation, micrometeorologi cal eddy-covarian ce, 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, micr ometerological eddy-covariance, static flux chamber) that are typically usedto 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 co mmonly used to determine mass flux emissions they are not direct replacements for the cu rrent surface emissions monitoring method, which determines methane concentration five to ten centimeters above the landfill surface. Notwithstanding the costs of im plementation, which are signifi cantly higher than the SEM procedure in Subpart WWW and proposed in S ubpart XXX, a horizontal RPM method or other open path method could conceivabl y be useful for hotspot detec tion. The technique can be used to produce a concentration map of the surface. Howe ver, 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 fiel d validation of this method whic h includes a comparison to the surface scan method be conducted prior to consid eration as an alternate method. One important part of the field validation would be to co mpare the path-integrated measurements produced from an HRPM with the point concentrati on data of the serpentine FID measurements.

The methods of detection listed can detect mi nute quantities of methan e and can have large dynamic measurement ranges making them useful wh en employed in optical remote sensing and tracer correlation work. The solid state nature of the laser system s 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 so me distance downwind of the source, or would need to be flown over facilities, as has beendone 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 calculations 5 . 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 contemporan eous local background concentra tion to enable quantification199 of emissions from any particular site is ch allenging and another source of uncertainty. Additionally, an important character istic of oil and gas production emission sources is that there are several significant non steady state emissi on sources, and the variability introduced by episodic events such as tank flashing makes it very difficult to cal culate annual emission estimates from short-term dow nwind ambient measurements 6 . 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 cond itions. 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. Screenin g-level accuracy is not suitable for regulatory purposes, and is not useful to quantify emi ssion sources from oil and gas operations.

Footnotes:

3 http://www.phmsa.dot.gov/portal/site/P HMSA/menuitem.6f23687cf7b00b0f22e4c6962d9c8789 /?vgnextoid=a87 2dfa122a1d110VgnVCM1000009ed07898RCRD&vgnextchannel=3430fb649a2dc110VgnVCM 1000009ed07898RCR D&vgnextfmt=print

5 Thoma, E. D., et al. “Assessment of methane an d voc emissions from select upstream oil and gas production operations using remote measuremen ts, interim report on re cent 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 Me thane Emissions from Oil and Gas Production Pads using Mobile Measurements.” Envir onmental 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 ma ny of these sites are harsh and no enclosures or protection for sophisticated instrumentation and data sy stems exist. Given the cost and complexity of installing, operating an d maintaining the types of measurement devices discussed in the Proposed Rule Preamble a nd EPA’s memo (e.g., cavity ring-down spectroscopy (CRDS) or other tunable diode la ser systems ), application to the facilities and sources under Subpart W is simply not feasible from either a technical or cost persp ective. These types of devices are typically used for short-term mon itoring and measurement studies, not as fixed200 continuous monitoring systems. Should the e fforts 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- cu t-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 CO 2 and CH 4 there are large and potentially significant natural and anthropogeni c sources that may be co-locat ed with oil and gas operations. Emissions of CH 4 from wetlands, ruminants, landfills and waste treatment can lead to very high concentrations of observed CH 4 enhancement relative to background, and accurate source apportionment is difficult 7 . The typically complex intermix of oil and gas sources in a field/basin with wells, central production f acilities, compressor stations, a nd 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 sour ces along with widely variable speciation of oil and gas emissions leads to significant uncertainty in source identification. Two re cent papers using different techniques identified, fo r 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 th an those same inventories.

Given the unique characteristics of oil and gas sources, current advanced monitoring methods are not suitable for regulatory quantification of em issions. Direct emission measurement studies of individual sources (like those perfor med by Allen et al 10 11 12 ) may lead to source specific emissions data that could potenti ally be used for quantifying CH 4 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. “Anthr opogenic 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. “Ma pping of North American methane emissions with high spatial resolution by inversion of SC IAMACHY satellite data.” Jour nal of Geophysical Research: Atmospheres (2014).201 10 Allen, David T., et al. “Measurements of Me thane 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. “Metha ne Emissions from Process Equi pment at Natural Gas production Sites in the United States: Li quid Unloadings.” Environmenta l Science and Technology (2015) 49 (1), pp 641-648.

12 Allen, David T., et al. “Metha ne Emissions from Process Equi pment at Natural Gas production Sites in the United States: Li quid Unloadings.” Environmenta l 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, a nd to develop best practices to make OTM 10 and CRDS practical tools for landfill emi ssions 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 manage ment practices and/or me thod 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 emi ssions 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 landf ills are still research methods and not appropriate for emission invent ory purposes at this time. Per EPA’s Emission Measurement Center’s Interim Policy on Posti ng Methods, test methods are divi ded into four categories. For example, Category C: Other Methods includes testmethods, 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 measur ing fugitive methane or other hydrocarbons at landfills and therefore should notbe 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 contri buting 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 stabili ty 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 n eed to be developed for each combination of cover type (e.g. daily, intermediate and final) an d 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 perfor med 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 pe rcent 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 us e of static flux chambers to determine emission
rates.

Additionally, after more than 50 we eks of measurement at 20 landfill s, we are still unsure of how many measurements are required to capture accurately the temporal variabili ty of emission rates. For example, we have observed that the unit emissi on 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 oxi dation; all of which are also affected by climate (Chanton et al. 2010).

As a practical matter, we are very concerne d that only 31 percent of the 72,500 measurements obtained over 50 weeks data collect ed 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 influe nce weather (e.g., wind direction and speed, precipitation, barometric pre ssure) plays on the ability to obtain usable TDL readings. The large source size, heterogeneous so urce 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 crea te very significant uncertainti es in measuring methane flux.203 

### 11.0 Out of Scope Comments: General Co mments 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 a nd Hazardous Materials Safety Administration (PHMSA) in considering the drivers for blowdow n emissions and to pin point areas where new technology could help to reduce emissions.

Commenter 0140: EPA and PHMSA should work toge ther to identify the various drivers for blowdown emissions prior to finalizing this rule.

As EPA is aware, the 2014 GHG National Inventory 1 , 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, th is estimate is based upon an emission factor developed by the EPA/Gas Research Institute (GRI) study 2 conducted 20 years ago. The EPA/GRI study relied on limited data to develo p 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 th e total methane emissions from the natural gas transmission sector and inform the cost-benefitanalysis of reducing those emissions, the EPA should consider the current and future regulat ory drivers for various emissions categories, including pipeline segment blowdo wns. The blowdown of a pipeli ne segment is essential for certain pipeline maintenance, testing, and replace ment activities. Pipeline operators must have the flexibility to blowdown pipeline segments to meet regulatory requirements, to conduct pipeline maintenance and repairs, to mainta in 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 fo r a class location change , hydrostatic testing requirements (i.e., testing the strength of a pipeli ne by filling it with water under pressure as part of integrity assessments), and to a ssure pipeline integrity and safety.204 The number of required blowdowns may increas e as PHMSA publishes new pipeline safety regulations in response to Congressional mandate s. However, other methods such as improved inline inspection technologies are av ailable to help pipeline operator s 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 dete rmine when a pipeline blowdown is necessary, the Administration as a whole shoul d consider policy, processes, and technologies that can minimize the need for blowdowns as part of its larger stra tegy for reducing methane emissions. Reducing unnecessary pipeline blow downs 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 2 014 report added the 2012 inventory, “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2012.” See http://www.epa.gov/climatechange/ghge missions/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 meth ane emissions from the natural gas transmission sector and to inform the nece ssary cost-benefit analysis, EP A should consider the regulatory drivers associated with certain emissions – in cluding pipeline segment blowdowns. In short, pipeline blowdowns are not only an integral part of operations a nd essential for safety, but they are also required by law. Operators must conduc t pipeline blowdowns to perform maintenance, testing, and pipe replacements to ensure sa fe operations. Additionally, the Pipeline and Hazardous Materials Safety Admi nistration (“PHMSA”) requires pi peline blowdowns as part of the replacement process for class location change s (e.g., population increase s in the vicinity of the pipeline above specif ied 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 Admini stration to review exis ting and future pipeline safety regulations as a part of its broader st rategy 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 pi pe replacements causing pipeline blowdowns with unburned methane emissions. Using IMP principles in place of pipe replacement would address safety concerns while reducing the need fo r 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 ag encies, 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 pr oposed rule and are beyond the scope of this205 rulemaking. Therefore, the EPA is not specifi cally responding to th ese comments in this document.