BEFORE 

THE UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

PETITION FOR RULEMAKING AND 

INTERPRETIVE GUIDANCE ENSURING 

COMPREHENSIVE COVERAGE OF METHANE 

SOURCES UNDER SUBPART W OF THE 

GREENHOUSE GAS REPORTING RULE – 

PETROLEUM AND NATURAL GAS SYSTEMS 

Respectfully Submitted by Clean Air Task Force, Environmental Defense Fund, Natural 

Resources Defense Council, and Sierra Club 

March 19, 2013 

Pursuant to 5 U.S.C. § 553(e), Clean Air Task Force, Environmental Defense Fund 

(“EDF”), Natural Resources Defense Council, and Sierra Club petition EPA fulfill its obligations 

under the Clean Air Act to collect greenhouse gas emissions data from several large sources of 

methane in the petroleum and natural gas sector that are currently not included in Subpart W or 

other Subparts of the Mandatory Reporting Rule (“MRR”).1 Specifically, we respectfully 

request that the agency: 

• Clarify that oil wells that co-produce natural gas (“co-producing wells”) located 

in tight-oil formations are required to report emissions from venting and flaring 

associated with well completions; 

• Require reporting of well-completion emissions from any co-producing well 

currently excluded by the Rule’s focus on “gas wells”; 

• Require reporting from facilities and pipelines in the gathering and boosting 

segment of the natural gas industry, and from transmission pipeline blowdown 

events.

Likewise, to promote better understanding of the facilities covered by the 25,000 metric 

ton CO2 equivalent (CO2e) threshold, we ask that EPA require reporters to include API well 

 

1

 This does not represent an exhaustive list of all potential areas for strengthened coverage. 
2 

identification numbers along with their submissions.

2

 Reports from the oil and gas industry for 

2011 methane emissions under Subpart W are at least 51% lower than national estimates from 

EPA, due to a combination of missing source categories (those mentioned above and others) and 

excluded emissions from smaller facilities that are not required to report due to the 25,000 ton 

CO2e threshold.3

 Including API well identification numbers along with facilities’ submissions 

will help the public and policymakers understand which sources are reporting and how the 

threshold may be adjusted to most effectively provide emissions information.4

Finally, regarding the Subpart W data generally, we respectfully reiterate our request to 

phase out the use of best available monitoring methods (“BAMM”), which will further help to 

ensure Subpart W data are rigorous, and comprehensive.5

 We also ask that the agency consider 

including Advanced Innovative Monitoring Methods (“AIMM”) as a way to accelerate 

development and deployment of real-time continuous methane emission monitoring in the oil 

and natural gas sector. 

I. SUBPART W MUST PRODUCE COMPREHENSIVE, HIGH-QUALITY DATA

Emissions data are the foundation of rigorous, effective, and informed air quality 

planning and management. EPA’s MRR declared that “[a]ccurate and timely information on 

GHG emissions is essential for informing some future climate change policy decisions.”6 

Emissions data enables policy-makers to develop, design, and assess policies, and effective 

emissions reporting programs also “raise awareness of emissions among reporters and other 

 

2

 API well numbers are critical addition to well counts because they will allow cross-reference to production data 

and other important information. 

3

 Subpart W reported methane emissions for 2011 were 83 million metric tons CO2e (see: EPA, “Petroleum and 

Natural Gas Systems: 2011 Data Publication” (February 2013), available at: 

http://www.epa.gov/ghgreporting/documents/pdf/2012/documents/subpart_W_2011_data_publication_fact_sheet.pd

f.pdf, at 3). EPA’s draft 2013 edition of their annual US Greenhouse Gas Inventory reports methane emissions from 

natural gas systems and petroleum production as 139.6 and 31.0 million metric tons CO2e, respectively (see: U.S. 

EPA, Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011(Feb. 2013), available at 

http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2011-Chapter-3-Energy.pdf ). 

The 2012 inventory reported even higher emissions from the sector; EPA is proposing to reduce that estimate 

somewhat. By citing the 2013 draft, we do not necessarily endorse its emissions figures; instead, we emphasize that 

both inventory estimates suggest that Subpart W is failing to address a significant amount of emissions. 

4

 We incorporate by reference comments on the Subpart W proposal, in which Petitioners outlined difficulties 

associated with the 25,000 mt CO2e threshold and requested a lower threshold. EPA Doc. No. EPA-HQ-OAR2009-0923-3545 (Comments of Clean Air Task Force, Colorado Environmental Coalition, Environmental Defense 

Fund, Natural Resources Defense Council, Sierra Club, and Wilderness Workshop on Subpart W). 

5

See EPA Doc. No. EPA-HQ-OAR-2011-0417-0013 (Comments of EDF on Subpart W proposed BAMM 

extension). 

6

 74 Fed. Reg. 16,448, 16,455 (Apr. 10, 2009) (emphasis added). 
3 

stakeholders, and thus contribute to efforts to identify reduction opportunities and carry them 

out.”7 

These functions are especially important for sources in the petroleum and natural gas 

sector, which EPA’s latest greenhouse gas inventory recognizes as the largest source of U.S. 

methane emissions, placing this industry among the top greenhouse gas emitters overall. In the 

final Subpart W rule, the agency noted that the data “will inform EPA’s implementation of CAA 

section 103(g) regarding improvements in sector based non-regulatory strategies and 

technologies for preventing or reducing air pollutants, and inform policy on possible regulatory 

actions to address GHG emissions.”8 

EPA echoed the importance of Subpart W data in its recently finalized (though still 

incomplete) New Source Performance Standards for the Oil and Natural Gas Sector: 

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

location and magnitude of GHG emissions from petroleum and natural gas 

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

emissions, compare them to similar facilities and aid in identifying cost effective 

opportunities to reduce emissions in the future . . . . [Through collection of 

Subpart W data] EPA will be in a better position to characterize (1) the extent of 

methane emissions from these sources that will remain after imposition of 

controls required by [the NSPS]; and (2) whether additional measures are 

available and appropriate for addressing such emissions.9

The collection and reporting of additional emissions data from sources not currently required to 

report will help ensure these important clean air benefits occur. 

The Subpart W data will likewise help in understanding top-down emissions inventory 

analyses, which have identified widely varying methane leak rates for the petroleum and natural 

gas sector. These range from slightly under 2 percent [of production]10 to as much as 9 percent 

in a recent NOAA study of the Uintah Basin in Utah.11 Subpart W data will help characterize the 

 

7

Id. at 16,456. 

8

 75 Fed. Reg. 74,458, 74,460 (Nov. 30, 2010). 

9

 77 Fed. Reg. 49,490, 49,513-14 (Aug. 16, 2012). We do not agree with EPA that it lacks the information it needs 

to determine that it is appropriate to regulate methane from the sector, or that controls are available to do so. EPA 

must move forward. Further improving Subpart W will support those required efforts, and should not delay them. 

10 Jeffrey Logan, et al., Natural Gas and the Transformation of the U.S. Energy Sector ES-2 (2012). 

11 A. Karion et al, "Estimate of methane emissions from oil and gas operations in the Uintah Basin using airborne 

measurements and Lidar wind data," Presentation A21J-01, Fall 2012 American Geophysical Union meeting (San 

Francisco, 4 December 2012); see also: A. Karion et al, “Top-down estimation of CH4 emissions from oil and 

natural gas operations in the Denver and Uintah oil and gas Basins,” Presented at Stakeholder Workshop on Natural 
4 

drivers behind these wide-ranging emissions estimates and, in turn, will allow states to calibrate 

additional policy priorities that optimize methane reductions. 

 

Finally, ensuring Subpart W produces rigorous and comprehensive data will help to 

fulfill a recent recommendation from EPA’s Office of Inspector General, which suggested that 

EPA “develop and implement a comprehensive strategy for improving air emissions data for the 

oil and gas production sector.”12 The report notes that EPA considers Subpart W as its main 

GHG emissions data collection strategy from the oil and natural gas industries, but that the 

Subpart W program is not a “coordinated cross-office strategy for improving the collection of all 

types of air emissions data for oil and gas production sources commensurate with recent and 

projected growth in this industry sector.”13 For Subpart W data to function as part of a 

comprehensive strategy for improving oil and gas air emissions data, as the Inspector General 

recommends, the Rule must include reporting requirements for all significant sources of methane 

from the petroleum and natural gas sector. 

Section 114 of the CAA, which is the source of EPA’s authority to promulgate the MRR 

for Title I sources, provides the agency with plenary authority to collect methane emissions 

information from sources in the petroleum and natural gas sector. Moreover, Section 111 of the 

Act creates a duty to review and, if appropriate, revise standards of performance for certain 

source categories, including the oil and natural gas sector. Subpart W can play an important role 

in informing EPA’s obligatory revision of these standards, as EPA has acknowledged. Yet the 

Rule currently omits several potentially significant sources of methane in this sector, yielding an 

incomplete picture of emissions from petroleum and natural gas operations.14 Accordingly, we 

respectfully urge EPA to expand the scope of Subpart W to include data gathering requirements 

for the significant emissions sources we describe below. 

II. GREENHOUSE GAS EMISSIONS FROM OIL AND GAS CO-PRODUCING WELLS

The Subpart W well completion reporting requirements apply only to “gas wells” and not 

to “oil wells.” This distinction creates potential confusion for co-producing oil and gas wells that 

 

Gas in the Inventory of U.S. Greenhouse Gas Emissions and Sinks, Washington DC, 13 Sept. 2012, available at: 

http://www.epa.gov/climatechange/Downloads/ghgemissions/2012Workshop/NOAA_Karion.pdf (describing 

methodology used in the Uintah Basin study); see also: Jeff Tollefson, Methane Leaks Erode Green Credentials of 

Natural Gas, NATURE (Jan. 2, 2013), available at http://www.nature.com/news/methane-leaks-erode-greencredentials-of-natural-gas-1.12123?nc=1359235303992. 

12 US EPA Office of Inspector General, EPA NEEDS TO IMPROVE AIR EMISSIONS DATA FOR THE OIL AND NATURAL 

GAS PRODUCTION SECTOR – REPORT 13-P-0161 (20 February 2013); available at 

http://www.epa.gov/oig/reports/2013/20130220-13-P-0161.pdf. 

13 Id. at 12. 

14 Notwithstanding these omissions, the agency possesses sufficient information to determine that methane 

performance standards for the oil and natural gas sector are appropriate and has a duty to make such a determination. 
5 

fall within the Rule’s definition of “gas well,” while excluding emissions from co-producing 

wells the Rule classifies as “oil wells.” Regardless of their classification, completion emissions 

from these co-producing wells can be significant. Accordingly, we respectfully request that EPA 

clarify that wells in tight-oil formations like the Bakken and Eagle Ford are subject to the 

completion reporting requirements as currently written. In addition, we urge the agency to 

expand the well completion reporting requirements to all wells, ensuring co-producing wells in 

any formation type are required to report completion emissions. 

A. Subpart W Must Address Greenhouse Gas Emissions from Co-producing Wells

EPA’s Subpart W regulations require onshore production facilities to report greenhouse 

gas emissions from certain processes. Because of gaps or ambiguities within the rule, reporters 

are not fully reporting emissions from all oil and gas wells. Specifically, Subpart W requires 

reporting of completion emissions from “gas wells” but does not specifically require such 

reporting from oil wells. It provides: 

“(c) For an onshore petroleum and natural gas production facility, report 

CO2, CH4 , and N2O emissions from only the following source types on a single 

well-pad or associated with a single well-pad: . . . 

 

(6) Gas well venting during well completions with hydraulic fracturing 

 

(8) Gas well venting during well workovers with hydraulic fracturing”15

There is no similar reporting requirement to report oil well venting greenhouse gas emissions 

during well completions or workovers with hydraulic fracturing. 

Although Subpart W defines some oil-producing wells within its broad definition of “gas well,” 

certain oil wells are likely not covered, creating potential confusion for reporters. Subpart W 

includes definitions for both “gas wells” and “oil wells.” “Gas wells” are defined to include 

“[w]ells that produce from high permeability gas, shale gas, coal seam, or other tight reservoir 

rock . . . .”16 Importantly, this definition does not specify that gas wells must produce a 

particular type of hydrocarbon, instead requiring only that such wells “produce” from certain 

reservoir formations. Conversely, an “oil well” is a well that produces “hydrocarbon liquids and 

do[es] not meet the definition of a gas well.”17 

 

15 40 C.F.R. § 98.232(C)(6), (8) (emphasis added); see also 75 Fed. Reg. 74,458, 74,463 (Nov. 30, 2010). 

16 40 C.F.R. § 98.238. 

17

 Id. 
6 

Certain co-producing wells, like those in the Bakken and Eagle Ford formations, are 

located in tight-oil formations. These wells “produce” from “other tight reservoir rock” and 

therefore fall within the Rule’s requirements to report gas well venting during well completions 

and workovers with hydraulic fracturing. Notwithstanding this requirement, there are very few 

facility reports from wells in these basins, leading us to infer that the owners or operators of 

these wells may not believe they are subject to Subpart W reporting. Accordingly, we 

respectfully request that EPA undertake rulemaking or issue guidance, as appropriate, to clarify 

that co-producing wells in tight-oil formations are required to report well completion emissions 

under Subpart W and to provide any necessary emission equations. 

To the extent other co-producing wells fall outside of the current Subpart W definition of 

“gas well,” we respectfully petition EPA to undertake a rulemaking to ensure that the Rule 

covers all of these significant emissions. Subpart W covers other emissions from oil wells, and 

this expansion will help ensure complete coverage. In particular, Subpart W’s requirement to 

report emissions from associated venting and flaring already applies to all wells, recognizing that 

oil wells can vent significant amounts of natural gas during ongoing production activities.18

Similarly, the completion reporting requirements should cover all wells, ensuring the Rule 

addresses these important emissions. 

B. Methane Emissions from Co-producing Wells can be Significant

Ensuring Subpart W addresses emissions from co-producing wells is critical because 

drilling in co-producing basins is rapidly expanding and, both individually and collectively, these 

wells account for significant amounts of methane emissions. 

Rapidly shifting market fundamentals have sparked swift development of co-producing 

wells. The relatively high price of oil and natural gas liquids has made these co-producing wells 

attractive investments and has shifted development away from areas that principally produce dry 

gas. Indeed, Shell has planned a $1 billion investment to target liquids-rich plays like the Eagle 

Ford,19 which Marathon Oil Chief Operating Officer David Roberts described as “the top basin 

we have in the world today.”20 

Overall rig deployment and oil and gas production numbers reflect this shift: from 

February 2011 to February 2012, rigs increased 61% in the oil and liquids-rich Eagle Ford and 

23% in the Bakken, while during the same period dry-gas plays experienced significant declines, 

 

18 See 40 C.F.R. §§ 98.232(c)(13) & 98.233(m). 

19

 Shell to Focus on Liquids-Rich Assets, Leverage Gas, NGI’S SHALE DAILY, (Feb. 6, 2012). 

20 Texas Top Finds From Brazil to Bakken as Best Prospect: Energy, BLOOMBERG (Mar. 23, 201), 

http://www.bloomberg.com/news/2012-03-23/texas-tops-finds-from-brazil-to-bakken-as-best-prospect-energy.html. 
7 

including a 43% reduction in rigs in the Haynesville shale.21 Moreover, this shift will likely 

persist far into the future -- over the next 20 years, some industry executives predict that Bakken 

production will increase from the approximately 5,000 existing wells to a projected 48,000.22 

Similarly, in 2010 there were 293 active wells in the Eagle Ford and industry projects that by 

2020, 4,890 new wells will be drilled.23

 

 

 Methane emissions from these wells can be significant. EPA recently issued a proposed 

and final Federal Implementation Plan for oil and gas wells on the Fort Berthold Indian 

Reservation (“FBIR FIP”), requiring pollution control measures at co-producing wells.24 As 

EPA recognized in the FBIR FIP, oil from certain unconventional oil, such as the Bakken and the 

Eagle Ford, contain relatively high amounts of lighter, more volatile hydrocarbons.25 In these 

lighter-hydrocarbon oil fields, the agency noted that the process associated with producing light 

crude oil “has greater potential to produce natural gas in addition to oil,” and explicitly 

characterized the oil production methods on the FBIR as “similar to natural gas well production” 

involving “the separation of the produced liquid into hydrocarbon liquids (oil), natural gas and 

water.”26 

EPA’s analysis of 154 synthetic minor permits27 from the FBIR found that uncontrolled 

production emissions (including both well completion emissions and ongoing production 

 

21 Unconventional Rig Count for the Week Ending February 10, 2012, NGI’S SHALE DAILY (on file with author). 

22 Clifford Krauss, In North Dakota, Flames of Wasted Natural Gas Light the Prairie, N.Y. TIMES (Sept. 26, 2011), 

available at September 26, 2011, http://www.nytimes.com/2011/09/27/business/energy-environment/in-northdakota-wasted-natural-gas-flickers-against-the-sky.html?_r=1&ref=energy-environment. 

23

 Economic Impact of the Eagle Ford Shale, AMERICA’S NATURAL GAS ALLIANCE (Feb. 2011), 

http://www.anga.us/media/195472/utsa%20eagle%20ford.pdf at 8, 21. 

24 See EPA, Approval and Promulgation of Federal Implementation Plan for Oil and Natural Gas Well Production 

Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa, and Arikara Nations), 77 Fed. Reg. 48,878, 48,885 

(August 15, 2012) [hereinafter “FBIR FIP”] (defining applicable facility as “oil and natural gas production

facilit[ies] producing from the Bakken Pool and located on the FBIR”) (emphasis added). 

25 Id. at 48,883. 

26 Id. 

27 In the Technical Support Document for the FBIR FIP, EPA describes the full scope of its analysis: 

We evaluated data from 154 synthetic minor permit applications containing 533 production wells among 

five of the main operators on the FBIR. From the applications, we were able to obtain the uncontrolled and 

controlled VOC emissions for each of the 154 facilities. Additionally, the data was analyzed to determine 

average emission rates for an individual well basis. Due to the variability in the production rates and 

product composition among the operators, we believe the mean value per well is an appropriate method for 

obtaining annual emissions. Average VOC emissions per well were evaluated against operating scenarios 

to determine cost impacts associated with the FIP. 

EPA, TECHNICAL SUPPORT DOCUMENT: FEDERAL IMPLEMENTATION PLAN FOR OIL AND NATURAL GAS WELL 

PRODUCTION FACILITIES; FORT BERTHOLD INDIAN RESERVATION (MANDAN, HIDATSA, AND ARIKARA NATIONS),

NORTH DAKOTA 17 [hereinafter “FBIR FIP TSD”]. 
8 

emissions) from FBIR wells are approximately 1,610 tons of VOCs per year per well.28 

Though the agency did not report methane emissions from these wells, applying EPA’s 

conversion factors in the Subpart W Technical Support Document (TSD) to these wells yields a 

value of 1,922 tpy of methane.29 EDF obtained a separate analysis from Stratus Consulting 

supporting the FBIR FIP’s conclusions with respect to co-production VOC and methane 

emissions.30 Further, if associated gas is flared during well completion, the carbon dioxide 

emissions from the flares will also be significant and must be addressed by Subpart W. These 

analyses confirm that greenhouse gas emissions from co-producing wells can be significant and 

must be included in Subpart W. 

III. GREENHOUSE GAS EMISSIONS FROM FACILITIES AND PIPELINES IN THE GATHERING 

AND BOOSTING SEGMENTS OF THE NATURAL GAS INDUSTRY AND GAPS IN REPORTING 

REQUIREMENTS FOR TRANSMISSION PIPELINES

The natural gas sector extends well beyond the wellhead – after production, natural gas is 

transported through gathering lines, processed to remove impurities, compressed, and transmitted 

at high pressures to storage facilities and/or distributors nationwide. 

EPA explicitly excluded gathering lines and boosting stations from coverage under both 

the natural gas processing segment and the natural gas transmission compression segment, 

stating that it “require[d] further analysis to ensure an effective coverage of emissions from this 

source in order to appropriately inform future policy decisions.”31 In addition to the pipelines 

and compressors explicitly excluded, emissions from many types of ancillary equipment in the 

gathering and boosting segments of the natural gas industry, such as pneumatic devices and 

pumps, dehydrators, and storage tanks are also excluded from Subpart W. Important methane 

sources in the transmission segment of the natural gas industry, such as transmission venting 

(“blowdowns”) and leaks, are also not covered. 

The exclusion of gathering and boosting facilities means that Subpart W does not require 

the natural gas sector to report a significant volume of emissions. The Pipeline and Hazardous 

Materials Safety Administration has estimated that there are approximately 230,000 miles of gas 

 

28 Id. at 18. EPA calculated controlled produced natural gas heater/treater emissions based on 90% destruction 

efficiency for 90 days and 98% destruction efficiency for the remaining 9 months of the year. 

29 EPA, OIL AND NATURAL GAS SECTOR: STANDARDS OF PERFORMANCE FOR CRUDE OIL AND NATURAL GAS 

PRODUCTION, TRANSMISSION, AND DISTRIBUTION: BACKGROUND TECHNICAL SUPPORT DOCUMENT FOR PROPOSED 

STANDARDS TECHNICAL SUPPORT DOCUMENT at Table 4-2 (July 2011) [hereinafter “Subpart W TSD”]. The TSD 

assumes 0.1459 lb VOC /lb methane for natural gas wells and 0.8374 lb VOC/lb methane for oil wells. The 

conversion in the text assume the oil factor applies. 

30 See EPA Doc. No. EPA-HQ-OAR-2010-0505-4490. We hereby incorporate this analysis by reference. 

31 75 Fed. Reg. 74,458, 74,462 (Nov. 30, 2010) (“This source category does not include reporting of emissions from 

gathering lines and boosting stations”). 
9 

gathering lines in the United States,32 and EPA’s draft 2013 Inventory of US GHG Sources and 

Sink (“US GHG Inventory”) reports that there are over 430,000 miles of such lines in service.33 

That inventory reports that leaks from gathering pipelines constitute slightly more than 2.5% 

percent of the total GHG emissions from the natural gas industry.34 Boosting compressors in 

gathering and boosting systems and their associated equipment are also significant sources of 

methane emissions.35 Failing to include leaks from gathering lines and emissions associated with 

boosting stations can therefore result in substantially underreporting the emissions from the oil 

and gas sector. 

 Additionally, in its current form, Subpart W does not include emissions from 

transmission pipeline venting (i.e., blowdowns) and leaks outside the boundaries of transmission 

compressor stations. Subpart W covers only venting and fugitives from compressor stations 

even though EPA’s draft 2013 Inventory reports that pipeline venting alone accounts for 

approximately 2% of the entire petroleum and natural gas GHG inventory and over 6% of 

emissions from the transmission and storage segment. Indeed, the Subpart W TSD indicates that 

pipeline venting is among the largest sources of methane emissions from the transmission 

segment, rivaling in scale several other categories of emissions (such as combustion emissions 

from compressors and fugitive emissions from centrifugal compressors) for which reporting is 

currently required.36 Further, pipeline operators are or should be able to track intentional 

blowdown events, and can readily estimate emissions for each such event based on the 

dimensions of the evacuated pipe. Accordingly, Petitioners believe it is both desirable and 

eminently feasible to require reporting of these emissions.37

Furthermore, Petitioners note that large leaks and ruptures are reported to PHMSA. A 

recent PHMSA-commissioned study indicates that the volume of natural gas released through 

 

32 Pipeline Safety: Safety of Gas Transmission Pipelines, 76 Fed. Reg. 53086, 53,101 (ANPRM, Aug. 25, 2011). 

33 EPA, Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011 at A-176-81 (Feb. 2013),

available at http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html. 

34 EPA, Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011 at A-188 (Feb. 2013), available 

at http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html. 

35 See, e.g., DAVID ALLEN ET. AL., NATURAL GAS INDUSTRY METHANE EMISSION FACTOR IMPROVEMENT STUDY 37 

(Dec. 2011), available at http://www.utexas.edu/research/ceer/GHG/files/FReports/XA_83376101_ 

Final_Report.pdf. 

36 Subpart W TSD, supra note 17, at 75 (pipeline venting equivalent to approximately 3.8 million metric tons CO2-e 

per year). 

37 As the Subpart W TSD indicates, defining a “facility” in the context of transmission pipeline segments may pose 

technical challenges. Id. at 18. However, EPA overcame similar challenges for the distribution segment by 

requiring corporate-level reporting and referencing relevant definitions applied by the Pipeline and Hazardous 

Materials Safety Administration (PHMSA). See id. at 105. A similar approach may be available for transmission 

pipelines, which PHMSA also regulates. Indeed, EPA noted that company-level reporting based on PHMSA 

requirements would be a feasible approach for gathering pipelines, which present definitional challenges similar to 

transmission pipelines. See id. at 18, 108. 
10 

large leaks and ruptures along transmission pipelines is approximately 1.9 billion standard cubic 

feet per year – nearly 11.5 times the level indicated in the Subpart W TSD.38 Indeed, accidental 

leaks of large magnitude can be a major source of methane leaking into the atmosphere, even if 

relatively short in duration. Emissions can be very high for leaks in remote locations that are not 

noticed or repaired immediately. 

To ensure that Subpart W robustly reports all major sources of emissions from the oil and 

gas sector, Petitioners respectfully request that EPA amend the language of 40 C.F.R. § 98.230 to 

explicitly include gathering lines, boosting stations, and pipeline venting and blowdowns. In 

addition, Petitioners recommend that EPA coordinate with PHMSA to ensure that the annual 

GHG inventory includes, at a minimum, those pipeline leaks and ruptures that are reported to 

Federal regulators, and to seek synergies, as appropriate, in data collection requirements. 

IV.BEST AVAILABLE MONITORING METHODS

 Facilities initially qualifying for alternative reporting under the best available monitoring 

methods (“BAMM”) provision of Subpart W have had ample time to transition to the methods 

otherwise required under Subpart W. Petitioners thus respectfully urge EPA to eliminate BAMM 

as it currently exists after calendar year 2013. Furthermore, because real-time continuous 

emissions monitoring technologies are rapidly evolving, we ask EPA to provide opportunities in 

Subpart W for use of “advanced innovative monitoring methods.” 

When EPA finalized Subpart W in November of 2010, the agency included certain nonstandardized procedures that oil and gas operators could use while coming into full compliance 

with the rule. 39 The agency limited these methods, known as BAMM, to situations in which 

regulated facilities were unable to install the proper monitoring equipment and allowed facilities 

to use BAMM until June 30, 2011. Facilities requesting BAMM past that date were required to 

submit a written petition to EPA requesting an extension,40 and no facility could request an 

extension beyond December 31, 2011 except “under extreme and unique circumstances, which 

include safety, or a requirement being technically infeasible or counter to other local, State or 

Federal regulations.”41 The only facilities authorized to utilize BAMM were gas well workovers 

 

38 See David Shaw, Martin Phillips, Ron Baker, Eduardo Munoz, Hamood Rehman, Carol Gibson, Christine 

Mayernik, Final Report: Leak Detection Study -- DTPH56-11-D-000001 at 3-27, PIPELINE AND HAZARDOUS 

MATERIALS SAFETY ADMINISTRATION (Dec. 10, 2012) (multiplying average release volume by total number of 

onshore leak and rupture incidents, and adjusting for 12-month time period), available at 

http://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=430; compare Subpart W TSD, supra note 17, at 75 

(estimating 166 million standard cubic feet per year in pipeline fugitive emissions). 

39 75 Fed. Reg. 74,458, 74,471 (Nov. 30, 2010). 

40 Id.

41 Id.
11 

using hydraulic fracture, gas well completions using hydraulic fracture, and well testing and 

flaring.42

 In response to a petition for reconsideration, on June 27, 2011, EPA published a 

proposed revision to Subpart W, proposing three key changes to the original BAMM rules. First, 

it would allow a presumptive extension of BAMM reporting techniques through December 31, 

2011.43 Second, it would extend the sources eligible to use BAMM to include the entire oil and 

gas sector (by adding Leak Detection and Measurement and “all other sources not previously 

listed”).44 Finally, the agency would replace the original Rule’s ban on extending the use of 

BAMM beyond 2011 except under “extreme and unique circumstances” with a provision 

allowing an extension under “unique or unusual circumstances such as data collection methods 

that do not meet safety, technical, or legal issues rendering them unable to meet the requirements 

of Subpart W.”45 EPA finalized the proposed rule, including all three changes, on September 27, 

2011.46 

 Expanding the BAMM provisions in this way transformed the program from a limited, 

transitional bridge to full compliance into a permanent fixture of the MRR. Facility level 

BAMM reports now available demonstrate that approximately 70 percent of facilities are 

currently using BAMM, further indicating that BAMM has far outgrown its remedial intent. 

EPA has recently proposed revisions to the BAMM provisions for Subpart W47 that would create 

earlier deadlines for submitting BAMM requests but otherwise leaving the program unchanged. 

While this Rule will allow EPA to more closely evaluate and scrutinize the BAMM requests it is 

receiving, it does not provide a pathway for transitioning away from the program. Accordingly, 

these potentially permanent BAMM provisions threaten to undermine the quality of data the 

MRR produces, making it difficult to determine whether differences among sources are due to 

different reporting methodologies or actual differences in emissions. This is especially 

challenging for Subpart W sources, where emissions are highly variable across sources due to 

technology and operator practices. 

Facilities have been able to use BAMM for the first two years of reporting (2011 and 

2012), and they have had ample time to transition to the methods required under Subpart W. As 

such, EPA should eliminate the use of BAMM as it currently exists after calendar year 2013. As 

part of the notice-and-comment process on that action, stakeholders will have the opportunity to 

 

42 Id.

43 76 Fed. Reg. 37,300, 37,303 (June 27, 2011). 

44 Id. at 37,304. 

45 Id.

46 76 Fed. Reg. 59,533, 59,536-38 (Sept. 27, 2011). 

47 78 Fed. Reg. 11,619 (Feb. 19, 2013). 
12 

identify any remaining areas where different measurement methodologies might be required. In 

the narrow circumstances in which operators may require flexible measurement methodologies 

on account of worker safety, we ask the agency to explicitly incorporate these flexibilities 

through rulemaking instead of through ongoing BAMM requests. Moreover, to ensure full 

transparency for the public and policymakers, we request that the agency provide information on 

every facility that has requested BAMM in 2011 and/or 2012, the data elements for which they 

have made the request, and the agency’s response to the BAMM request. We also ask the 

Agency to provide this type of information on the use of BAMM in 2013 and any subsequent 

years. 

 

Finally, real-time continuous emissions monitoring technologies are rapidly evolving in 

the oil and natural gas sector as well as in many other industrial applications. To encourage 

facilities to deploy these innovative technologies, we recommend that EPA provide opportunities 

for use of “advanced innovative monitoring methods (AIMM).” As such, we recommend that 

EPA add a new provision to the MRR providing a mechanism under which the Agency will 

consider requests which rely on real-time continuous monitoring techniques that the Agency 

determines are more accurate than those ordinarily required by EPA procedure. By doing so, 

AIMM can serve as a laboratory for innovation, allowing the agency to gain experience with 

modern measurement methodologies while laying the groundwork for continuous improvement 

in monitoring methods over time. Petitioners expect that this approach will be useful both in the 

oil and natural gas sector, and in other sectors of the MRR. 

 

 Respectfully submitted, 

Craig Segall 

Sierra Club

50 F St NW, Eighth Floor 

Washington, DC, 20009 

Craig.Segall@sierraclub.org 

Meleah Geertsma 

Natural Resources Defense Council 

2 N. Riverside Plaza, Suite 2250 

Chicago, IL 60606 

mgeerstma@nrdc.org 

/s/ Peter Zalzal________________ 

Peter Zalzal 

Tomás Carbonell 

Environmental Defense Fund 

2060 Broadway, Suite 300 

Boulder, CO 80302 

pzalzal@edf.org 

tcarbonell@edf.org 

David McCabe 

Darin Schroeder 

Clean Air Task Force

18 Tremont Street, Suite 530, 

Boston, MA 02108 

(617) 624-0234 

dmccabe@catf.us 

dschroeder@catf.us