# Waste Prevention, Production Subject to Royalties, and Resource Conservation

> Briefs, arguments, decisions, and more.

URL: https://www.frixlaw.com/law-library/documents/fr%3A2016-01865

## Record

- **Collection:** Federal Register
- **Document type:** Proposed Rule
- **Published:** February 8, 2016
- **Citation:** 81 FR 6616

## Text

DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3100, 3160, and 3170
[15X.LLWO300000.L13100000.NB0000]
RIN 1004-AE14
Waste Prevention, Production Subject to Royalties, and Resource Conservation

AGENCY:

Bureau of Land Management, Interior.

ACTION:

Proposed rule.

SUMMARY:

The Bureau of Land Management (BLM) is proposing new regulations to reduce waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on onshore Federal and Indian leases. The regulations would also clarify when produced gas lost through venting, flaring, or leaks is subject to royalties, and when oil and gas production used on site would be royalty-free. These proposed regulations would be codified at new 43 CFR subparts 3178 and 3179. They would replace the existing provisions related to venting, flaring, and royalty-free use of gas contained in the 1979 Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases, Royalty or Compensation for Oil and Gas Lost (NTL-4A), which are over 3 decades old.

DATES:

Send your comments on this proposed rule to the BLM on or before April 8, 2016. The BLM is not obligated to consider any comments received after this date in making its decision on the final rule.

As explained later, the proposed rule would establish new information collection requirements that must be approved by the Office of Management and Budget (OMB). If you wish to comment on the information collection requirements in this proposed rule, please note that the OMB is required to make a decision concerning the collection of information contained in this proposed rule between 30 and 60 days after publication of this document in the
Federal Register
. Therefore, a comment to the OMB on the proposed information collection requirements is best assured of having its full effect if the OMB receives it by March 9, 2016.

ADDRESSES:

Mail:
U.S. Department of the Interior, Director (630), Bureau of Land Management, Mail Stop 2134 LM, 1849 C St. NW., Washington, DC 20240, Attention: 1004-AE14.
Personal or messenger delivery:
20 M Street SE., Room 2134LM, Washington, DC 20003.
Federal eRulemaking Portal: http://www.regulations.gov.
Follow the instructions at this Web site.

Comments on the information collection burdens:
Fax:
Office of Management and Budget (OMB), Office of Information and Regulatory Affairs, Desk Officer for the Department of the Interior, fax 202-395-5806.
Electronic mail: OIRA_Submission@omb.eop.gov.
Please indicate “Attention: OMB Control Number 1004-XXXX,” regardless of the method used to submit comments on the information collection burdens. If you submit comments on the information collection burdens, you should provide the BLM with a copy, at one of the addresses shown earlier in this section, so that we can summarize all written comments and address them in the final rule preamble.

FOR FURTHER INFORMATION CONTACT:

Eric Jones at the BLM Moab Field Office, 82 East Dogwood Ave., Moab, UT 84532, or by telephone at 435-259-2117; or Timothy Spisak at the BLM Washington Office, 20 M Street SE., Room 2134LM, Washington, DC 20003, or by telephone at 202-912-7311. For questions relating to regulatory process issues, contact Faith Bremner at 202-912-7441.

Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 to contact these individuals during normal business hours. FIRS is available 24 hours a day, 7 days a week to leave a message or question with these individuals. You will receive a reply during normal business hours.

SUPPLEMENTARY INFORMATION:

I. Executive Summary

A. Background

This proposed regulation aims to reduce the waste of natural gas from mineral leases administered by the BLM. This gas is lost during oil and gas production activities through flaring or venting of the gas, and equipment leaks. While oil and gas production technology has advanced dramatically in recent years, the BLM's requirements to minimize waste of gas have not been updated in over 30 years. The Mineral Leasing Act of 1920 (MLA) requires the BLM to ensure that lessees “use all reasonable precautions to prevent waste of oil or gas developed in theland . . . .” 30 U.S.C. 225. The BLM believes there are economical, cost-effective, and reasonable measures that operators should take to minimize waste, which will enhance our nation's natural gas supplies, boost royalty receipts for American taxpayers, tribes, and States, and reduce environmental damage from venting and flaring.

The BLM's onshore oil and gas management program is a major contributor to our nation's oil and gas production. The BLM manages more than 245 million acres of land and 700 million acres of subsurface estate, making up nearly a third of the nation's mineral estate. Domestic production from over 100,000 Federal onshore oil and gas wells accounts for 11 percent of the Nation's natural gas supply and 5 percent of its oil. In Fiscal Year (FY) 2014, operators produced 204.6 million barrels (bbl) of oil, 2 trillion cubic feet (Tcf) of natural gas, and 3.1 billion gallons of natural gas liquids (NGLs) from onshore Federal and Indian oil and gas leases. The production value of this oil and gas exceeded $27.2 billion and generated approximately $3.1 billion in royalties.
1

1
Office of Natural Resources Revenue (ONRR), Statistical Information,
http://statistics.onrr.gov/ReportTool.aspx
using Sales Year—FY2014—Federal Onshore—All States Sales Value and Revenue for Oil, NGL, and Gas products as of December 2, 2015.

Over the past decade, the United States has experienced a dramatic increase in oil and natural gas production due to technological advances, such as hydraulic fracturing combined with directional and/or horizontal drilling. This boost in production has brought many benefits in the form of expanded and more secure domestic oil and gas supplies, lower oil and gas prices, increased economic activity, and greater royalty revenues for Federal, State and tribal governments. At the same time, the American public has not benefited from the full potential of this increased production, due to the flaring, venting, and leakage of significant quantities of gas during the production process. According to data reported to the Office of Natural Resources Revenue (ONRR), Federal and Indian onshore lessees and operators lost 375 billion cubic feet (Bcf) of natural gas between 2009 and 2014—enough gas to serve about 5.1 million households for a year, assuming 2009 usage levels.
2

2
The Energy Information Administration (EIA),
Trends in U.S. Residential Natural Gas Consumption, http://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2010/ngtrendsresidcon/ngtrendsresidcon.pdf
(reporting that in 2009, U.S. residential consumption was approximately 74 Mcf per household with natural gas service).

Flaring, venting, and leaks waste a valuable resource that could be put to productive use, and deprive American taxpayers, tribes, and States of royalty revenues. In addition, the wasted gas may harm local communities and

surrounding areas through visual and noise impacts from flaring, and regional and global air pollution problems of smog, particulate matter, toxic air pollution (such as benzene, a carcinogen) and climate change. The primary constituent of natural gas is methane, and increases in gas wasted through venting, flaring or leaks contribute to increases in atmospheric methane levels. Methane is an especially powerful greenhouse gas (GHG), with climate impacts roughly 25 times those of CO
2
, if measured over a 100-year period, or 86 times those of CO
2
, if measured over a 20-year period.
3

Thus, measures to conserve gas and avoid waste may significantly benefit local communities, public health, and the environment.

3
See Intergovernmental Panel on Climate Change, Climate Change 2013: The Physical Science Basis, Chapter 8,
Anthropogenic and Natural Radiative Forcing,
at 714 (Table 8.7),
available at https://www.ipcc.ch/pdf/assessment-report/ar5/wg1/WG1AR5_Chapter08_FINAL.pdf.

The BLM oversees oil and gas activities under the authority of a variety of laws, including the MLA, the Mineral Leasing Act for Acquired Lands of 1947 (MLAAL), the Federal Oil and Gas Royalty Management Act (FOGRMA), the Federal Land Policy and Management Act of 1976 (FLPMA), the Indian Mineral Leasing Act of 1938 (IMLA), the Indian Mineral Development Act of 1982 (IMDA), and the Act of March 3, 1909.
4

In particular, the MLA requires the BLM to ensure that lessees “use all reasonable precautions to prevent waste of oil or gas developed in the land . . . .”
5

This proposal would replace current requirements related to flaring, venting, and royalty-free use of production, which are contained in NTL-4A; amend the BLM's oil and gas regulations at 43 CFR part 3160; and add new subparts 3178 and 3179. It would apply to all Federal and Indian (other than Osage Tribe) onshore oil and gas leases as well as leases and business agreements entered into by tribes (including IMDA agreements), as consistent with those agreements and with principles of Federal Indian law.
6

4
Mineral Leasing Act, 30 U.S.C. 188-287; Mineral Leasing Act for Acquired Lands, 30 U.S.C. 351-360; Federal Oil and Gas Royalty Management Act, 30 U.S.C. 1701-1758; Federal Land Policy and Management Act of 1976, 43 U.S.C. 1701-1785; Indian Mineral Leasing Act of 1938, 25 U.S.C. 396a-g; Indian Mineral Development Act of 1982, 25 U.S.C. 2101-2108; Act of March 3, 1909, 25 U.S.C. 396.

5
30 U.S.C. 225.

6
Key statutes underpinning this proposed regulation contain exceptions for the Osage Tribe. Specifically, the Osage Tribe is excepted from the application of both the Indian Mineral Leasing Act and the Federal Oil and Gas Royalty Management Act, 25 U.S.C. 396f; 43 U.S.C. 1702(3), 1702(4). The leasing of Osage Reservation lands for oil and gas mining is subject to special Bureau of Indian Affairs regulations contained in 43 CFR part 226.

Several oversight reviews, including reviews by the Inspector General of the Department of the Interior and the Government Accountability Office (GAO), have raised concerns about waste of gas, found that the BLM's existing requirements regarding venting and flaring are insufficient, expressed concerns about the “lack of price flexibility in royalty rates,”
7

and identified concerns about royalty-free use of gas. These reports recommended that the BLM update its regulations to address waste prevention, afford flexibility in rate setting, and clarify policies regarding royalty-free, on-site use of oil and gas. With respect to waste, the GAO found that “around 40 percent of natural gas estimated to be vented and flared on onshore Federal leases could be economically captured with currently available control technologies.”
8

The GAO recommended that the BLM reduce venting and flaring of gas by revising its regulations “to make it clear that technologies should be used where they can economically capture sources of vented and flared gas, including gas from liquid unloading, well completions, pneumatic valves, and glycol dehydrators.”
9

The GAO further recommended that the BLM consider expanded use of infrared cameras to identify opportunities to minimize lost gas.
10

7
GAO, Oil and Gas Royalties: The Federal System for Collecting Oil and Gas Revenues Needs Comprehensive Reassessment, GAO-08-691, September 2008, 6.

8
GAO, Federal Oil and Gas Leases: Opportunities Exist to Capture Vented and Flared Natural Gas, Which Would Increase Royalty Payments and Reduce Greenhouse Gases, GAO-11-34, (Oct. 2010), 2.

9
Ibid. at 34.

10
Ibid. at 34.

This proposed rule would align the BLM's royalty rate for new competitive Federal oil and gas leases with the regime envisioned by the MLA, which specifies “a rate of
not less than
12.5 percent in amount or value of the production removed or sold from the lease.”
11

In addition, the proposed rule would update the BLM's existing NTL-4A requirements related to venting, flaring, and royalty-free use of natural gas from onshore Federal and Indian leases. Under NTL-4A, operators must apply to the BLM on a case-by-case basis for approval to flare royalty-free, based on economic criteria. We propose to reduce the need for case-by-case applications by clarifying when flared or vented natural gas is subject to royalties. Further, with respect to venting and flaring of natural gas, we propose to: Prohibit venting, except in certain limited circumstances; limit the rate of routine flaring at development oil wells;
12

require operators to detect and repair leaks; and mandate reductions in venting from: Pneumatic controllers and pneumatic pumps that operate by releasing natural gas; storage vessels; activities to unload liquids from a well; and well drilling, completion, and testing activities. Finally, the proposed rule would require operators to submit gas capture plans with their Applications for Permits to Drill new wells.

11
30 U.S.C. 226(b)(1)(A) (emphasis added);
see also
30 U.S.C. 352 (applying the MLA's leasing provisions to leases on acquired land).

12
“
Development oil well”
or “
development gas well”
means a well drilled to produce oil or gas, respectively, from an established field in which hydrocarbons have been discovered and from which they are being produced at a profit or expected profit.

The BLM has engaged in substantial stakeholder outreach in the course of developing this proposal. In 2014, the BLM conducted a series of forums to consult with tribal governments and solicit stakeholder views to inform the development of this proposed rule, with public meetings (some of which were livestreamed) in Colorado, New Mexico, North Dakota, and Washington, DC.
13

For each forum, we held a tribal outreach session in the morning and a public outreach session in the afternoon. We also accepted informal comments generated as a result of the public/tribal outreach sessions. Since those meetings, we have continued to consult with stakeholders throughout the rule development process, including numerous meetings and calls with State representatives, individual companies, trade associations, and non-governmental organizations (NGOs). We have also received and considered many reports, peer-reviewed studies, and letters from stakeholders providing information and views on what the BLM should propose.

13
Further information can be found at the BLM oil and gas program's outreach-events page:
http://www.blm.gov/wo/st/en/prog/energy/public_events_on_oil.html.

The BLM conducted additional outreach with States where there is extensive oil and gas production from BLM-administered leases. We have carefully reviewed State regulations and guidance and consulted with State regulatory bodies that oversee aspects of oil and gas production to discuss their requirements and practices. The BLM intends to continue close interaction with State and tribal regulators.

The BLM is not the only entity to recognize the need to reduce flaring and

venting from oil and gas production activities. Domestically, the Environmental Protection Agency (EPA) and a few individual States have been active in this area, as have some oil and gas producers. In 2012, for example, the EPA adopted Clean Air Act new source performance standards (NSPS) for certain activities in the oil and gas production sector. These regulations target reductions of volatile organic compounds (VOCs) and have the effect of reducing venting and leaks. The EPA recently proposed regulations to amend the 2012 NSPS for the oil and natural gas source category by setting standards for both methane and VOCs for certain equipment, processes and activities across this source category (40 CFR part 60 subpart OOOOa rulemaking).
14

This EPA proposal would have the effect of further reducing gas losses through venting and leaks.

14
EPA, Oil and Natural Gas Sector: Emission Standards for New and Modified Sources, Proposed Rule, 80 FR 56593 (Sept. 18, 2015). For further information about EPA's existing and proposed NSPS standards for this source category, see Section IV.I.3 of this preamble below.

In addition, several States with BLM-administered lands and mineral interests have acted in this area. Colorado has adopted comprehensive statewide regulations to limit emissions of VOCs from venting and leaks from oil and gas production activities.
15

The Colorado regulations require operators to implement leak detection and repair (LDAR) programs, replace high-bleed pneumatic controllers with low-bleed pneumatic controllers, and control emissions from storage vessels, among other things. Wyoming has adopted similar comprehensive regulations that apply in the Upper Green River Basin, a “nonattainment area” where air quality does not meet national ozone standards adopted by the EPA under the Clean Air Act.
16

North Dakota has also adopted an innovative program to phase down flaring by operators across the State, requiring 91 percent gas capture by 2020.
17

Pennsylvania has issued guidance that exempts oil and gas facilities from certain air quality permitting requirements if they implement changes to reduce gas loss, such as developing an LDAR program, reducing VOC emissions from storage vessels, and limiting flaring activity.
18

15
Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Sections XII, XVII, XVIII,
available at https://www.colorado.gov/pacific/sites/default/files/5-CCR-1001-9_0.pdf.

16
Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015),
available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

17
North Dakota Industrial Commission Order 24665 Policy Guidance Version 102215,
available at https://www.dmr.nd.gov/oilgas/GuidancePolicyNorthDakotaIndustrialCommissionorder24665.pdf.

18
Pennsylvania Department of Environmental Protection, Air Quality Permit Exemptions (Aug. 10, 2013),
available at http://www.elibrary.dep.state.pa.us/dsweb/Get/Document-96215/275-2101-003.pdf,
at 8-11.

The oil and gas industry has also taken voluntary actions to reduce flaring and venting. Many of these efforts have been initiated by companies participating in Natural Gas STAR, a voluntary EPA-industry partnership program that encourages oil and natural gas companies to adopt cost-effective technologies and practices that improve operational efficiency and reduce methane emissions. Twenty-six companies in the production sector currently participate in Natural Gas STAR, and they reported that they achieved about 50 Bcf of methane emissions reductions in 2013.
19

To further encourage emissions reductions from the oil and gas sector, the EPA announced, in July 2015, a voluntary program called the Natural Gas STAR Methane Challenge, in which companies would make ambitious commitments to reduce methane emissions and would track their progress in achieving those reductions.
20

In addition, six oil and gas companies have joined together to form the One Future Coalition, which aims to “(e)nhance the energy delivery efficiency of the natural gas supply chain by limiting energy waste and by achieving a methane `leak/loss rate' of no more than one percent.”
21

19
EPA Natural Gas STAR
Accomplishments, available at http://www3.epa.gov/gasstar/accomplishments/index.html.

20
EPA Natural Gas Star Methane Challenge,
Program Proposal, available at http://www3.epa.gov/gasstar/methanechallenge/index.html.

21
Maria Galluci,
Six Major Oil & Gas Firms Agree To Cut Potent Methane Emissions Ahead Of UN Climate Change Summit,
International Business Times, Sept. 23, 2014,
http://www.ibtimes.com/six-major-oil-gas-firms-agree-cut-potent-methane-emissions-ahead-un-climate-change-summit-1693517
;
http://www.gastechnology.org/CH4/Documents/Fiji-George-CH4-presentation-Sep2014.pdf
; One Future: Our Nation's Energy, 1, 6 (Sept. 2014),
http://www.gastechnology.org/CH4/Documents/Fiji-George-CH4-presentation-Sep2014.pdf.

Given these activities, it is important to ensure that updated BLM requirements do not subject operators to conflicting or redundant requirements. Thus, in addition to our outreach to States, we are coordinating closely with the EPA as it works to finalize its 40 CFR part 60 subpart OOOOa rulemaking.

The ongoing EPA and State regulatory activities do not, however, obviate the need for the BLM, in its role as a public land manager, to update its requirements governing flaring, venting, and leaks to ensure that the public's resources and assets are not wasted and are developed in a manner that provides for long term productivity and sustainability. First, the BLM has an independent legal responsibility, and a proprietary interest as a land manager, to oversee oil and gas production activities on Federal and Indian leases. The BLM has requirements in place, but as independent reviews have pointed out, the existing requirements pre-date, and thus do not account for, significant technological developments. Updating and clarifying the regulations will make them more effective, more transparent, and easier to understand and administer, and will reduce operators' compliance burdens in some respects. The BLM must ensure that it has modern, effective requirements to govern oil and gas operations on BLM-administered leases. Second, as a practical matter, neither the EPA nor State regulations adequately address the issue of waste of gas from BLM-administered leases. The EPA regulations are directed at air pollution reduction, not waste prevention; they focus largely on new sources; and they do not address all avenues for reducing waste (for example, they do not impose flaring limits for associated gas). Similarly, no State has established a comprehensive set of requirements addressing all three avenues for waste—flaring, venting, and leaks—and only a few States have significant requirements in even one of these areas. It is wholly within the BLM's statutory authority to address flaring, venting, and leaks in its capacity as a land manager with a responsibility to ensure the longevity and long term productivity of public lands and resources, including gas resources. Part I.B. of this preamble, below, offers a summary of the proposed rule's provisions, benefits, and costs, and parts V and VI of this preamble provide more detail about those provisions (part V) and impacts (part VI). Overall, the BLM estimates that the benefits of this rule would outweigh its costs by a significant margin. Under certain assumptions, for example, the rule is expected to produce net benefits ranging from $115 million to $188 million per year (assuming the EPA finalizes 40 CFR part 60 subpart OOOOa and calculating costs and cost savings using a 7 percent discount rate) or from $138 million to $232 million per year (assuming the EPA finalizes 40 CFR part 60 subpart OOOOa and calculating costs

and cost savings using a 3 percent discount rate).
22

22
BLM, Economic Impact and Regulatory Threshold Analysis for 43 CFR 3178 (Royalty Free Use of Production) and 43 CFR 3179 (Venting and Flaring Requirements) (2015) (hereinafter RIA) at 7.

B. Summary of Proposal

The proposed rule would require operators to take various actions to reduce waste of gas, establish clear criteria for when flared gas would qualify as waste and therefore be subject to royalties, and clarify the on-site uses of gas that are exempt from royalties. The BLM has identified several key points in the oil and gas production process where waste-prevention actions would be most effective and least costly. Specifically, we propose to focus on reducing waste from the following aspects of the production process: Flaring of associated gas from development oil wells; gas leaks from equipment and facilities located at the well site, as well as from compressors located on the lease; operation of high-bleed pneumatic controllers and certain pneumatic pumps; gas emissions from vessels; downhole well maintenance and liquids unloading; and well drilling and completions. The following discussion summarizes the proposed requirements applicable to each of these aspects of the production process.

These requirements would impose annual costs and yield annual benefits, but both costs and benefits are expected to vary over time. Over the first few years, compliance activity (and associated costs and gas savings) would likely be highest. During this time, some operators would have to add or improve gas-capture capability, and some would have to replace existing equipment. After these transitional years, we expect that both compliance activities and gas savings from this rule would be significantly reduced.

1. Venting and Flaring

In 2013, operators vented about 22 Bcf and flared at least 76 Bcf of natural gas from BLM-administered leases.
23

The 2013 flaring estimate, a 109 percent increase from 2009 levels,
24

represents 2.6 percent of the total production from BLM-administered leases in that year (2,901 Bcf)
25

and sufficient gas to supply over 1 million households.
26

Of this, roughly 71 Bcf came from oil wells.
27

Analysis of data supplied by the ONRR suggests that most of this was routine flaring of associated gas from development oil wells (as opposed to flaring during exploration, well testing, and emergencies). Over 90 percent of this flaring occurred in North Dakota, South Dakota, and New Mexico.
28

23
RIA at 119-120.

24
RIA 119.

25
RIA at 111 (Appendix A-2).

26
See footnote 2 (assuming 2009 usage levels).

27
RIA at 33.

28
RIA at 122 (Appendix A-8, Table 4).

The BLM is proposing to prohibit venting of natural gas, except under certain conditions, including in emergencies, as would be defined in the regulations.
29

With respect to flaring, the BLM proposes to limit the rate of routine flaring of associated gas from development oil wells and retain the current exemptions from gas capture requirements and royalties for gas flared in other situations, as long as the operator has complied with the proposed requirements to minimize such losses. These exemptions include gas lost in the normal course of well drilling and well completion; well tests; emergencies, as would be defined in the regulations;
30

and gas flared from exploration or wildcat wells, or delineation wells (wells drilled to define the boundaries of a mineral deposit).

29
See proposed 43 CFR 3179.105.

30
Ibid.

The primary alternative to flaring associated gas from oil wells is to capture, transport, and process that gas for sale, using the same technologies that are used for natural gas production. The capture and sale of associated gas is viable where there is sufficient gas production to offset the costs of connecting to or expanding existing pipeline infrastructure. In addition, technologies for capturing and using gas without a pipeline are becoming increasingly available. This capture infrastructure may include: Separating out NGLs or liquefying the natural gas (LNG), allowing the resulting liquids to be trucked off location; converting the gas into compressed natural gas (CNG) for use on-site or to be trucked off location; and using the gas to run micro-turbines to generate power for use on-site or for sale back to the grid.

Gas is flared under a variety of circumstances. Some circumstances, such as emergencies, can occur unplanned in the course of oil and gas production. Further, in a new field, operators and the midstream processing companies that commonly build and operate gas gathering and processing infrastructure may not have sufficient information about how much gas will be produced to invest in building gathering lines and processing plants. In other instances, however, operators may decide to focus on near-term oil production rather than investing in the gas capture and transmission infrastructure that would be necessary to realize a profit from the associated gas.

On BLM-administered leases, two situations result in substantial flaring of associated gas. In some areas, there is capture infrastructure, but the rate of new well construction is outpacing the infrastructure capacity. This accounts for the majority of flaring on BLM-administered leases. In other areas, capture and processing infrastructure has not yet been built out.

Currently, under NTL-4A, operators must seek BLM approval to flare on a case-by-case basis, with limited exceptions. Operators must provide economic data with each request, demonstrating that requiring the gas to be captured would “lead to the premature abandonment of recoverable oil reserves and ultimately to a greater loss of equivalent energy than would be recovered” if the flaring were approved. This approach results in a substantial amount of paper-work, but does not significantly limit flaring, as BLM has commonly, although not always, approved these requests.

The BLM proposes to simplify, clarify, and strengthen its approach to reducing flaring by establishing clear parameters for when routine flaring from development wells is allowed, and by setting a limit on the rate of flaring from individual wells. As a general matter, operators would no longer have to obtain permission for flaring on a case-by-case basis, provided they stay within the proposed prescribed limit.

Specifically, we propose to limit routine flaring of associated gas from development wells to 1,800 thousand cubic feet (Mcf) per month per well, averaged across all of the producing wells on a lease. This limit is similar to requirements in Wyoming and Utah, which limit flaring to 60 Mcf/day and 1,800 Mcf/month, respectively, unless the operator obtains State approval of a higher limit.
31

The BLM estimates that this limit would reduce flaring by up to 74 percent, although there is substantial uncertainty regarding this estimate. The BLM proposes to retain the authority to allow higher rates of flaring in specific circumstances, where adhering to the proposed flaring limit would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease. In making this

determination, the BLM would consider the costs of capture, and the costs and revenues of all oil and gas production on the lease. Further, the BLM proposes to create a 2-year renewable exemption from the flaring limit, available only for certain existing leases that are located a significant distance from gas processing facilities and flaring at a rate well above the proposed flaring limit. Holders of these leases have, until now, had no prior notice of the proposed flaring limit. Given the significant distance from these leases to the nearest gas capture facilities, and the leases' high rates of gas flaring, operators at these sites might have few options to meet the proposed flaring limit other than shutting in the wells. The BLM anticipates the number of leases eligible for this 2-year exemption would decline over time, as production of oil and associated gas from existing leases naturally declines.

31
Wyoming Operational Rules, Drilling Rules Section Ch. 3, Section 39(b),
available at http://soswy.state.wy.us/Rules/RULES/9584.pdf
(60 Mcf/day); Utah R649-3-20, Gas Flaring or Venting Section 1.1,
available at
(
http://www.rules.utah.gov/publicat/code/r649/r649-003.htm#T20
(1,800 Mcf/mo.).

The BLM proposes to phase in the flaring limit over the first 2 years after the rule becomes effective, in recognition of the fact that some wells are flaring at rates considerably higher than 1,800 Mcf/month, not all wells will be able to use on-site capture technologies, and connecting to gas pipeline infrastructure may take some time. We propose that in the first year after the effective date of the rule, the flaring limit per well, averaged across all of the producing wells on a lease, would be 7,200 Mcf/month. In the second year, it would be 3,600 Mcf/month. The 1,800 Mcf/month limit would apply beginning in the third year of the rule.

The BLM is also proposing that prior to drilling a new development oil well, an operator would have to evaluate the opportunities and prepare a plan to minimize waste of associated gas from that well, and the operator would need to submit this plan along with the Application for Permit to Drill or Reenter (APD). The BLM proposes to require submission of a plan with specific content, to ensure that operators have carefully considered and planned for gas capture prior to drilling.

In addition to these requirements to reduce flaring, the BLM proposes to update existing royalty provisions by more specifically defining when a loss of gas would be considered “unavoidable” and royalty-free, and when it would be considered “avoidable” and subject to royalties. A loss of gas would be deemed unavoidable when an operator has complied with all applicable requirements and taken prudent and reasonable steps to avoid waste, and the gas is lost from any of the following specified operations or sources, subject to limits specified in the proposed regulations: Emergencies; well drilling, well completion and related operations; initial production tests and subsequent well tests; exploratory coalbed methane well dewatering; leaks; venting from pneumatic devices in the normal course of operation; evaporation from storage vessels; and downhole well maintenance and liquids unloading. A loss of gas would also be deemed unavoidable when gas is flared (or, in limited circumstances, vented) from a well that is not connected to gas capture infrastructure, provided the BLM has not otherwise determined that the loss of gas is avoidable, pursuant to the provisions of the 1,800 Mcf/month limit in § 3179.6. All losses of gas not specifically found to be unavoidable would be considered avoidable and subject to royalties. Thus, royalties would apply to associated gas flared from a development well that is already connected to capture infrastructure. Under these circumstances, operators have made an economic choice to flare, and that flaring should not be considered an unavoidable consequence of oil production.

Currently, there is a backlog of requests for approval to flare royalty-free pending with the BLM. By establishing clear categories for avoidable and unavoidable losses, and thus clarifying when gas may be flared without payment of royalties, the BLM aims to reduce the number of applications for approval to flare royalty-free and thereby reduce the burden on both operators and the BLM. The BLM could then use these administrative resources to process applications for permit to drill and right-of-way applications, and to conduct inspections, among other activities.

The costs and benefits of the flaring provisions are as follows. First, the rule proposes to require the metering of flared volumes when gas flaring meets or exceeds 50 Mcf/day for a flare stack or manifold. We estimate compliance costs ranging from $1.0-1.8 million per year when the capital costs of equipment are annualized with a 7 percent discount rate, or $0.9-1.6 million per year when the capital costs of equipment are annualized with a 3 percent discount rate.
32

32
RIA at 69.

For purposes of this analysis, we present costs and benefits using discount rates of 7% and 3% to annualize the costs of capital investments. OMB Circular A-94 (Revised) “Guidelines and Discount Rates for Benefit-Cost Analysis of Federal Programs,”
https://www.whitehouse.gov/omb/circulars_a094/,
directs agencies to conduct baseline analyses using a discount rate of 7%, which “approximates the marginal pretax rate of return on an average investment in the private sector in recent years.” It also recommends that agencies show sensitivity of the discounted net present value and other outcomes using additional discount rates. The BLM chose to use a second discount rate of 3%, because the literature suggests that there is a divergence between private discount rates (considered by firms or industry) and social discount rates (considered by society), with private rates exceeding social rates. Further, it is common for regulatory impact analyses to analyze outcomes using a 3% discount rate, particularly for the environmental benefits of proposed regulations.

We estimate that the proposed flaring limits, including the 3-year phase-in period would affect an estimated 435-885 leases in any given year. These requirements could pose total costs of about $32-68 million per year (7 percent discount rate) or $26-43 million per year (3 percent discount rate). Because these requirements would drive additional capture of gas, the flaring limits are also projected to pose total cost savings (from the value of the captured gas) of about $40-58 million per year (7 percent discount rate) or $40-64 million per year (3 percent discount rate). We also estimate that they would increase natural gas production by 2.5-5.0 Bcf per year, and increase NGL production by 36-51 million gallons per year. The net benefits of these requirements are estimated to range from negative $10 to positive $8 million per year (7 percent discount rate) or $13-30 million per year (3 percent discount rate).
33

33
RIA at 60.

2. Leaks

One significant source of the 22 Bcf of gas vented from Federal and Indian leases in 2013 is leakage. The BLM estimates that up to 4.35 Bcf of natural gas was lost in 2013 as a result of leaks or other fugitive emissions at operations on BLM-administered leases.
34

Multiple studies have found that once leaks are detected, the vast majority can be repaired with a positive return to the operator. In addition, both Colorado and Wyoming (for part of the State) have recently adopted LDAR requirements for oil and gas production,
35

and EPA has adopted and proposed additional LDAR requirements for certain new and modified oil and gas production sources.
36

34
RIA at 3.

35
Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVII.F; Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(g) (June 2015),
available at
http://soswy.state.wy.us/Rules/RULES/9868.pdf
.

36
Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution, 60 CFR subpart OOOO; 80 CFR 56593, 56660-56698.

The BLM believes that LDAR programs are a cost-effective means of

reducing waste in oil and gas production. We are proposing to require operators to use an instrument-based approach to leak detection. Operators would be required initially to conduct semi-annual inspections at their well sites and compressor locations. If an operator finds no more than 2 leaks at a facility for two consecutive inspections, the operator may change to annual inspections at that facility. If the operator finds more than 2 leaks at a facility for two consecutive inspections, the operator must inspect for leaks quarterly. If an operator that is required to inspect for leaks quarterly finds no more than 2 leaks at a given facility in two sequential inspections, the operator could then change back to semi-annual inspections, and so forth. Once a leak is identified, the BLM proposes that the operator would be required to repair the leak as soon as practicable, but no later than 15 calendar days after discovery, absent good cause. Operators would have to verify the effectiveness of a repair within 15 calendar days of the repair, using the same method used to detect the leak. Operators would also be required to keep records documenting the dates and results of leak inspections, repairs, and follow-up inspections.

The costs and benefits of the BLM's proposed LDAR requirements depend on the rest of the regulatory landscape. Assuming that the EPA finalizes its 40 CFR part 60 subpart OOOOa rulemaking for new and modified sources,
37

then the BLM expects that its proposed requirements would impact up to 36,700 existing wellsites, and pose total costs of about $69-70 million per year (using 7 percent and 3 percent discount rates). These requirements are also projected to result in cost savings of about $12-15 million per year (7 percent discount rate) or $15-17 million per year (3 percent discount rate), increase gas production by 3.9 Bcf per year, and reduce VOC emissions by 18,600 tons per year (tpy). We estimate they would reduce methane emissions by 67,000 tpy, producing monetized benefits of $73 million per year in 2017-2019, $87 million per year in 2020-2024, and $100 million in 2025 and 2026. Thus, we estimate that these provisions would result in net benefits of $19-21 million per year in 2017-2019, $31-35 million per year in 2020-2024, and $43-48 million in 2025 and 2026.
38

37
The RIA includes a broader discussion of the estimates of the costs and benefits of this proposed rule if the EPA does not finalize its 40 CFR part 60 subpart OOOOa rulemaking, but the preamble omits some of those estimates to simplify the discussion. EPA's proposed requirements would apply to wells that are new, “modified,” or “reconstructed” after September 18, 2015. See 40 CFR 60.14 and 60.15 for EPA's definitions of “modification” and “reconstruction.”

38
RIA at 109.

If, for analytical purposes we assume a baseline in which EPA does not finalize its proposed LDAR requirements, we estimate the following impacts. We project that the proposed LDAR requirements would affect up to about 37,000-38,000 wellsites per year, and pose total costs of about $70-71 million per year (using 7 percent and 3 percent discount rates). These requirements are also projected to result in cost savings of about $12-18 million per year (using 7 percent and 3 percent discount rates), increase gas production by 3.9-4.0 Bcf per year, and reduce VOC emissions by 19,000 tpy. We estimate these proposed requirements would also reduce methane emissions by 68,000 tpy, producing monetized benefits of $75 million per year in 2017-2019, $88 million per year in 2020-2024, and $102 million in 2025 and 2026. Thus, we estimate that these proposed provisions would result in net benefits of $19-21 million per year in 2017-2019, $30-35 million per year in 2020-2024, and $43-48 million in 2025 and 2026.
39

39
RIA at 108-109.

These estimates represent the maximum likely impact. As noted previously, some operators currently have LDAR programs. This analysis accounts for existing State requirements in Colorado, Utah, and Wyoming, but it does not account for existing (voluntary or required) LDAR activities conducted by operators outside of those States. If we accounted for these existing activities, then the costs, emissions reductions, incremental production, and royalty estimates resulting from this proposed rule would be less than those shown.

3. Pneumatic Controllers and Pneumatic Pumps

Pneumatic controllers and pneumatic pumps are operated by gas pressure and emit gas as part of their normal operations. We estimate that on BLM-administered leases in 2013, about 5.4 Bcf of natural gas was lost from pneumatic controllers, and about 2.5 Bcf was lost from all pneumatic pumps.
40

Further, we estimate that the proposed rule would impact up to 15,600 high bleed pneumatic controllers (pneumatic controllers with bleed rates of more than 6 standard cubic feet per hour (scf/hour)) on BLM-administered leases.
41

A recent study by the consulting firm ICF International (ICF) identified replacement of high-bleed pneumatic controllers with low-bleed pneumatic controllers (pneumatic controllers with bleed rates of 6 scf/hour or less) as one of the most inexpensive options for reducing methane, estimating that it would actually save industry $2.65 per Mcf of avoided methane emissions.
42

40
RIA at 3.

41
RIA at 78.

42
ICF International, Economic Analysis of Methane Emission Reduction Opportunities in the U.S. in the Onshore Oil and Natural Gas Industries, 4-4 (Mar. 2014),
available at https://www.edf.org/sites/default/files/methane_cost_curve_report.pdf
(ICF 2014 Study) (base case assumed $4/Mcf price for recovered gas and a 10 percent discount rate/cost of capital).

EPA generally prohibits the use of new high-bleed pneumatic controllers,
43

and Colorado and Wyoming (in part of the State) have required replacement of existing high-bleed pneumatic controllers with low-bleed pneumatic controllers.
44

The State of Wyoming has regulations that require pneumatic pumps used in the Upper Green River Basin to destroy or capture emissions or be replaced by zero-emission solar-, electric-, or air-driven pumps by January 1, 2017.
45

43
40 CFR 60.5390.

44
Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVIII; Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(f) (June 2015),
available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

45
Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(e) (June 2015),
available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

The BLM is proposing to require operators to replace high-bleed pneumatic controllers with low-bleed or no-bleed pneumatic controllers within 1 year of the effective date of the final rule. This requirement would apply only to pneumatic controllers that are not subject to EPA regulations. The BLM also proposes exceptions to this requirement, including where the operator demonstrates, and the BLM concurs, that replacing the controller(s) would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease. In making this determination, the BLM would consider the costs of capture, and the costs and revenues of all oil and gas production on the lease.

We estimate that the proposed pneumatic controller requirements would impact up to about 15,600 existing low-bleed pneumatic devices, and pose total costs of about $6 million per year (capital costs annualized using a 7 percent discount rate) or $5 million per year (capital costs annualized using a 3 percent discount rate). Because the sale of recovered gas is expected to offset the engineering costs of new controllers, the BLM expects that

compliance with the pneumatic controller requirements would increase gas production by 2.9 Bcf per year, result in cost savings to the industry of about $9-11 million per year (using a 7 percent discount rate) or $11-12 million per year (using a 3 percent discount rate). On net, we project that the industry would save $3-5 million per year (using a 7 percent discount rate) or $6-7 million per year (using a 3 percent discount rate) under these requirements. These requirements are also projected to reduce methane emissions by 43,000 tpy, producing monetized benefits of $48 million per year in 2017-2019, $56 million per year in 2020-2024, and $65 million in 2025 and 2026. The resulting net benefits of $53-68 million per year (using a 7 percent discount rate for costs and cost savings) or net benefits of $54-73 million per year (using a 3 percent discount rate for costs and cost savings), along with a reduction in VOC emissions of about 200,000 tpy.
46

46
Regulatory Impact Analysis (RIA) at 78.

For pneumatic pumps, the BLM is proposing to require the operator to either: (1) Replace a pneumatic chemical injection or diaphragm pump with a zero-emissions pump; or (2) Route the pneumatic chemical injection or diaphragm pump to a flare. This requirement would apply only to pneumatic pumps that are not subject to EPA regulations. In addition, an operator would be exempt from this requirement if it demonstrates, and the BLM concurs, that: (1) There is no flare already available on-site or routing to a flare device is technically infeasible; and (2) A zero-emission pneumatic pump is not a viable alternative to perform the required function. An operator would also be exempt if the operator demonstrates and the BLM concurs that replacing the pneumatic pump(s) would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease. In making this determination, the BLM would consider the costs of capture, and the costs and revenues of all oil and gas production on the lease.

If the EPA finalizes its concurrent 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that these requirements would impact up to 8,775 existing pumps, posing total costs of about $2.5 million per year. They would also increase gas production by 0.46 Bcf per year and result in cost savings of about result in cost savings of $1.5-1.9 million per year (7 percent discount rate) or $1.75-2.15 million per year (3 percent discount rate). In addition, they are projected to reduce methane emissions by about 16,000 tpy, producing monetized benefits of $18 million per year in 2017-2019, $21 million per year in 2020-2024, and $24 million in 2025 and 2026. This would result in net benefits of $17 million per year in 2017-2019, $20 million per year in 2020-2024, and $23 million in 2025 and 2026, as well as reducing VOC emissions by about 4,000 tpy.
47

47
RIA at 82.

Assuming, for purposes of analysis, that EPA does not finalize the 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that the pneumatic pump requirements would affect up to about 8,775 existing pumps and about 75 new pumps per year, posing total costs of about $2.5-2.7 million per year (using 7 percent and 3 percent discount rates). They would also increase gas production by 0.5 Bcf per year and result in cost savings of about $1.5-2.2 million per year (using 7 percent and 3 percent discount rates). In addition, they are projected to reduce methane emissions by about 16,000-17,000 tpy, producing monetized benefits of $18 million per year in 2017-2019, $22 million per year in 2020-2024, and $26 million in 2025 and 2026. This would result in net benefits of $17 million per year in 2017-2019, $21-22 million per year in 2020-2024, and $25 million in 2025 and 2026, as well as reducing VOC emissions by about 4,000 tpy.
48

48
RIA at 81.

4. Storage Vessels

Vapors released from storage vessels are a lost source of energy and revenue, present safety concerns, and contribute to local air pollution and climate change. We estimate that 2.77 Bcf of natural gas was lost in 2013 from storage tank venting on Federal and Indian lands.
49

Of that volume, we estimate that 1.82 Bcf was lost from storage vessels used in natural gas production and 0.95 Bcf of gas was lost from storage vessels used in oil production.
50

49
RIA at 3.

50
RIA at 19.

Tank vapors can be controlled by routing them to a flare or combustor, or by installing a vapor recovery unit (VRU). New and modified vessels used in oil and gas production are already subject to EPA emissions limits, which require that individual storage vessels with VOC emissions equal to or greater than 6 tpy achieve at least a 95 percent reduction in VOC emissions from baseline levels. Colorado and part of Wyoming have similar, somewhat more stringent, requirements for storage vessels.
51

51
Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Sections XII.D-F; XVII.C; Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(c) (June 2015),
available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

The BLM proposes to address gas losses from existing storage vessels, which are not covered by the EPA standards. The BLM believes that reducing venting from existing storage vessels, which have higher rates of venting, is a reasonably cost-effective means of reducing gas losses. Rather than establishing new and separate standards for venting from existing vessels, we have been informed by operators that it would be easier to comply if we simply require existing vessels on BLM-administered leases to meet standards that are the same as the EPA standards that already apply to new and modified vessels on those leases. Additionally, there does not appear to be a uniform conversion factor that we could use to translate the VOC standards established by EPA, Colorado, and Wyoming to a whole gas standard. Depending on the content of a vessel, the same quantity of gas released from the vessel may contain different quantities of VOCs. Thus, even though the BLM is concerned about loss of
all
hydrocarbons from vessels, not just loss of VOCs, we propose to use VOCs as a proxy for whole gas, and thus to apply the control requirement to existing vessels with at least 6 tpy of VOCs, using the same applicability threshold as EPA and Colorado.
52

(Wyoming also uses VOC emissions to determine applicability, but has a lower threshold.
53

)

52
40 CFR 60.5395; Colorado Air Quality Control Commission Regulations, Regulation 7, 5 CCR 1001-9, Section XVII.C.

53
Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(c)(i)(a) (June 2015),
available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

The BLM proposes to require that operators route VOC emissions from existing storage vessels subject to these requirements to combustion devices, continuous flares, or sales lines within 6 months after the effective date of the rule. The BLM would grant an exception to this requirement if the operator submits an economic analysis demonstrating—and the BLM agrees—that compliance would impose such costs as to cause the operator to cease production and abandon significant recoverable oil reserves under the lease. In making this determination, the BLM would consider the costs of capture, and the costs and revenues of all oil and gas production on the lease. Consistent with the EPA requirements for new vessels,

these requirements would no longer apply if the uncontrolled VOC emissions fall below 4 tpy for 12 months.

The BLM estimates that the proposed requirements would affect about 300 existing storage vessels on BLM-administered leases, and pose total costs of about $6 million per year (using 7 percent and 3 percent discount rates).
54

We project that these requirements would increase gas production by 0.04 Bcf per year, resulting in cost savings of about $0.1-0.2 million per year (using 7 percent and 3 percent discount rates). They would also reduce methane emissions by 7,000 tpy, producing monetized benefits of $8 million per year in 2017-2019, $9 million per year in 2020-2024, and $11 million in 2025 and 2026. Overall, we estimate that these provisions would result in net benefits of $2 million per year in 2017-2019, $3-4 million per year in 2020-2024, and $5 million in 2025 and 2026, and reduce VOC emissions by 32,500 tpy.

54
RIA at 95.

5. Well Maintenance and Liquids Unloading

Over time, as pressure in a natural gas well drops, liquids often start accumulating at the bottom of the well, impeding gas production. Operators often remove or “unload” the liquids, but depending on the method, this process can release substantial quantities of natural gas into the environment. In particular, operators may allow the bottom-hole pressure to increase and then vent or “blow down” or “purge” the well. We estimate that 3.26 Bcf of natural gas was lost in 2013 during liquids unloading operations on Federal and Indian lands.
55

55
RIA at 3.

There are a wide variety of methods for liquids unloading, and technological developments, such as automated plunger lifts, now allow liquids to be unloaded with minimal loss of gas. The BLM believes that it is reasonable to expect operators to use these available technologies to minimize gas losses, and we believe that failure to minimize losses of gas from liquids unloading now constitutes waste.

For wells drilled after the effective date of the rule, the BLM is proposing to prohibit unloading liquids by simply purging the well (except in specified circumstances). The BLM believes that it is less costly to avoid purging altogether at new wells than at existing wells. In addition, the BLM is proposing to require specified best management practices to minimize venting from liquids unloading at both new and existing wells. Specifically, the operator would be required to be on-site during well purging events, unless the well has an automatic control system, and the operator would also be required to document liquids unloading events. This would allow the BLM to verify compliance, and it would provide additional information on the amounts of gas lost through these activities on Federal and Indian lands.

We estimate that the proposed liquids unloading requirements would affect up to about 1,550 existing wells and about 25 new wells per year, posing total costs of about $6 million per year (capital costs annualized using a 7 percent discount rate) or $5-6 million per year (capital costs annualized using a 3 percent discount rate). We project that they would increase gas production by roughly 2 Bcf per year, resulting in cost savings of about $7-8 million per year (using a 7 percent discount rate) or $7-10 million per year (using a 3 percent discount rate). In addition, these requirements are projected to reduce methane emissions by 30,000 to 34,000 tpy, producing monetized benefits of $33-34 million per year in 2017-2019, $41-43 million per year in 2020-2024, and $50-51 million in 2025 and 2026. Overall, we estimate that these provisions would produce net benefits of $35-52 million per year (using a 7 percent discount rate for costs and cost savings) or $35-55 million per year (using a 3 percent discount rate for costs and cost savings), and reduce VOC emissions by about 136,000 to 156,000 tpy.
56

56
RIA at 87.

6. Reduction of Waste From Drilling, Completion, and Related Operations

Substantial quantities of gas can be lost during drilling, completion, and refracturing (sometimes referred to by the broader term “workover”) operations, and we estimate that in 2013, 2.1 Bcf of natural gas was lost during these operations on BLM-administered leases.
57

Of this, we estimate that completion emissions from hydraulically fractured (and refractured) oil wells accounted for 1.4 Bcf of the loss, emissions from hydraulically fractured gas wells accounted for about 0.7 Bcf of the loss, and all other completions accounted for a de minimis amount.
58

57
RIA at 3.

58
RIA at 18 (Table 6).

The EPA currently requires new hydraulically fractured and refractured gas wells to capture or flare gas that otherwise would be released during drilling and completion operations, and EPA has announced that it plans to extend these requirements to new hydraulically fractured and refractured oil wells. Nonetheless, the BLM believes that it is appropriate for the BLM to adopt its own requirements to minimize the waste of gas during well drilling and well completion and post-completion operations at hydraulically fractured or refractured wells and wells that are not fractured. The BLM has an independent statutory obligation to minimize waste of oil and gas resources on BLM-administered leases. As proposed, the BLM waste requirements for well drilling and completions would extend to both conventional and hydraulically fractured wells, and therefore would apply to a broader set of wells than the EPA regulations propose to cover. Also, the BLM anticipates that to the extent both sets of requirements applied, the BLM believes that an operator would satisfy both sets of requirements by either capturing or flaring the gas that would otherwise be released. Thus, the BLM is also proposing to allow an operator to demonstrate that it is in compliance with EPA requirements for control of gas from well completions in lieu of compliance with the BLM requirements. The BLM is coordinating closely with the EPA on the agencies' proposals, and the BLM expects to ensure that our final requirements would not impose additional burdens on an operator that complies with any EPA requirements on new well completions.

The proposed rule would require operators to: Flare gas generated during drilling operations, capture and sell that gas, use it in operations on the lease, or inject it into the well. We estimate that the rule would apply to about 3,000 wells per year. Based on our experience in the field, however, the BLM believes that operators are already controlling gas from drilling operations as a matter of safety and operating practice. Thus, we do not estimate costs associated with this requirement. Similarly, based on our professional experience in the field, we believe that operators are already controlling gas from workover operations on conventional wells as a matter of safety and operating practice, and there should be no compliance costs for this requirement.

The proposed rule would also require operators to reduce the emissions associated with well completions by capturing and selling associated gas, flaring it, using it in operations on the lease, or injecting it. This proposal would only impact well completions and workovers/refractures on conventional oil and gas wells and

hydraulically fractured oil wells, as EPA already covers hydraulically fractured gas wells.

If the EPA finalizes its 40 CFR part 60 subpart OOOOa rulemaking, as we expect, then as a practical matter, this rule's completion requirements will only impact conventional well completions, because the EPA will regulate completions of new and modified hydraulically fractured oil and gas wells. We estimate that the BLM rule would impact between 115-150 completions per year and pose costs to the industry of less than $430,000 per year. There would be only
de minimis
anticipated incremental production, incremental royalty, and emissions reductions.
59

59
RIA at 74.

If, for purposes of analysis, we assume that EPA does not finalize its 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that these provisions would affect about 1,250 to 1,575 completions per year and pose total costs of about $8-12 million per year (using a 7 percent discount rate) or $12 million per year (using a 3 percent discount rate). We further estimate that these provisions would increase gas production by 0.5 to 0.6 Bcf per year, resulting in cost savings of about $2-3 million per year (using 7 percent and 3 percent discount rates). This would also reduce methane emissions by 11,500 to 14,500 tpy, producing monetized benefits of $13 million per year in 2017-2019, $16-18 million per year in 2020-2024, and $21-22 million in 2025 and 2026. Overall, under this scenario, these provisions are estimated to produce net benefits of $3-15 million per year (considering the present value of costs and cost savings using a 7 percent discount rate) or net benefits of $3-13 million per year (considering the present value of costs and cost savings using a 3 percent discount rate), and reduce VOC emissions by 9,600 to 12,200 tpy.
60

60
RIA at 74.

7. Royalty Provisions Governing New Competitive Leases

Finally, the BLM proposes to revise the regulations at 43 CFR 3103.3-1, which govern royalty rates applicable to onshore oil and gas leases, to make the rule text parallel to the statutory text, respond to findings and recommendations in audits from the GAO, and eliminate unnecessary provisions in the existing regulations.

The proposed revisions would do three principal things: (1) Make clear that the royalty rate on all existing leases would remain at the rate prescribed in the lease or in regulations applicable at the time of lease issuance; (2) Specify the fixed, statutory rate of 12.5 percent
61

for all noncompetitive leases issued after the effective date of the rule; and (3) Make the rule text parallel to the corresponding MLA text for competitive leases issued after the effective date of the rule.
62

The MLA text provides the BLM the flexibility to set royalty rates for these competitive leases at
or above
12.5 percent. By contrast, the BLM's existing royalty regulation sets a flat rate of 12.5 percent for all new competitive leases.
63

Although the BLM does not currently propose to raise royalty rates, the proposed rule would allow the BLM to set a royalty rate for oil and gas produced from competitive oil and gas leases issued after the effective date of this rule of “not less than” 12.5 percent. The BLM is not proposing any further changes to the royalty provisions governing new competitive oil and gas wells,
64

but we are requesting comment on the use of a fluctuating royalty rate to incentivize reductions in flaring from new competitive leases. Further information about this possible approach is provided below in Section V.C. of this preamble.

61
30 U.S.C. 226(c)(1).

62
30 U.S.C. 226(b)(1)(A).

63
43 CFR 3103.3-1(a)(1).

64
Note that the proposed rule would renumber current 43 CFR 3103.3-1 (a)(2) and (3) but would not otherwise change the content of those provisions. Further, the proposed rule would not alter 43 CFR 3103.3-1(b), (c), or (d). Those five provisions are reprinted in this proposed rule solely to clarify the proposed numbering of the revised § 3103.3-1, and for ease of reference. The BLM does not intend to revise those provisions, nor to invite comment on their content.

C. Summary of Costs and Benefits

1. Costs

Overall, assuming that the EPA finalizes its concurrent 40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that this proposed rule will pose costs ranging from $125-161 million per year (using a 7 percent discount rate) or $117-$134 million per year (using a 3 percent discount rate) over the next 10 years.
65

These costs would include engineering compliance costs and the social cost of minor additions of carbon dioxide to the atmosphere, resulting from the on-site or downstream use of gas that is newly captured as a result of this proposed rule.
66

The engineering compliance costs presented do not include potential cost savings from the recovery and sale of natural gas (those savings are shown in the summary of benefits).

65
RIA at 127.

66
Some gas that would have otherwise been vented would now be combusted on-site or presumably downstream to generate electricity. As described in the RIA, the estimated value of these carbon additions would not exceed $30,000 in any given year.

If, for analytical purposes, we assume that EPA does not finalize its concurrent 40 CFR part 60 subpart OOOOa rulemaking, these requirements would affect more sources and the costs would be somewhat higher. Under that scenario, the BLM estimates that this rule will pose costs ranging from $139-174 million per year (using a 7 percent discount rate) or $131-147 million per year (using a 3 percent discount rate) over the next 10 years.
67

67
RIA at 127.

In some areas, operators have already undertaken, or plan to undertake, voluntary actions to address gas losses. To the extent that operators are already in compliance with the requirements of this proposed rule, the above estimates overstate the likely impacts of the rule.

We expect that cost impacts on individual operators would be small, even for businesses with less than 500 employees. In the RIA, we estimate that average costs for a representative small operator would increase by about $31,300-37,500, which would result in an average reduction in profit margin of 0.087-0.104 percentage points in 2020.
68

68
RIA at 159. These estimates rely on 2014 company data, use a 7% discount rate, and assume the finalization of EPA's 40 CFR part 60 subpart OOOOa rulemaking.

2. Benefits

We measure the benefits of the rule as the cost savings that the industry would receive from the recovery and sale of natural gas and the environmental benefits of reducing the amount of methane (a potent GHG) and other air pollutants released into the atmosphere. As with the estimated costs, we expect benefits on an annual basis. The estimated benefits of the rule also depend on whether the EPA finalizes its 40 CFR part 60 subpart OOOOa rulemaking. Assuming that rule is in effect, the BLM estimates that this rule would result in monetized benefits of $255-329 million per year (using a 7 percent discount rate to calculate the present value of future annual cost savings, and using model averages of the social cost of methane with a 3 percent discount rate) or $255-357 million per year (using a 3 percent discount rate to calculate the present value of future annual cost savings, and using model averages of the social cost of methane with a 3 percent discount rate).
69

We estimate that the proposed rule would reduce methane emissions by 164,000-

169,000 tpy, which we estimate to be worth $180-253 million per year (this social benefit is included in the monetized benefit above). We estimate that the proposed rule would reduce VOC emissions by 391,000-411,000 tpy (this benefit is not monetized in our calculations).
70

69
RIA at 130.

70
RIA at 133-135.

If, for purposes of analysis, we assume that EPA does not finalize its 40 CFR part 60 subpart OOOOa rulemaking, we estimate that this proposed rule would result in monetized benefits of $270-354 million per year (using a 7 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate) or $270-384 million per year (using a 3 percent discount rate to calculate the present value of future annual cost savings and using model averages of the social cost of methane with a 3 percent discount rate).
71

We estimate that the proposed rule would reduce methane emissions by 176,000-185,000 tpy, which we estimate to be worth $193-277 million per year (this social benefit is included in the monetized benefit above). We estimate that the proposed rule would reduce VOC emissions by 400,000-423,000 tpy (this benefit is not monetized in our calculations).
72

71
RIA at 130.

72
RIA at 133-135.

Adoption of the proposed rule would also have numerous ancillary benefits. These include improved quality of life for nearby residents, who note that flares are noisy and unsightly at night; reduced release of VOCs, including benzene and other hazardous air pollutants; and reduced production of nitrogen oxides (NO
X
) and particulate matter, which can cause respiratory and heart problems.

3. Net Benefits

Overall, the BLM estimates that the benefits of this rule outweigh its costs by a significant margin. The BLM expects net benefits ranging from $115-188 million per year (using a 7 percent discount rate) or $138-232 million per year (using a 3 percent discount rate). Specifically, assuming a 7 percent discount rate, we estimate the following annual net benefits:

• $115-130 million per year from 2017-2019;

• $155-156 million per year from 2020-2024; and

• $187-188 million per year from 2025-2026.

Assuming a 3 percent discount rate, we estimate the annual net benefits would be:

• $138-151 million per year from 2017-2019;

• $192-196 million per year from 2020-2024; and

• $231-232 million per year from 2025-2026.
73

73
RIA at 7.

If, for purposes of analysis, we assume that the EPA does not finalize the 40 CFR part 60 subpart OOOOa rulemaking, we estimate the net benefits of this proposed rule would be somewhat higher, ranging from $119-203 million per year (costs and costs savings calculated using a 7 percent discount rate) or $139-245 million per year (costs and costs savings calculated using a 3 percent discount rate).

4. Influence on Production

The proposed rule has a number of requirements that are expected to influence the production of natural gas, NGLs, and crude oil from onshore Federal and Indian oil and gas leases.

If 40 CFR part 60 subpart OOOOa is finalized, we estimate the following incremental changes in production, noting the representative share of the total U.S. production in 2014 for context. We estimate additional natural gas production, ranging from 11.7-14.5 Bcf per year (representing 0.04-0.05 percent of the total U.S. production in 2014), the productive use of an additional 29-41 Bcf of natural gas, which we estimate would be used to generate 36-51 million gallons of NGL per year (representing 0.08-0.11 percent of the total U.S. production), and a reduction in crude oil production ranging from 0.6-3.2 million bbl per year (representing 0.02-0.10 percent of the total U.S. production). We also expect 0.5 Bcf of gas to be combusted on-site that would have otherwise been vented. Combined, the capture or combustion of gas represents 44-46 percent of the volume vented in 2013 and the capture and/or productive use of the gas 41-60 percent of the volume flared in 2013.
74

74
RIA at 140.

If 40 CFR part 60 subpart OOOOa is not finalized, we estimate additional natural gas production ranging from 12-15 Bcf per year (representing 0.04-0.06 percent of the total U.S. production), the productive use of an additional 29-41 Bcf of natural gas, which we estimate would be used to generate 36-51 million gallons of NGL per year (representing 0.08-0.11 percent of the total U.S. production), and a reduction in crude oil production ranging from 0.6-3.2 million bbl per year (representing 0.02-0.10 percent of the total U.S. production). Separate from the volumes listed above, we also expect 1 Bcf of gas to be combusted on-site that would have otherwise been vented. Combined, the capture or combustion of gas represents 49-52 percent of the volume vented in 2013 and the capture and/or productive use of gas represents 41-60 percent of the volume flared in 2013.
75

75
RIA at 140.

Since the relative changes in production are expected to be small, we do not expect that the proposed rule would significantly impact the price, supply, or distribution of energy.

5. Royalties

Assuming the EPA 40 CFR part 60 subpart OOOOa rulemaking is finalized, we estimate that this proposed rule would produce additional royalties of $9-11 million per year (discounted at 7 percent) or $10-16 million per year (discounted at 3 percent).
76

If, for purposes of analysis, we assume that the EPA does not finalize the 40 CFR part 60 subpart OOOOa rulemaking, we estimate that this proposed rule would result in annual incremental royalties of $9-11 million per year (discounted at 7 percent) or $11-17 million per year (discounted at 3 percent).

76
RIA at 143.

II. Table of Contents

I. Executive Summary

A. Background

B. Summary of Proposal

1. Venting and Flaring

2. Leaks

3. Pneumatic Controllers and Pneumatic Pumps

4. Storage Vessels

5. Well Maintenance and Liquids Unloading

6. Reduction of Waste From Drilling, Completion, and Related Operations

7. Royalty Provisions Governing New Competitive Leases

C. Summary of Costs and Benefits

1. Costs

2. Benefits

3. Net Benefits

4. Royalties

II. Table of Contents

III. Public Comment Procedures

IV. Background

A. Overview

B. Impacts of Waste and Loss of Gas

C. Purpose of This Rule

D. Stakeholder Outreach

E. Existing BLM Regulations and Requirements for Preventing Natural-Gas Waste

F. Legal Authority

G. Concerns About Loss of Gas Identified Through Oversight

H. Volumes of Lost Natural Gas

1. Data Sources on Lost Gas

2. Additional Information on Loss Estimates

I. Examples of and Gaps in Existing Waste-Reduction and Related Efforts

1. State Activities

2. Voluntary Industry Efforts

3. EPA Air Quality Requirements

V. Discussion of the Proposed Rule

A. Measures To Reduce Waste

1. Venting or Flaring of Associated Gas From Producing Oil Wells

2. Leaks

3. Pneumatic Controllers and Pneumatic Pumps

4. Storage Vessels

5. Well Maintenance and Liquids Unloading

6. Reduction of Waste From Drilling, Completion, and Related Operations

7. Additional Opportunities To Reduce Waste From Venting

B. Royalty-Free Use of Production

C. Royalty Rates on New Competitive Leases

D. Record Keeping Requirements

E. Reporting and Information Availability

F. Planning Process

G. Facilities in Rights-of-Way

H. State or Tribal Variances

I. Section-by-Section Discussion

1. Section 3103.3-1

2. Section 3160.0-5

3. Section 3162.3-1

4. Subpart 3178—Royalty-Free Use of Lease Production

5. Subpart 3179—Waste Prevention and Resource Conservation

6. Flaring and Venting Gas During Drilling and Production Operations

7. Gas Flared or Vented From Equipment or During Well Maintenance Operations

8. Leak Detection and Repair

9. State or Tribal Variances

VI. Analysis of Impacts

A. Description of the Regulated Entities

1. Potentially Affected Entities

2. Affected Small Entities

B. Impacts of the Proposed Requirements

1. Overall Costs of the Rule

2. Overall Benefits of the Rule

3. Net Benefits of the Rule

4. Distributional Impacts

VII. Procedural Matters

A. Executive Order 12866, Regulatory Planning and Review

B. Regulatory Flexibility Act and Small Business Regulatory Enforcement Fairness Act of 1996

C. Unfunded Mandates Reform Act of 1995

D. Executive Order 12630, Governmental Actions and Interference With Constitutionally Protected Property Rights (Takings)

E. Executive Order 13132, Federalism

F. Executive Order 12988, Civil Justice Reform

G. Executive Order 13175, Consultation and Coordination With Indian Tribal Governments

H. Paperwork Reduction Act

1. Overview

2. Summary of Proposed Information Collection Requirements

3. Proposals Involving APDs and Sundry Notices

4. Other Proposed Information Collection Activities

5. Burden Estimates

I. National Environmental Policy Act

J. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use

K. Clarity of the Regulations

L. Executive Order 13563, Improving Regulation and Regulatory Review

VIII. Authors

III. Public Comment Procedures

If you wish to comment on the proposed rule, you may submit your comments by any one of several methods specified (see
ADDRESSES
). If you wish to comment on the information collection requirements, you should send those comments directly to the OMB as outlined (see
ADDRESSES
); however, we ask that you also provide a copy of those comments to the BLM.

Please make your comments as specific as possible by confining them to issues for which comments are sought in this notice, and explain the basis for your comments. The comments and recommendations that will be most useful and likely to influence agency decisions are:

1. Those that are supported by quantitative information or studies; and

2. Those that include citations to, and analyses of, the applicable laws and regulations.

The BLM is not obligated to consider or include in the Administrative Record for the rule comments received after the close of the comment period (see
DATES
) or comments delivered to an address other than those listed (see
ADDRESSES
).

Comments, including names and street addresses of respondents, will be available for public review at the address listed under
ADDRESSES
during regular hours (7:45 a.m. to 4:15 p.m.), Monday through Friday, except holidays. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.

IV. Background

A. Overview

The BLM's onshore oil and gas management program is a major contributor to our nation's oil and gas production. The BLM manages more than 245 million acres of land and 700 million acres of subsurface estate, comprising nearly a third of the nation's mineral estate. Domestic production from over 100,000 Federal onshore oil and gas wells accounts for 11 percent of the Nation's natural gas supply and 5 percent of its oil. In FY 2014, the ONRR reported that operators produced 204.6 MMbbl of oil, 2 Tcf of natural gas, and 3.1 billion gallons of NGLs from onshore Federal and Indian oil and gas leases. The production value of this oil and gas exceeded $27.2 billion and generated approximately $3.1 billion in royalties.
77

77
ONRR, Statistical Information,
http://statistics.onrr.gov/ReportTool.aspx
using Sales Year—FY2014—Federal Onshore—All States Sales Value and Revenue for Oil, NGL, and Gas products as of December 2, 2015.

Over the past decade, the United States has experienced a dramatic increase in natural gas and oil production due to technological advances, such as hydraulic fracturing combined with directional drilling. This boost in production has brought many benefits in the form of expanded and more secure domestic supplies, lower prices, increased economic activity, and greater royalty revenues for Federal, State, and tribal governments.

At the same time, the American public has not benefited from the full potential of this increased production, as it has been accompanied by significant and growing quantities of wasted natural gas. Between 2009 and 2014, operators on BLM-administered leases wasted enough natural gas to serve 5.1 million homes for 1 year, according to data reported to ONRR.
78

78
Based on an estimate of 74 Mcf of gas used per household per year. See footnote 2.

A sizeable quantity of natural gas is flared or vented in the course of exploration, development, and production activities. Commonly used well pad production equipment, such as pneumatic controllers, are designed to function by venting natural gas. Leaks and other unintentional releases across oil and gas operations account for additional waste. As discussed in the RIA, we estimate that in 2013, about 98 Bcf of natural gas was vented, flared, or leaked from oil and gas production on BLM-administered leases.
79

This represents about 3.4 percent of the total production from BLM-administered leases in that year (2,901 Bcf).
80

79
RIA at 3.

80
RIA at 111 (Appendix A-2).

This proposed rule aims to reduce wasteful venting, flaring, and leaks of natural gas from oil and natural gas production activities on onshore Federal and Indian leases. The rule would update the BLM's existing requirements

related to venting, flaring, and royalty-free use of natural gas, which are over 3 decades old. The BLM proposes to clarify the circumstances under which operators may flare, or in very limited circumstances vent, natural gas produced in the course of exploration, development, and production activities, and we propose to expand the circumstances under which flared or vented natural gas would be subject to royalties. The BLM also proposes other reasonable measures to reduce wasteful venting, flaring, and leaks of natural gas from oil and gas operations on Federal and Indian leases.

The BLM expects that these regulations would benefit the public by reducing waste of a public resource, improving production accountability, increasing natural gas supplies, and increasing royalties received by Federal, State, and tribal governments. In addition, reducing venting and flaring would reduce impacts on local communities and the environment by reducing emissions of air pollutants that contribute to smog, particulate pollution, and climate change.

B. Impacts of Waste and Loss of Gas

Natural gas is a valuable resource that plays a significant role in the U.S. economy and is critical to our energy and national security. Gas that is flared, vented, or leaked into the atmosphere from production on BLM-administered leases is a lost public or tribal resource that is not available for productive use.

In addition, most of the lost gas is not currently subject to royalties, which compensate the public for the removal of publicly owned resources and help fund activities of States, localities, tribes and the Federal Government. State governments receive roughly half of the 12.5 percent royalty that the Federal Government typically collects from onshore oil and gas lessees. The BLM estimates that if captured, the gas presently lost from BLM-administered leases would provide an additional $49 million in royalties each year to the Federal Government, States, and tribes.
81

81
RIA at 3.

This waste of gas through flaring can affect the quality of life for nearby residents, who note that flares are noisy and unsightly at night. Venting, flaring, and leaks of gas also contribute to local, regional, and global air pollution. VOCs and hazardous air pollutants (components of the gas, such as benzene, toluene, ethylbenzene, and xylene) are released into the atmosphere when natural gas is released through venting, flaring, or incomplete combustion at a flare. VOCs combine with sunlight and NO
X
, which are created by burning fossil fuels, to form ground-level ozone, or smog, which causes a wide range of health effects. Benzene and other components of natural gas are also classified as hazardous air pollutants, which are known or suspected to cause cancer or reproductive effects.
82

Flaring of gas produces NO
X
and particulate matter, both of which can cause respiratory and heart problems.
83

82
The EPA has classified benzene as a known human carcinogen and reproductive effects have been reported at high exposures and observed in animal studies. U.S. EPA,
Benzene Hazard Summary (online at: http://www3.epa.gov/airtoxics/hlthef/benzene.html).

83
U.S. EPA,
Nitrogen Dioxide; Health
(online at:
http://www3.epa.gov/airquality/nitrogenoxides/health.html
); U.S. EPA,
Particulate Matter; Health
(online at:
http://www3.epa.gov/pm/health.html
).

Venting and leaks of natural gas in the oil and gas production process also contribute to climate change. Natural gas is primarily composed of methane, which is a potent GHG. Measured over a 100-year time-frame, methane results in more than 20 times more warming than CO
2
, on a ton-per-ton basis. Over a 20-year time-frame, methane is 86 times more potent than CO
2
, according to the most recent report of the Intergovernmental Panel on Climate Change.
84

Venting, flaring, and leaks also produce CO
2
. As the President's Climate Action Plan recognizes, reducing methane emissions can make an important contribution to addressing climate change.
85

84
See Intergovernmental Panel on Climate Change, Climate Change 2013: The Physical Science Basis, Chapter 8,
Anthropogenic and Natural Radiative Forcing,
at 714 (Table 8.7),
available at https://www.ipcc.ch/pdf/assessment-report/ar5/wg1/WG1AR5_Chapter08_FINAL.pdf.

85
The President's Climate Action Plan,
https://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf.
at 10-11 (June 2013)

C. Purpose of This Proposed Rule

The purpose of this proposed rule is to establish a comprehensive framework to give operators on Federal and tribal leases clear direction to minimize waste and losses of natural gas. This proposed rule is necessary because the BLM's existing requirements on venting and flaring are more than 3 decades old, do not reflect technological advances and current scientific understanding, have failed to deter rising losses of gas, fail in some respects to provide clear guidance to BLM staff and oil and gas operators, and do not address leaks from existing and new infrastructure.

This proposed rule would implement statutory directives to avoid waste of oil and gas resources. It would supplement the BLM's regulations contained in 43 CFR 3162.5 and 3162.7, to address prevention of waste of produced natural gas, use of produced oil and gas on a royalty-free basis, and record keeping requirements. It would also update and replace NTL-4A,
86

pertaining to venting and flaring, unavoidably and avoidably lost gas, and waste prevention. The proposed rule would ensure that operators use best practices that minimize waste from new and existing operations.

86
44 FR 76600 (1979). The U.S. Geological Survey (USGS) issued regulations on these subjects in NTL-4A. In the early 1980's, the responsibility for Federal onshore oil and gas operations was transferred from the USGS to the Minerals Management Service (MMS). In 1983, the Secretary transferred the responsibility to the BLM. NTL-4A has remained in force through the changes in agency responsibility.

The BLM recognizes the importance of ensuring that our requirements do not subject operators to conflicting or redundant requirements. In 2012, the EPA adopted air pollution regulations for certain activities in the oil and gas production sector, and the EPA has recently proposed further regulations in that area, which would have the effect of reducing loss of gas. In addition, in response to growing concerns about venting, flaring, and leakage of gas, several States have adopted or are considering regulations to address these issues. The EPA regulations focus largely on new sources, however, and they are directed at pollution reduction, not waste prevention, so they do not address all opportunities to reduce waste. Similarly, none of the States has established a comprehensive set of requirements addressing all of the sources of lost gas that we are considering here, and many States have minimal requirements in this area. We are committed to working closely with State and tribal governments to ensure that the BLM requirements are coordinated with State and tribal requirements to the extent possible. The BLM requirements would not supersede equally effective or more stringent State and tribal requirements. We are also working closely with the EPA to coordinate our requirements, so that operators are not faced with conflicting or duplicative Federal mandates.

D. Stakeholder Outreach

Over several months of last year, the BLM conducted a series of forums to consult with tribal governments and solicit stakeholder views to inform the development of this proposed rule. We held public meetings in Denver, Colorado (March 19, 2014), Albuquerque, New Mexico (May 7,

2014), Dickinson, North Dakota (May 9, 2014), and Washington, DC (May 14, 2014).
87

Each day, we held a tribal outreach session in the morning and a public outreach session in the afternoon. At the Denver, Colorado, and Washington, DC sessions, the tribal and public meetings were live streamed to allow for the greatest possible participation by interested parties. The tribal outreach sessions also served as initial consultation with Indian tribes to comply with Executive Order 13175, Consultation and Coordination with Indian tribal governments.

87
See the BLM oil and gas program's outreach-events page:
http://www.blm.gov/wo/st/en/prog/energy/public_events_on_oil.

As part of our outreach efforts, the BLM accepted informal comments generated as a result of the public/tribal outreach sessions through May 30, 2014. A total of 29 unique comments were received: 12 from the oil and gas industry and trade associations, 6 from NGOs representing 37 organizations, 2 from government officials or elected representatives and 9 from private citizens. Two hundred and sixty comments from private citizens were part of an email campaign.

In addition, the BLM has conducted outreach to States with extensive oil and gas production on BLM-administered leases. We have carefully reviewed State regulations and guidance, and we have contacted State regulatory bodies that oversee aspects of oil and gas production to discuss their requirements and practices. We look forward to continued close interaction with State and tribal regulators.

The proposed rule reflects input gathered from the public meetings, comments, and discussions with States and tribes.

E. Existing BLM Regulations and Requirements for Preventing Natural-Gas Waste

Venting, flaring, and royalty-free uses of oil and natural gas on BLM-administered leases are currently governed by NTL-4A, which was issued by the U.S. Geological Survey on December 27, 1979, before the BLM assumed oversight responsibility for onshore oil and gas development and production. NTL-4A prohibits venting or flaring of gas well gas, and it prohibits venting or flaring of oil well gas unless approved in writing by the “Supervisor.”
88

Both prohibitions are subject to specified exemptions for emergencies, certain equipment malfunctions, certain well tests, and vapors from storage vessels. With respect to venting or flaring of oil well gas, NTL-4A IV.B states:

88
44 FR 76600. (Dec. 27, 1979).

The Supervisor may approve an application for the venting or flaring of oil well gas if justified either by the submittal of (1) an evaluation report supported by engineering, geologic, and economic data which demonstrates to the satisfaction of the Supervisor that the expenditures necessary to market or beneficially use such gas are not economically justified and that conservation of the gas, if required, would lead to the premature abandonment of recoverable oil reserves and ultimately to a greater loss of equivalent energy than would be recovered if the venting or flaring were permitted to continue or (2) an action plan that will eliminate venting or flaring of the gas within 1 year from the date of application.
89

89
Ibid.

Thus, the key criteria under this provision in NTL-4A for approving venting or flaring (and rendering it royalty-free) are: (1) That the expenditures for capture are “not economically justified,”
and
they would “lead to the premature abandonment of recoverable oil reserves”; or (2) The venting or flaring will be eliminated within 1 year.
90

NTL-4A IV.C also provides that “(w)hen evaluating the feasibility of requiring conservation of the gas, the total leasehold production, including both oil and gas, as well as the economics of a field wide plan shall be considered . . . in determining whether the lease can be operated successfully if it is required that the gas be conserved.”
91

90
Ibid.

91
Ibid.

In addition, NTL-4A specifies the circumstances under which an operator owes royalties on oil and gas that is lost from a lease. It provides that gas which is “avoidably lost” is subject to royalties. It defines “avoidably lost” production as produced gas that is vented or flared without the “prior authorization, approval, ratification, or acceptance of the Supervisor,” or lost due to: (1) Negligence; (2) Failure to comply with lease terms, the operating plan, orders or regulations; or (3) “(T)he failure of the lessee or operator to take all reasonable measures to prevent and/or to control the loss.”
92

NTL-4A I further provides that no royalty is due for gas that is: (1) Used on the lease for “beneficial purposes”; (2) Vented or flared with the Supervisor's prior authorization or approval; (3) Vented or flared pursuant to State rules or orders, when such rules have been ratified or accepted by the Supervisor; or (4) Otherwise unavoidably lost, as determined by the Supervisor.
93

92
44 FR at 76600. (Dec. 27, 1979).

93
Ibid.

NTL-4A III. authorizes royalty-free venting or flaring of gas “on a short-term basis” without the need for approval under specified circumstances, including during: (1) Emergencies; (2) Well purging and evaluation tests; and (3) Initial production tests.
94

Venting or flaring is authorized during emergency situations, such as equipment failures, for up to 24 hours per incident and up to 144 cumulative hours per lease per month.
95

NTL-4A III.B. authorizes venting or flaring “(d)uring the unloading or cleaning up of a well during drillstem, producing, routine purging, or evaluation tests, not exceeding a period of 24 hours.”
96

In addition, NTL-4A III.C. authorizes venting or flaring during initial well evaluation tests, for up to 30 days or up to 50 million cubic feet (MMcf) of gas, whichever occurs first.
97

Finally, NTL-4A II.C. provides that gas vapors that are released from storage tanks or other low-pressure vessels are considered to be unavoidably lost, and not subject to royalties, unless the Supervisor determines that their recovery is warranted.
98

94
Ibid.

95
Ibid.

96
Ibid.

97
Ibid.

98
Ibid.

Over the past 36 years since NTL-4A was issued, technologies and practices for oil and gas production have advanced considerably. The development of modern hydraulic fracturing and horizontal drilling techniques has been especially significant. We also now have better technologies for capturing and using gas on-site, detecting leaks, powering equipment, controlling vapors from storage vessels, removing liquids from gas wells, and many other aspects of production. Not surprisingly, NTL-4A neither reflects today's best practices and advanced technologies, nor is particularly effective in requiring their use to avoid waste. In addition, much of NTL-4A relies on broad, generalized directives. As these have been implemented in the decades since NTL-4A was issued, there has been ambiguity and variation regarding the circumstances under which venting or flaring requires prior approval, the circumstances under which venting or flaring is approved, and the circumstances under which royalties are paid on vented and flared gas. There is also some ambiguity regarding what properly constitutes royalty-free on-site use. All of these factors indicate the need to update NTL-4A.

NTL-4A also includes a provision for assessing the full value of avoidably lost gas and gas that is vented or flared without required approval.
99

This provision was subsequently overridden, however, by the later-enacted FOGRMA.
100

Section 308 of FOGRMA states, “Any lessee is liable for royalty payments on oil or gas lost or wasted from a lease site when such loss or waste is due to negligence on the part of the operator of the lease, or due to the failure to comply with any rule or regulation, order or citation issued under this Act or any mineral leasing law.”
101

99
Ibid.

100
30 U.S.C. 1701
et seq.

101
30 U.S.C. 1756.

NTL-4A's “full value” policy has not been enforced since FOGRMA's enactment. The proposed rule would comply with FOGRMA Section 308 and require payment of royalty, rather than full value, on all oil and gas that is avoidably lost.

F. Legal Authority

With this proposed rule, the BLM aims to update the NTL-4A requirements for venting, flaring, and royalty-free uses of oil and natural gas on BLM-administered leases. The BLM's general authority to issue this proposed regulation derives from various statutes applicable to onshore Federal lands and minerals and Indian tribal and allotted lands, principally the MLA, MLAAL, FOGRMA, FLPMA, IMDA, IMLA, and the Act of March 3, 1909.
102

102
See footnote 4.

The MLA rests on the fundamental principle that the public should benefit from mineral production on public lands.
103

A primary instrument for public benefit is the requirement that a lessee return a portion of the proceeds from production to the public through the payment of royalties to Federal, State, and tribal governments. For all competitively issued leases on Federal lands, the MLA requires a royalty “at a rate of not less than 12.5 percent in amount or value of the production removed or sold from the lease.”
104

The BLM is responsible for setting royalty rates and determining the quantity of produced oil and gas that is subject to royalties under the terms and conditions of a Federal lease. The MLA also requires the BLM to: Ensure that lessees “use all reasonable precautions to prevent waste of oil or gas developed in the land”;
105

regulate “all surface-disturbing activities conducted pursuant to any lease issued under (the MLA)”;
106

and “determine reclamation and other actions as required in the interest of conservation of surface resources.”
107

103

See, e.g., California Co.
v.
Udall,
296 F.2d 384, 388 (D.C. Cir. 1961) (noting that the MLA was “intended to promote wise development of . . . natural resources and to obtain for the public a reasonable financial return on assets that `belong' to the public”). The Indian Mineral Leasing Act also had the similar purpose of securing for Indian tribes “the greatest return on their property.”
Kerr-McGee
v.
Navajo Tribe of Indians,
731 F.2d 597, 601 n.3 (internal quotation mark omitted).

104
30 U.S.C. 226(b)(1)(A) and (c)(1); 30 U.S.C. 352 (applying that requirement to leases on acquired land). The same royalty provision is included in the lease instruments for leases of Indian tribal and allotted lands under applicable regulations, although that rate is set at no less than 16-2/3%, absent approval of the Secretary. 25 CFR 211.41, 212.41.

105
30 U.S.C. 225.

106
30 U.S.C. 226(g).

107
Ibid.

In FLPMA, Congress declared it to be the policy of the United States that the BLM should manage the public lands “in a manner that will protect the quality of scientific, scenic, historical, ecological, environmental, air and atmospheric, water resources, and archeological values; . . . preserve and protect certain public lands in their natural condition; . . . provide food and habitat for fish and wildlife; and . . . provide for outdoor recreation and human occupancy and use.”
108

In addition, the BLM is required to manage public lands under principles of multiple use and sustained yield under FLPMA, which include management of the lands without permanent impairment of the quality of the environment.
109

The definition of “multiple use” explicitly includes the consideration of environmental resources; “multiple use” means a “combination of balanced and diverse resource uses that takes into account the long-term needs of future generations for renewable and nonrenewable resources, including, but not limited to, recreation, range, timber, minerals, watershed, wildlife and fish, and natural scenic, scientific, and historical values.”
110

Further, the statutory definition of “multiple use” constitutes management in a “harmonious and coordinated” manner “without permanent impairment to the productivity of the land
and the quality of the environment.
”
111

Significantly, FLPMA admonishes the Secretary to consider “the relative values of the resources and not necessarily . . . the combination of uses that will give the greatest economic return of the greatest unit output.”
112

FLPMA also mandates that the Secretary, “(i)n managing the public lands . . . shall, by regulation or otherwise, take any action necessary to prevent unnecessary or undue degradation of the lands.”
113

108
Ibid. 1701(a)(8).

109
43 U.S.C. 1702(c), 1732(a).

110
Ibid. (emphasis added).

111
Ibid. (emphasis added).

112
Ibid.

113
Ibid. 1732(b).

The proposed rule would supplement BLM onshore lease operations regulations found at part 3160 of Title 43 of the Code of Federal Regulations (CFR). The rule would apply to all BLM-managed leases. The proposed rule would also apply to business agreements entered into by tribes (other than Osage Tribe) and agreements under the IMDA, as consistent with those agreements and with principles of Federal Indian law. Oil and gas agreements entered into under the IMDA may or may not provide for a royalty; if they do, that royalty may or may not be expressed as a percentage of the production “removed or sold from the lease.”

The BLM's authority to require royalty payments derives from the above-quoted provision in the MLA: “A lease shall be conditioned upon the payment of a royalty at a rate of not less than 12.5 percent in amount or value of the
production removed or sold from the lease.
”
114

As established in several judicial decisions, the phrase “production removed or sold from the lease” exempts from royalty payments production that is used on the lease for lease operations.
115

Thus, operators may use oil or gas on the lease royalty-free to support the productivity of the lease. For example, a lessee may use produced gas to power the production infrastructure.

114
30 U.S.C. 226(b)(1)(A) (emphasis added).

115

See Marathon Oil Co.
v.
Andrus,
452 F. Supp. 548, 522-23 (D. Wyo. 1978);
Gulf Oil Corp.
v.
Andrus,
460 F. Supp. 15, 18 (C.D. Cal. 1978).

The proposed rule does not use the terms “beneficial purpose” and “beneficial use,” which are used in NTL-4A. Over the years, those terms appear to have been applied inconsistently within the BLM, creating confusion for some in the industry regarding when production may be used royalty-free. Instead of referencing beneficial purposes or use, the proposed rule would directly address the royalty-free treatment of various uses of lease production, and would identify the situations in which prior written BLM approval would be required for royalty-free treatment.

The BLM, through NTL-4A, has long read the MLA to exempt from royalty payments production that is “unavoidably lost” in the course of production.
116

Under NTL-4A, in

determining when production is unavoidably versus avoidably lost, the BLM has generally considered the technical and economic feasibility of preventing the loss of gas. Under NTL-4A, the BLM deems a loss of gas “avoidable”—and charges associated royalties—if it determines that such loss occurred as a result of: (1) Negligence on the part of the lessee or operator; (2) The failure of the lessee or operator to take all reasonable measures to prevent and/or to control the loss; and/or (3) The failure of the lessee or operator to comply fully with the applicable lease terms and regulations, appropriate provisions of the approved operating plan, or the prior written orders of the BLM.
117

If, on the other hand, the loss of gas is not the result of operator negligence and results from certain specified circumstances, such as emergencies, well tests, and production tests, or if the BLM determines that venting from storage tanks is “warranted,” the BLM deems the loss “unavoidable” and does not charge associated royalties.
118

As discussed below, however, the BLM has not always been consistent in applying this distinction between “unavoidably” and “avoidably” lost gas, creating significant confusion for both operators and regulators. The proposed rule seeks to clarify the distinction, and thereby limit the need for operators to submit, and BLM to process, applications for approval of royalty-free use of gas.

116
44 FR 76600.

117
Ibid.

118
Ibid. at 76,601.

G. Concerns About Loss of Gas Identified Through Oversight

Several oversight reviews have raised concerns about waste of gas, found that the BLM's existing requirements regarding venting and flaring are insufficient, and have identified concerns about royalty-free use of gas. They recommended that the BLM update its regulations and guidance on royalty-free use and waste prevention. These include reviews by the Subcommittee on Royalty Management of the Royalty Policy Committee (RPC), which is a Federal advisory committee to the Department of the Interior; the Inspector General of the Department of the Interior; and the GAO.

The RPC's December 2007 report entitled,
Mineral Revenue Collection from Federal and Indian Lands and the Outer Continental Shelf,
includes specific recommendations to the BLM and the former Minerals Management Service (MMS (which was subsequently divided into ONRR, the Bureau of Ocean Energy Management (BOEM), and the Bureau of Safety and Environmental Enforcement.)) The report emphasized the need for enhanced verification of production accountability, and it recommended that the BLM update relevant pre-1983 (remnant U.S. Geological Survey and MMS) rules. In recognition of those needs, the BLM began a process to implement the recommendations to improve production accountability oversight. This proposed rule—along with other separately proposed rules dealing with site security and oil and gas measurement—responds to recommendations in the RPC's report. A March 2010 report by the Department of the Interior Inspector General also recommended that the BLM clarify its requirements for royalty-free use of gas.
119

119
Department of the Interior, Inspector General,
BLM and MMS Beneficial Use Deductions
(March 2010),
https://www.doioig.gov/sites/doioig.gov/files/2010-I-00171.pdf.

In October 2010, the GAO issued a report entitled,
Federal Oil and Gas Leases—Opportunities Exist to Capture Vented and Flared Gas, Which Would Increase Royalty Payments and Reduce Greenhouse Gases.
For this audit, the GAO examined the amounts of natural gas being vented and flared on Federal oil and gas leases, and evaluated the potential for additional capture of natural gas using available technologies. The GAO also evaluated what the associated potential increases in royalty payments and decreases in GHG emissions would be from any additional gas capture.

The GAO found that “around 40 percent of natural gas estimated to be vented and flared on onshore Federal leases could be economically captured with currently available control technologies.”
120

The GAO further found that “Interior's oversight efforts to minimize these losses have several limitations, including that its regulations and guidance do not address” new capture technologies and some significant sources of lost gas.
121

As the GAO noted, BLM guidance is over 30 years old and does not address venting and flaring reduction technologies that have advanced since it was issued, such as automated plunger lift technologies that reduce the amount of gas vented during liquid unloading operations or low-bleed pneumatic devices that can replace the functions of high-bleed pneumatic devices.
122

120
GAO-11-34, Oct. 2010, 2.

121
Ibid. at 34.

122
Ibid. at 27.

The GAO recommended that “to help reduce venting and flaring of gas by addressing limitations” in the regulations, the “BLM should revise its guidance to operators to make it clear that technologies should be used where they can economically capture sources of vented and flared gas, including gas from liquid unloading, well completions, pneumatic valves, and glycol dehydrators.”
123

The GAO further recommended that the BLM should “assess the potential use of venting and flaring reduction technologies to minimize the waste of natural gas” before production occurs, and that the BLM should consider expanded use of infrared cameras to improve reporting and identify opportunities to minimize lost gas.
124

This proposed regulation responds to these recommendations as well.

123
Ibid. at 34.

124
Ibid. at 34.

In addition, multiple public advocacy organizations have recently raised concerns about the waste of gas in oil and gas production operations, and recent State regulatory actions to reduce venting and flaring indicate that some States share these concerns as well.
125

125
See discussion in Section I.1 of this preamble.

H. Volumes of Lost Natural Gas

1. Data Sources on Lost Gas

While concerns have been growing over rising quantities of lost gas, there is no single definitive estimate on the volume of these losses from Federal and Indian leases. One relevant source of information for estimating the volumes of waste is the Oil and Gas Operations Report Part B (OGOR-B) that producers from BLM-administered leases file each month with ONRR to report quantities of gas removed from their leases. Another key source of information is the EPA Inventory of Greenhouse Gas Emissions and Sinks (2015) (“EPA GHG Inventory”), which is an annual report that estimates the total national GHG emissions and removals associated with human activities across the United States. Additional information is drawn from the EPA Greenhouse Gas Reporting Program (GHGRP), which collects GHG data from large emitting facilities, suppliers of fossil fuels and industrial gases that result in GHG emissions when used. Additional emissions quantification data was presented by ICF in a publication entitled,
Onshore Petroleum and Natural Gas Operations on Federal and Tribal Lands in the United States.
126

With respect to oil and gas production, some of these sources estimate releases of natural gas, while

others estimate methane emissions. Natural gas is primarily composed of methane, however, and translating back and forth between the two types of estimates is a relatively straightforward calculation.

126
ICF, Onshore Petroleum and Natural Gas Operations on Federal and Tribal Lands in the United States (June 2015) (SHORT FORM—ICF 2015).

The data collected by ONRR includes operators' estimates of gas vented and flared-during production from each Federal and Indian lease. These data do not include any estimates of natural gas lost through leaks, or from routine operation of pneumatic devices, storage vessels, compressors, or glycol dehydrators (equipment that circulates the chemical glycol in gas to absorb moisture). In addition, the GAO found that there is variation across BLM offices as to whether operators must report certain other types of natural gas losses on their OGOR-Bs. Specifically, operators varied in whether they included quantities of vented or flared gas where the BLM had authorized the venting or flaring or where the quantities were under the BLM's permissible limits. Operators are also not always required to meter the quantities of vented or flared gas reported on their OGOR-Bs. Instead they may use BLM-approved methods to estimate the quantities to be reported. So while the ONRR data are highly relevant, they provide information about a subset of gas wasted and there is some uncertainty regarding the accuracy of the estimates the data do include. In reviewing these data, the GAO found that they “likely underestimate venting and flaring because they do not account for all sources of lost gas.”
127

127
GAO-11-34, Oct. 2010.

For purposes of this proposed rule, ONRR provided the BLM with 6 years of vented and flared volumes reported on the OGOR-Bs. The data analyzed included gas flared and vented from both oil wells and gas wells from 2009 through 2014. During this period, operators reported that they vented or flared a total of 375 Bcf of natural gas, or about 2.6 percent of the 14.6 Tcf of natural gas that was produced from BLM-administered leases from 2009 through 2014. This is enough natural gas to supply about 5 million households—or every household in the States of Colorado, Montana, New Mexico, Utah, and Wyoming—for 1 year.
128

These data are reported by operators on BLM-administered leases, but the production is actually derived from lands with various ownership patterns. Of the vented and flared gas reported to ONRR, 15.2 percent came from wells extracting only Federal minerals; 9.0 percent from Indian ownership, and 75.8 percent from mixed ownership (some combination of Federal, Indian, fee (private) and State land). While all of the natural gas flared or vented from the Federal and Indian lands categories originates from the Federal and Indian mineral estates, only a portion of the natural gas flared or vented from the mixed ownership category originates from the Federal and Indian mineral estates.

128
Using U.S. Census Bureau Total Households as of 2013 (latest data available).

Data in the EPA GHG Inventory can be used to calculate a more complete estimate of gas losses from venting and leaks from BLM-administered leases, which is discussed in more detail in the Regulatory Impact Analysis (RIA) for this rule. Using data from the GHG Inventory, we estimate that about 167 Bcf of natural gas was released or vented to the atmosphere from all U.S. onshore oil and gas leases in 2013, the most recent year for which estimates are currently available. In that year, production from Federal and Indian leases accounted for 12.7 percent of the U.S. natural gas production and 7.43 percent of the U.S. crude oil production.
129

Because we expect the national emissions level to be generally representative of what we would expect on Federal and Indian lands, we derived emissions estimates largely by applying the Federal and Indian share of production to the national emissions estimate.
130

The analysis of these data sources indicates that roughly 22 Bcf of natural gas was lost from BLM-administered leases through venting and leaks in 2013.

129
Based on updated EIA production crossed against ONRR Federal production data.

130
For additional detail on these calculations, see RIA App. 7.

In addition, the ONRR data indicate that operators reported flaring 76 Bcf of natural gas from BLM-administered leases in 2013 (the most recent year for which data are available). Of this, ONRR estimates that about 44 Bcf was gas from the Federal and Indian mineral estate (as opposed to gas from State or private mineral estates that is being extracted through a well that is producing from a mix of Federal, Indian, State or private mineral estates).
131

131
RIA at 19.

Thus, for purposes of this proposal, our best estimate is that 98 Bcf of natural gas was vented, leaked, or flared from BLM-administered leases in 2013,
132

of which 66 Bcf originated from the Federal and Indian mineral estates.
133

The 66 Bcf of vented or flared gas represents about 2.3 percent of total Federal and Indian production from these leases in 2013, and is enough gas to supply almost 900,000 homes each year.
134

This is consistent with ICF's estimate that fugitive sources, vented emissions and flared emissions from Federal and Indian onshore leases amounted to 66 Bcf of natural gas in 2013.

132
That is, 22 Bcf vented or leaked (per EPA GHG Inventory data), and 76 Bcf flared (per ONRR data).

133
RIA at 3.

134
Based on an estimate of 74 Mcf of gas used per household per year. See footnote 2.

Based on available data, the problem of natural gas loss on BLM-administered leases is also growing. The total amounts of annual reported flaring from Federal and Indian leases increased by 109 percent from 2009 through 2013.
135

During this period, reported volumes of flared oil-well gas increased by 292 percent, while reported volumes of flared gas-well gas decreased by 75 percent.
136

The reduction in flaring at gas wells coincides with the adoption of EPA air pollution requirements limiting emissions from gas wells hydraulically fractured after August 2011.

135
RIA at 201.

136
Ibid.

Another indicator of the increase of flaring on Federal and Indian lands is the increase of applications to vent or flare received by the BLM. In 2005, the BLM received just 50 applications to vent or flare gas. In 2011, the BLM received 622 applications, and this doubled again within 3 years to 1,248 applications in 2014. BLM field offices indicate that most of the additional applications were for flaring in New Mexico, Montana, the Dakotas, and, to a lesser extent, Wyoming.
137

137
BLM data extracted from AFMSS in response to media inquiry, October 2014.

In addition to considering the quantity of gas that is lost now, it is also important to consider the potential future quantities of lost gas, and to evaluate the future sources of such losses. One source of information on this question is a study by ICF entitled,
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries,
issued in March 2014. The ICF Study estimated methane emissions from onshore oil and gas production in 2018 based on a 2011 baseline. It found that absent regulation, emissions are projected to grow 4.5 percent from 2011 through 2018, and almost 90 percent of emissions in 2018 would come from sources that were already operating prior to 2012.
138

Based on this information, the BLM believes that it is important for the proposal to address waste from both new sources and

sources that already exist at the time of the final rule.

138
ICF 2014 Study.

2. Additional Information on Loss Estimates

The BLM developed the emissions estimates discussed in the preamble and RIA using the best data available at the time. Some of the data produced by EPA and ONRR, such as the EPA estimates of the quantities of gas lost through leaks, and emergency releases reported to ONRR by the operators, rely on emissions factors, which have been developed by the EPA. These emissions factors are usually based on representative measured data and are applied to activity data to calculate estimated emissions. The ONRR relies primarily on self-reporting by industry, subject to agency audits.

Annually, EPA reviews new information as it becomes available, and the GHG Inventory continues to be refined to reflect new information available. For example, EPA notes the availability of new da

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2016-01865. Public record. Not legal advice.