[Federal Register Volume 81, Number 25 (Monday, February 8, 2016)]
[Proposed Rules]
[Pages 6616-6686]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-01865]



[[Page 6615]]

Vol. 81

Monday,

No. 25

February 8, 2016

Part II





Department of the Interior





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Bureau of Land Management





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43 CFR Parts 3100, 3160, and 3170





Waste Prevention, Production Subject to Royalties, and Resource 
Conservation; Proposed Rule

  Federal Register / Vol. 81 , No. 25 / Monday, February 8, 2016 / 
Proposed Rules  

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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.

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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: [email protected]. 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 the land . . . .'' 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\
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    \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.
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    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\
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    \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).
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    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

[[Page 6617]]

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 
CO2, if measured over a 100-year period, or 86 times those 
of CO2, 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.
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    \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.
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    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\
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    \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.
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    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\
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    \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.
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    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.
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    \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.
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    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.
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    \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.
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    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

[[Page 6618]]

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.
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    \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.
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    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\
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    \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.
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    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\
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    \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.
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    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

[[Page 6619]]

and cost savings using a 3 percent discount rate).\22\
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    \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.
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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\
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    \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).
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    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).
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    \29\ See proposed 43 CFR 3179.105.
    \30\ Ibid.
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    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

[[Page 6620]]

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.
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    \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.).
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    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 
Sec.  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\
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    \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\
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    \33\ RIA at 60.
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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\
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    \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.
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    The BLM believes that LDAR programs are a cost-effective means of

[[Page 6621]]

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.
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    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\
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    \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

[[Page 6622]]

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.
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    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.
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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\)
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    \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,

[[Page 6623]]

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\
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    \56\ RIA at 87.
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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

[[Page 6624]]

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.
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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 Sec.  3103.3-1, and for ease of reference. The BLM does not 
intend to revise those provisions, nor to invite comment on their 
content.
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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-

[[Page 6625]]

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 (NOX) 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

[[Page 6626]]

    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

[[Page 6627]]

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 NOX, 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 NOX 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 
CO2, on a ton-per-ton basis. Over a 20-year time-frame, 
methane is 86 times more potent than CO2, according to the 
most recent report of the Intergovernmental Panel on Climate 
Change.\84\ Venting, flaring, and leaks also produce CO2. As 
the President's Climate Action Plan recognizes, reducing methane 
emissions can make an important contribution to addressing climate 
change.\85\
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    \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,

[[Page 6628]]

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.

[[Page 6629]]

    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

[[Page 6630]]

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

[[Page 6631]]

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

[[Page 6632]]

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 data in its 
GHG Inventory, including data and information that are becoming 
available through EPA's GHGRP and external studies, allowing EPA to re-
evaluate and make updates to GHG Inventory data, as applicable.
    Several recently completed academic studies aim to improve our 
understanding of the quantity of natural gas and petroleum system 
emissions, and more such studies are underway. In general, there are 
two major types of studies related to oil and gas GHG data: So-called 
``bottom up'' studies that focus on measurement or quantification of 
emissions from specific activities, processes, and equipment (e.g., 
EPA's Greenhouse Gas Reporting Program data and many of the series of 
studies being conducted by the Environmental Defense Fund, academic 
researchers, and industry, discussed below), and ``top down'' studies 
that focus on verification of estimates at the regional scale through 
methods such as airborne mass balance, atmospheric transport models, 
and enhancement ratios with well-constrained pollutants, along with 
approaches such as inverse modeling (e.g., National Oceanic and 
Atmospheric Administration (NOAA) verification studies), which measure 
atmospheric levels of emissions and attempt to allocate contribution 
among potential sources. The first type of study can lead to direct 
improvements to or verification of inventory estimates. The second type 
of study can provide general indications of potential over- and under-
estimates in existing data. Several of these recent studies are 
discussed below.
    An article published last year in the peer-reviewed journal Science 
reviewed 20 years of technical literature on natural gas emissions in 
the U.S. and Canada and compared various emissions estimates from top 
down (e.g., aircraft) and bottom up (e.g., inventory) studies. The 
authors found that inventories consistently underestimate actual 
methane emissions.\139\ Similarly, a study published in May 2014 by 
researchers from NOAA and the University of Colorado, Boulder, 
estimated methane emissions from oil and gas production areas using 
atmospheric hydrocarbons gathered while flying over the Denver-
Julesberg Basin. This study estimated that hourly methane emissions 
from oil and gas sources in that basin are three times higher than 
would be expected based on estimates derived from data reported under 
the EPA GHGRP.\140\
---------------------------------------------------------------------------

    \139\ A. R. Brandt et al., Methane Leaks from North American 
Natural Gas Systems, Science, 733 (Feb. 14, 2014), http://www.sciencemag.org/content/343/6172/733.full.
    \140\ Gabrielle P[eacute]tron et al., A new look at methane and 
nonmethane hydrocarbon emissions from oil and natural gas operations 
in the Colorado Denver-Julesburg Basin, Journal of Geophysical 
Research: Atmospheres, 6836 (June 3, 2014), http://onlinelibrary.wiley.com/doi/10.1002/2013JD021272/pdf.
---------------------------------------------------------------------------

    Beginning in 2012, the Environmental Defense Fund began working 
with about 100 universities, research institutions and companies on a 
multi-pronged scientific research effort to develop a clearer picture 
of methane losses across the U.S. natural gas supply chain. Several 
studies from this effort, in addition to the NOAA and Science studies 
discussed above, are particularly relevant to this rulemaking.
    For example, researchers at the University of Texas, Austin, in 
Phase 1 of their production studies, published in September 2013, found 
that methane emissions from equipment leaks and pneumatic devices were 
larger than previously thought.\141\ The study focused on methane 
emissions at 190 sites (focusing on ongoing production activity and 
well completion emissions) operated by nine natural gas companies. It 
also found that emissions from well completions were smaller than 
previously thought (apparently due to the EPA's requirement for reduced 
emission completions, which can reduce venting from well completions by 
99 percent).\142\ Phase II of the study, which looked at wells operated 
by 10 companies, found that for emissions from liquids unloading and 
pneumatic devices, a small percentage of sources account for the 
majority of the emissions from these categories.\143\ Nineteen percent 
of pneumatic devices produced 95 percent of the emissions that were 
attributable to the devices, while 20 percent of wells that vented 
during liquids unloading produced 65 to 83 percent of the emissions 
from those sources.\144\ The study further found that average emissions 
from pneumatic controllers are higher than EPA's previous estimates, 
which are the basis for the emissions factors used in calculating gas 
waste.\145\
---------------------------------------------------------------------------

    \141\ David T. Allen et al., Measurements of Methane Emissions 
at Natural Gas Production Sites in the United States, 17768 (Oct. 
2013), The Proceedings of the National Academy of Sciences of the 
United States of America, 17768 (Oct. 2013), http://www.pnas.org/content/110/44/17768.full.pdf.
    \142\ Ibid, 17769-70.
    \143\ David T. Allen et al., Methane Emissions from Process 
Equipment at Natural Gas Production Sites in the United States: 
Pneumatic Controllers, 636 (Dec. 9, 2014), Environmental Science and 
Technology, available at http://pubs.acs.org/doi/abs/10.1021/es5040156.
    \144\ Ibid.
    \145\ Ibid. at 638.
---------------------------------------------------------------------------

    A February 2015 study from Colorado State University, entitled 
Measurements of Methane Emissions from Natural Gas Gathering Facilities 
and Processing Plants: Measurement Results,\146\ found wide variations 
in the amount of methane leaking at gathering and processing 
facilities. Another study, Analyzing Methane Emissions from Upstream 
Oil and Gas Production Operations,\147\ conducted by researchers at the 
Houston Advanced Research Center and the EPA, analyzed fence line data 
on methane emissions at well production sites. It found that 
unpredictable events, such as malfunctions and leaks, likely have a 
strong influence on emissions rates.\148\ In addition, a recent study 
questions the accuracy of the sampler used in the University of Texas 
and other studies. The new study, published in the journal Energy 
Science & Engineering, asserts that the University of Texas researchers 
used a sampler that can fail under certain conditions, leading to 
``severe'' underreporting of natural gas emissions.\149\ Other sources 
of information also reinforce concerns about the volumes of lost gas. 
In October 2014, an analysis of satellite measurements from 2002-2012 
by

[[Page 6633]]

scientists from the National Aeronautics and Space Administration 
(NASA) and the University of Michigan identified a 2,500-square-mile 
(about half the size of the State of Connecticut) concentration of 
methane located over the Four Corners area in Arizona, Colorado, New 
Mexico, and Utah.\150\ The study's lead author indicated that the 
emissions likely come from natural gas production and processing 
equipment (although not from hydraulic fracturing, as much of the data 
predates its upsurge) in the San Juan Basin in New Mexico, which 
produces natural gas from conventional gas production, oil production, 
and coalbed methane.\151\
---------------------------------------------------------------------------

    \146\ Austin L. Mitchell et al., Measurements of Methane 
Emissions from Natural Gas Gathering Facilities and Processing 
Plants: Measurement Results, 3219 (Feb. 2015), Environmental Science 
and Technology, available at http://pubs.acs.org/doi/abs/10.1021/es5052809.
    \147\ Birmur Guven et. al., Analyzing Methane Emissions from 
Upstream Oil and Gas Production Operations, (Nov. 2014).
    \148\ Ibid.
    \149\ Howard, Touch[eacute], University of Texas study 
underestimates national methane emissions at natural gas production 
sites due to instrument sensor failure, Energy Science & Engineering 
(Aug. 4, 2015).
    \150\ NASA news release, Oct. 9, 2014 available at http://www.nasa.gov/press/2014/october/satellite-data-shows-us-methane-hot-spot-bigger-than-expected/#.VLbQ0PnF9sE.
    \151\ Ibid.
---------------------------------------------------------------------------

    On the other hand, another recent study found that methane 
measurements taken by aircraft in some natural gas production basins 
track well with the EPA's GHG Inventory estimates.\152\ Data indicate 
that emissions from gas production activities vary from basin to basin. 
This variation may be due to characteristics of the natural gas, the 
amount of natural gas processing that is necessary, and the condition 
of the natural gas gathering, compression and transportation system. 
Also, some of the older studies may tend to overestimate current losses 
in some respects, as recent EPA and State regulations, as well as 
voluntary actions by industry, have substantially reduced the volumes 
of gas lost from some sources, such as gas well completions.
---------------------------------------------------------------------------

    \152\ Jeff Peischl, T. B. Ryerson, K. C. Aikin, J. A. de Gouw, 
J. B. Gilman, J. S. Holloway, B. M. Lerner, R. Nadkarni, J. A. 
Neuman, J. B. Nowak, M. Trainer, C. Warneke, D. D. Parrish, 
Quantifying atmospheric methane emissions from the Haynesville, 
Fayetteville, and northeastern Marcellus shale gas production 
regions, Journal of Geophysical Research: Atmospheres, 120 (5), pp. 
2119-2139.
---------------------------------------------------------------------------

    Most recently, a new study by Zavala et al., published in the 
Proceedings of the National Academy of Sciences, developed new 
techniques to reconcile bottom up and top down estimates of methane 
emissions from oil and gas production in the Barnett Shale region in 
Texas.\153\ This study found that in this region, methane emissions 
from oil and gas production and processing are almost twice as high as 
would be estimated based on the EPA GHG Inventory, and are 3.5 times 
higher than would be estimated based on EPA GHGRP data.\154\ It further 
found that the emissions from these sources in this region are 
dominated by a relatively small number of high emitters, with, at any 
given time, 2 percent of the facilities contributing half of the 
emissions, and 10 percent contributing 90 percent of the 
emissions.\155\
---------------------------------------------------------------------------

    \153\ Zavala-Araiza et al., Reconciling divergent estimates of 
oil and gas methane emissions, Proceedings of the National Academy 
of Sciences, vol. 112, no. 51, 15597-15602 (Dec. 22, 2015).
    \154\ Ibid. at 15599.
    \155\ Ibid. at 15600.
---------------------------------------------------------------------------

    The BLM expects that additional studies will use bottom-up and top-
down data comparisons to continue to refine emissions estimates for 
these sources. The presence, distribution, and effect of super-
emitters, which are often defined as sources with exceptionally high 
emissions as compared to similar sources (essentially malfunctioning 
equipment), is also being further studied. Overall, these studies and 
alternative sources of data suggest that the BLM's estimates of lost 
gas likely underestimate, and potentially substantially underestimate, 
the extent of the problem.

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

1. State Activities
    In developing the proposed rule, we have consulted with State 
regulators and reviewed State requirements related to waste of oil and 
gas resources. Like the MLA, most State laws and regulations prohibit 
or encourage prevention of waste of these resources. But specific State 
requirements, and the outcomes they produce, vary widely. This 
variability reinforces the need for this rule to update standards for 
oil and gas operations on Federal and Indian lands. In developing the 
proposed rule, we also looked to some of the most effective State 
approaches as models. In particular, we have drawn on new requirements 
recently adopted by Colorado and North Dakota to address rising rates 
of flaring, resource losses, and other impacts. Below we summarize how 
several States have approached these issues.
(a) Alaska
    The State of Alaska adopted regulations in the 1970s to address 
high rates of flaring.\156\ Since then, the State has prohibited 
venting or flaring of gas except in narrowly defined circumstances: 
Testing a well before regular production; fuel that maintains a 
continuous flare; de minimis venting of gas incidental to normal oil 
field operations; and flaring or venting gas for no more than 1 hour 
during an emergency or operational upset.\157\ The practical effect of 
this prohibition has been widespread reinjection of associated gas into 
the field for conservation and oil recovery purposes.\158\ Alaska 
estimates that roughly 0.4 percent of gas production is flared, which 
is far lower than in most other States.\159\
---------------------------------------------------------------------------

    \156\ Alaska Administrative Code Title 20--Chapter 25 235, Gas 
Disposition, available at http://doa.alaska.gov/ogc/Regulations/RegIndex.html.
    \157\ Ibid.
    \158\ Telephone call with BLM staff and State of Alaska, Oil and 
Gas Conservation Commission (April 30, 2015).
    \159\ Ibid.
---------------------------------------------------------------------------

(b) Colorado
    The State of Colorado has reduced venting and flaring through air 
quality regulations directed at emissions of hydrocarbons and VOCs from 
the oil and natural gas industry.\160\ The Colorado Department of 
Public Health and Environment, Air Quality Control Commission has 
instituted regulations similar in many ways to the EPA's existing NSPS 
for new and modified hydraulically fractured gas wells and gas 
processing facilities.\161\ The Colorado regulation includes some 
aspects of EPA's NSPS, and expands on the EPA standards in other areas. 
For example, the Colorado rule requires reduced emissions completions 
for most oil and gas well completions and recompletions, whereas EPA's 
NSPS currently applies only to hydraulically fractured or refractured 
gas well completions in developed gas fields. Colorado has also adopted 
some requirements that are independent of the EPA NSPS. For instance, 
under the reduced emissions completion process, operators must minimize 
venting ``to the maximum extent practicable.'' \162\
---------------------------------------------------------------------------

    \160\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, Control of Ozone via Ozone Precursors and Control of 
Hydrocarbons via Oil and Gas Emissions (Emissions of Volatile 
Organic Compounds and Nitrogen Oxides).
    \161\ For further information about EPA's NSPS standards for 
this source category, see Section IV.I.3 of this preamble below.
    \162\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9, Sections XII, XVIII.
---------------------------------------------------------------------------

    In addition to requiring green completions, Colorado's rules: 
Establish requirements for pneumatic controllers;\163\ require a 
comprehensive LDAR program;\164\ set standards for liquids 
unloading;\165\ establish emission standards for storage vessels;\166\ 
and require storage tank emissions management (STEM) plans, which would 
identify strategies to minimize emissions from storage vessels during 
normal operations.\167\ BLM has several memoranda of understanding with 
the Colorado Oil and Gas Conservation

[[Page 6634]]

Commission regarding permitting, inspection, and enforcement relating 
to oil and gas activities on BLM lands.\168\
---------------------------------------------------------------------------

    \163\ Ibid. at Section XVIII.
    \164\ Ibid. at Section XVII.F.
    \165\ Ibid. at Section XVII.H.
    \166\ Ibid. at Sections XII.D-F; XVII.C.
    \167\ Ibid. at Section XVII.C.2.
    \168\ The MOUs are available at http://cogcc.state.co.us/gov.html#/federal.
---------------------------------------------------------------------------

(c) Montana
    The State of Montana has had limits on venting and flaring in place 
since the 1970s. Produced gas vented to the atmosphere at a rate 
exceeding 20 Mcf per day that continues for more than 72 hours must be 
burned.\169\ After completion of a gas well, no gas may be permitted to 
escape, except gas required for periodic testing or cleaning of the 
well bore.\170\ If, after well completion, the operator intends to 
flare gas production in excess of 100 Mcf per day, the operator must 
obtain a variance from the oil and gas board.\171\ The operator must 
submit a production test and a statement justifying the need for a 
variance, including information such as potential human exposure; 
relative isolation of location; measures to restrict public access to 
the location; low gas volume; and low BTU content.\172\ The board may 
elect to restrict production until the gas is marketed or otherwise 
beneficially used.\173\
---------------------------------------------------------------------------

    \169\ Administrative Rules of Montana, Section 36.22.1221(1).
    \170\ Ibid. at 36.22.1219.
    \171\ Ibid. at 36.22.1220(1-2).
    \172\ Ibid. at 36.22.1221(2).
    \173\ Ibid. at 36.22.1221(3).
---------------------------------------------------------------------------

(d) North Dakota
    North Dakota has experienced a rapid increase in oil production in 
recent years. A byproduct of this development is more natural gas being 
produced than can be processed and transported to market through 
existing pipeline infrastructure. Without access to a market, much of 
the associated natural gas continues to be flared.
    In March 2013, the North Dakota Industrial Commission adopted a 
policy to reduce flaring, and it followed this with an enforceable 
order adopted in July 2014 and modified in September 2015.\174\ The 
policy and order require well operators to meet flaring reduction 
targets according to a prescribed time line.\175\ The gas capture 
requirements for each operator include a target of capturing at least 
74 percent of production by October 2014.\176\ The target then rises 
over time to a target of capturing at least 91 percent of production by 
October 2020.\177\ The operator may show compliance with the target at 
each well, or on a field, county, or statewide basis.\178\
---------------------------------------------------------------------------

    \174\ North Dakota Industrial Commission Order No. 24665 (July 
1, 2014), available at https://www.dmr.nd.gov/oilgas/or24665.pdf; 
North Dakota Industrial Commission Order No. 24665 Policy/Guidance 
Version 102215, available at https://www.dmr.nd.gov/oilgas/GuidancePolicyNorthDakotaIndustrialCommissionorder24665.pdf.
    \175\ Ibid.
    \176\ Ibid.
    \177\ Ibid.
    \178\ Ibid.
---------------------------------------------------------------------------

    North Dakota's policy includes additional requirements intended to 
help operators reach the targets.\179\ One component of the policy 
requires that all applications for permits to drill be accompanied by 
gas capture plans.\180\ The State's goal is to ensure that options for 
capturing any natural gas discovered are fully evaluated before a well 
is drilled. North Dakota also requires the gas capture plan to be 
provided to midstream processing companies so they can plan 
accordingly.\181\
---------------------------------------------------------------------------

    \179\ Ibid.
    \180\ Ibid.
    \181\ Ibid.
---------------------------------------------------------------------------

    The policy provides for oil production to be restricted from wells 
where the operator does not meet the flaring reduction targets.\182\ 
Production is restricted to no more than 200 bbl of oil per day for 
those wells capturing more than 60 percent of the gas production, but 
less than the applicable target percentage.\183\ Production is 
restricted to no more than 100 bbl of oil per day from those wells 
capturing less than 60 percent of produced gas.
---------------------------------------------------------------------------

    \182\ Ibid.
    \183\ Ibid.
---------------------------------------------------------------------------

(e) Pennsylvania
    In August 2013, the Pennsylvania Department of Environmental 
Protection issued guidance that exempted from certain air quality 
permitting requirements oil and gas exploration, development, and 
production facilities and associated equipment and operations that 
implemented the following: An LDAR program consistent with relevant EPA 
regulations; VOC emission controls on all storage tanks; a 2.7 tpy 
limit on VOC emissions from all facility sources; certain limitations 
on flaring activities; and hourly, daily, seasonal, and annual limits 
on NOx emissions.\184\
---------------------------------------------------------------------------

    \184\ Pennsylvania Department of Environmental Protection, Air 
Quality, Air Quality Permit Exemptions, http://www.elibrary.dep.state.pa.us/dsweb/Get/Document-96215/275-2101-003.pdf (August 10, 2013) at 8-11.
---------------------------------------------------------------------------

(f) Utah
    The Utah Department of Environmental Quality issued a General 
Approval Order on June 5, 2014, that applies to new and modified oil 
and gas well sites and tank batteries. Among other provisions, this 
order requires pneumatic controllers to be low bleed or route the 
emissions to a flare or capture device; pneumatic pumps route emissions 
to a flare or capture device; and requires operators to inspect for 
leaks at least annually, and more frequently for sources with greater 
throughput levels.\185\
---------------------------------------------------------------------------

    \185\ State of Utah, Department of Environmental Quality, 
Division of Air Quality, Approval Order: General Approval Order for 
a Crude Oil and Natural Gas Well Site and/or Tank Battery, DAQE-
AN1492500001-14 (June, 5, 2014).
---------------------------------------------------------------------------

(g) Wyoming
    The Wyoming Department of Environmental Quality adopted regulations 
in June 2015, to reduce emissions of VOCs from storage vessels, 
pneumatic controllers, pneumatic pumps, glycol dehydrators, and leaks 
in the Upper Green River Basin nonattainment area.\186\ Among other 
things, the rule requires emissions from vessels with uncontrolled VOC 
emissions from flashing of 4 tpy or more to be controlled by 98 
percent,\187\ emissions from pneumatic pumps to be controlled by 98 
percent,\188\ high-bleed pneumatic controllers to be replaced with low-
bleed controllers,\189\ and operators to establish LDAR programs with 
at least quarterly inspections.\190\
---------------------------------------------------------------------------

    \186\ Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015), 
available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.
    \187\ Ibid. at Section 6(c)(i)(A).
    \188\ Ibid. at Section 6(e).
    \189\ Ibid. at Section 6(f).
    \190\ Ibid. at Section 6(g).
---------------------------------------------------------------------------

2. Voluntary Industry Efforts
    The oil and gas industry has also recognized concerns about the 
rising quantities of flared and vented gas, and has begun to take 
voluntary steps to reduce gas losses. For example, oil and gas 
companies developed the technologies for green completions.\191\ 
Individual companies voluntarily use some of the approaches proposed 
here to reduce their natural gas losses through venting, flaring, and 
leaks and boost profitability.
---------------------------------------------------------------------------

    \191\ See, e.g., EPA, Lessons Learned from Natural Gas STAR 
Partners, Reduced Emissions Completions for Hydraulically Fractured 
Natural Gas Wells, available at http://www3.epa.gov/gasstar/documents/reduced_emissions_completions.pdf.
---------------------------------------------------------------------------

    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. Partners 
in this program have

[[Page 6635]]

pioneered some of what are now the most widely-used, innovative 
technologies and practices to reduce methane emissions. These include 
green completions for hydraulically fractured wells, artificial lift 
systems for well maintenance, pneumatic controllers and pumps with no 
or low gas releases, and infrared cameras for leak detection. Natural 
Gas STAR partners from the oil and gas production sector reported that 
they achieved about 50 Bcf of methane emissions reductions in 
2013.\192\
---------------------------------------------------------------------------

    \192\ EPA Natural Gas STAR, Accomplishments, http://www3.epa.gov/gasstar/accomplishments/index.html.
---------------------------------------------------------------------------

    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.\193\
---------------------------------------------------------------------------

    \193\ EPA Natural Gas Star Methane Challenge, Program Proposal, 
http://www3.epa.gov/gasstar/methanechallenge/index.html.
---------------------------------------------------------------------------

    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.'' 
\194\ These companies aim ``to develop yearly, sliding-scale emission 
intensity goals for the entire value chain and each sector within the 
value chain,'' and use a flexible approach to achieve reductions.\195\
---------------------------------------------------------------------------

    \194\ International Business Times, ``Six Major Oil and Gas 
Firms Agree to Cut Potent Methane Emissions Ahead of UN Climate 
Change Summit, (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.
    \195\ Our Nation's Energy (ONE) Future Coalition, http://
www.gastechnology.org/CH4/Documents/fiji-George-CH4-presentation-
Sep2014.pdf.
---------------------------------------------------------------------------

3. EPA Air Quality Requirements
    While EPA does not regulate waste of oil and gas resources, certain 
air pollution regulations applicable to the oil and gas production 
sector have the co-benefit of also reducing waste of natural gas. 
Because the air pollutants regulated by EPA are contained in natural 
gas, many of the control options for reducing emissions operate by 
limiting the release (and hence loss) of natural gas. To the extent 
that EPA rules under the Clean Air Act address some aspects of the 
waste issue, the BLM intends to coordinate its requirements with the 
EPA as far as possible, to ensure that industry is not burdened by 
duplicative or conflicting requirements. The EPA rules will include 
both standards that EPA adopted in 2012, which are largely focused on 
natural gas wells and infrastructure, and the 40 CFR part 60 subpart 
OOOOa rulemaking, which addresses additional categories of new and 
modified sources in the oil and gas production sector.
    In 2012, EPA adopted NSPS to limit the release of VOCs from new and 
modified hydraulically-fractured natural gas wells, certain new or 
modified sources located at well sites, natural gas processing plants, 
or natural gas gathering and boosting stations.\196\ These standards 
require new hydraulically fractured gas wells to use a process termed a 
``reduced emission completion'' or ``green completion'' to capture 
natural gas that would otherwise be released in the well-completion 
process.\197\ EPA estimated that this requirement reduces VOC emissions 
from the hydraulic fracturing process by 95 percent.\198\ EPA allows 
for flaring instead of green completions for new exploratory or 
delineation wells, on the assumption that these types of wells are 
generally not near pipeline infrastructure to transport captured gas. 
EPA also does not require green completions for wells where there is 
not sufficient pressure to route the gas to a gathering line, instead 
allowing operators to flare the gas that would otherwise be released.
---------------------------------------------------------------------------

    \196\ U.S. EPA, Oil and Natural Gas Sector: New Source 
Performance Standards and National Emission Standards for Hazardous 
Air Pollutants Reviews; Final Rule, 77 FR 49490 (Aug. 16, 2012).
    \197\ 40 CFR 60.5375.
    \198\ U.S. EPA, Overview of Final Amendments to Air Regulations 
for the Oil and Natural Gas Sector, Fact Sheet, available at http://www3.epa.gov/airquality/oilandgas/pdfs/20120417fs.pdf.
---------------------------------------------------------------------------

    The 2012 standards also require operators to use certain types of 
new and modified equipment at natural gas processing plants and 
gathering and boosting stations. The standards limit VOC emissions from 
centrifugal compressors and establish maintenance requirements for 
reciprocating compressors.\199\ The standards also apply to new and 
modified high-bleed pneumatic controllers powered by natural gas, which 
are defined as pneumatic controllers that emit more than 6 scf/
hour.\200\ The standards limit the bleed rate for pneumatic controllers 
at well sites and gathering and boosting stations to 6 scf/hour, and 
they require zero VOC emissions from pneumatic controllers located at 
processing plants.\201\ In practice, this standard requires operators 
to replace high-bleed pneumatic controllers with low-bleed or no-bleed 
devices. New, modified, and reconstructed storage vessels at these 
locations (including well sites) are also covered by the 2012 
requirements.\202\ They require new storage vessels with VOC emissions 
of at least 6 tpy to reduce those emissions by at least 95 
percent.\203\ In addition, the 2012 standards strengthened existing 
leak detection standards for natural gas processing plants.\204\
---------------------------------------------------------------------------

    \199\ 40 CFR 60.5380; 40 CFR 60.5385.
    \200\ 40 CFR 60.5390.
    \201\ Ibid.
    \202\ 40 CFR 60.5395.
    \203\ Ibid.
    \204\ 40 CFR 60.5400.
---------------------------------------------------------------------------

    On September 18, 2015, EPA published a notice of proposed 
rulemaking that proposes NSPS standards to be codified as 40 CFR part 
60 subpart OOOOa.\205\ The EPA proposes to establish both methane and 
VOC standards for several emission sources not covered by the 2012 
NSPS, including hydraulically fractured oil well completions, pneumatic 
pumps, and fugitive emissions from well sites and compressor stations. 
In addition, the EPA proposed methane standards for certain emission 
sources that are currently regulated for VOCs but not for methane, and 
proposed to extend VOC standards and create methane standards for 
equipment used widely in the industry.\206\
---------------------------------------------------------------------------

    \205\ 80 FR 56593, Sept. 18, 2015.
    \206\ Ibid.
---------------------------------------------------------------------------

    In addition, the EPA proposed to issue Control Technique Guidelines 
(CTGs), which States could adopt in nonattainment areas to reduce 
methane emissions from existing sources in the oil and gas production 
sector.\207\
---------------------------------------------------------------------------

    \207\ Ibid.
---------------------------------------------------------------------------

4. Need for BLM Requirements
    While the proposed EPA standards are expected to reduce methane 
emissions from certain new and modified oil and gas production 
facilities, they would not be sufficient to meet the goals of BLM's 
proposed rule for several reasons. First, the proposed EPA regulations 
do not include any provisions to reduce flaring of associated gas 
during normal production operations. Second, even with respect to the 
natural gas waste from venting, the EPA regulations would apply only to 
new and modified sources, whereas this proposal would reach existing 
sources as well. In States that choose to adopt the CTGs, those 
guidelines would apply to existing sources, but the guidelines are 
designed to reduce emissions in nonattainment

[[Page 6636]]

areas, and very little oil and gas is produced from BLM-administered 
leases in such areas. Third, because the EPA's legal authorities differ 
from those of the BLM, the proposed EPA regulations do not cover all 
BLM-regulated activities, such as well maintenance and liquids 
unloading.
    Similarly, of the States with extensive oil and gas operations on 
BLM-administered leases, only one has comprehensive requirements to 
reduce flaring, and only one has comprehensive statewide requirements 
to control losses from venting and leaks. Moreover, State regulations 
do not apply to BLM-administered oil and gas leases on Indian lands, 
and States do not have a statutory mandate to reduce waste of Federal 
oil and gas.
    In addition, the BLM has regulated oil and gas operations on 
Federal and Indian leases for decades to prevent waste, conserve 
resources, and protect public lands. The BLM has the responsibility and 
experience to ensure that these valuable public resources are extracted 
in a safe manner, while minimizing harm to local communities and the 
environment and ensuring fair returns to Federal taxpayers and tribes. 
We have existing requirements that are intended to serve these 
purposes, but NTL-4A is over 3 decades old and is no longer adequate in 
meeting these goals. Thus, the proposed rule would update NTL-4A, and 
would do so in coordination with the concurrent EPA rulemaking. In 
addition, the proposed rule would make provision for State and tribal 
programs that address flaring or venting.

V. Discussion of the Proposed Rule

    The proposed rule would require operators to limit waste of gas 
through flaring and venting, clarify the situations in which flared gas 
would be subject to royalties, conform the royalty terms applicable to 
competitive leases with the corresponding statutory language, and 
clarify the on-site uses of gas that are exempt from royalties. In 
addition, the BLM is proposing to require operators to record and 
report information related to venting and flaring of gas, and is taking 
comment on how best to make this information more available to the 
public. This section of the preamble also includes a discussion of how 
today's proposal relates to the planning process for lands subject to 
BLM administration, although this rule would not make any regulatory 
changes to the planning process itself.

A. Measures To Reduce Waste

    The BLM has identified several key points in the production process 
where waste-prevention actions would be most effective and least 
costly. Specifically, we propose to focus on reducing waste from the 
following: Flaring of associated gas from producing 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 
storage vessels; well maintenance and liquids unloading; and well 
drilling and completions. Based on the available data regarding methane 
emissions and the numbers and types of sources of gas losses from 
Federal and Indian leases, we believe that these aspects of the 
production process offer the best opportunities for reducing waste.
    To the extent that EPA completes regulations that would have the 
effect of reducing waste from these sources, the BLM proposes to take 
EPA's requirements into account in finalizing this proposed rule to 
avoid conflict or burdensome duplication.
    In addition, the BLM requests public comments on the scope of this 
proposed rule, including whether there are other aspects of the 
production process that might provide sufficient opportunities for 
economical and cost-effective waste reduction to warrant inclusion in 
this regulation. We also request comment on whether we could achieve 
additional economical and cost-effective waste reduction from any of 
the sources of waste that we are addressing here. In addition, we 
request comment on the cost-effectiveness of the changes we are 
proposing to each aspect of the production process, taking into account 
the full range of private and public benefits achieved through waste 
reduction. We also request comment on how we could lower costs of the 
measures that we are proposing here.
1. Venting or Flaring of Associated Gas From Producing Oil Wells.
    As discussed earlier in Section II.H. of this preamble, operators 
currently vent gas under some circumstances, and they also flare large 
quantities of natural gas that is produced at oil wells (commonly 
called ``associated gas'' or ``casinghead gas''). Operators have an 
economic incentive to capture and sell the flared gas, or to use it on-
site. Nonetheless, substantial flaring occurs under a variety of 
circumstances.
(a) Quantities of Gas Vented or Flared
    BLM analysis of ONRR data shows that operators reported venting 
about 22 Bcf and flaring at least 76 Bcf of natural gas from BLM-
administered leases in 2013 (with about 44 Bcf estimated to be Federal 
and Indian minerals).\208\ Of that total volume of flared gas, 71 Bcf 
was flared oil-well gas while about 5 Bcf was flared gas-well gas. Most 
of the flared oil-well gas volume appears to be associated gas flaring, 
with the balance coming from other sources such as well testing and 
emergency flaring. Flared gas represents 2.6 percent of the total gas 
production from BLM-administered leases in 2013, enough to supply over 
1 million households.\209\
---------------------------------------------------------------------------

    \208\ RIA at 3.
    \209\ Based on an estimate of 74 Mcf of gas used per household 
per year. See footnote 2.
---------------------------------------------------------------------------

    According to ONRR data, 91 percent of flared oil-well gas from BLM-
administered leases occurred in three States: North Dakota, South 
Dakota, and New Mexico. In 2013, the volumes of flared oil-well gas 
from BLM-administered leases in these States were about 42 Bcf, 15 Bcf, 
and 8 Bcf, respectively.\210\ The data also show that these volumes 
have increased dramatically since 2009, while oil production increased 
in North Dakota and either remained relatively constant or declined in 
New Mexico and South Dakota. For example, between 2009 and 2013, flared 
oil-well gas in New Mexico increased by 2.3 percent, even as oil 
production decreased by 3 percent, and in South Dakota flaring 
increased by 1.3 percent even as oil production fell by 45 
percent.\211\ Meanwhile, the increase in oil-well gas flaring in North 
Dakota appears to have tracked closely with the increase in oil 
production (each increased by roughly 350 percent over that 
period).\212\
---------------------------------------------------------------------------

    \210\ RIA at 203.
    \211\ Ibid.
    \212\ Ibid.
---------------------------------------------------------------------------

(b) Technologies To Address Flaring
    The primary means to avoid flaring of 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 wells. While industry 
continues to reduce the cost and improve the reliability of this 
technology, it is long-established and well understood. The capture and 
sale of associated gas can pay for itself where there is sufficient gas 
production relative to costs of connecting to or expanding existing 
infrastructure. The costs of installing equipment and pipelines for 
capture and transport can range from $400,000 to $1 million per mile 
for a 4-inch natural gas pipeline.\213\ In some cases, line capacity 
can be

[[Page 6637]]

increased by adding more compressors to boost pressure. Similarly, 
industry has long used some of this gas on-site to pneumatically 
control equipment or fuel various types of equipment, including such 
items as drilling rigs, artificial lift equipment or heater/treater 
equipment.
---------------------------------------------------------------------------

    \213\ Pipeline and Gas Journal, Billions Needed to Meet Long-
Term Natural Gas Infrastructure Supply, Demands (April 2009) http://pipelineandgasjournal.com/billions-needed-meet-long-term-natural-gas-infrastructure-supply-demands?page=4.
---------------------------------------------------------------------------

    In addition, the recent increase in flaring has encouraged 
entrepreneurs to develop new technologies and applications designed to 
capture smaller amounts of gas and put them to productive uses where 
building a pipeline to connect to the market is impractical. Companies 
are beginning to experiment with and deploy several technologies as 
potential alternatives to the traditional pipeline systems that capture 
associated gas. These include: Separating out NGLs, which are often 
quite valuable, and trucking them off location; using the gas to run 
micro-turbines to generate power; and using small integrated gas 
compressors to convert the gas into CNG that can be used on-site or 
trucked off location for use as transportation fuel or conversion to 
chemicals. In addition, there are other promising and innovative 
approaches that are either in development or in the earlier stages of 
deployment.\214\
---------------------------------------------------------------------------

    \214\ See Carbon Limits (providing detailed evaluation of new 
and emerging gas utilization technologies).
---------------------------------------------------------------------------

    Natural gas contains hydrocarbons that can exist in liquid phase 
without being in a high pressure or low temperature environment. These 
are referred to as NGLs. Higher NGL concentrations in a gas stream 
reflect higher heating (Btu) value and a higher combined commodity 
value when the NGLs are separated from the remaining gas stream. 
Although NGLs are typically stripped and fractionated into their 
various components (e.g., propane, butane, etc.) at a gas processing 
plant, well-site equipment capable of stripping NGLs into a mixed 
liquid is available. This technology is particularly applicable in 
situations where high Btu associated natural gas is being flared due to 
lack of gas capture infrastructure. The NGLs can be stripped from the 
gas stream in the field and stored in tanks at the well site. Trucks 
would transport the stored NGLs to a gas processing plant for sale. The 
remaining lower Btu gas would continue to be flared, but typically with 
a higher combustion efficiency than mixed gas. Conservation of the NGLs 
from a gas stream would reduce waste, add energy to the domestic 
supply, and increase royalty payments to the Federal Government and 
tribal governments.
    Facilities to condense natural gas into LNG are more cost-effective 
at locations with large amounts of flaring, as relatively larger 
quantities of gas are needed to offset the cost of the LNG equipment. 
The surface area of well sites may need to be expanded to accommodate 
truck traffic and product storage needs. Also, because associated gas 
production drops off quickly at hydraulically fractured oil wells, LNG 
recovery is more likely to be cost-effective if it is implemented when 
production starts.
    Micro-turbines that generate electricity typically require 
preprocessing of the associated gas to minimize equipment maintenance 
issues. Generating electricity can work well if it is paired with NGL 
recovery, as the NGL residue gas stream is well suited as fuel for the 
generators. However, scaling the generators to the electricity demand 
that could be used locally on the well pad complicates their use. The 
generators may produce more electricity than is needed on site, but it 
may be too costly to connect to the electric grid from a remote 
location, as would be necessary to put the excess electricity to 
productive use. The cost of connecting to the electric grid depends, 
among other things, on the distance of the operation from the nearest 
electrical distribution lines. Moreover, the electricity produced for 
use on site would be viewed as beneficial use, and therefore the gas 
used to generate the electricity would be royalty free. If the 
electricity produced by a micro-turbine is sold to the grid, however, 
it would not be beneficial use and the gas used to generate the 
electricity would not be royalty free.
    The CNG alternative technologies show considerable promise in 
effectively transporting associated gas to a centrally located 
processing plant while removing the higher value NGLs for other 
productive uses. Well sites may need to be expanded to accommodate 
truck traffic and storage needs, but not to the extent needed under the 
LNG option. The on-site equipment for CNG is smaller than for LNG, and 
the size of the CNG operation can also be more easily adjusted to meet 
the associated gas decline over the life of the well. However, 
limitations on the amount and rate of natural gas capture/compression 
on-site can limit applicability of this technology. Breakthroughs in 
compression technology are increasing the range of viable sites where 
CNG would be the preferred alternative technology. This technology 
could become sufficiently attractive to reduce flaring to near zero 
rates, according to companies offering these services. While these 
newer on-site technologies may not be suitable in all situations, in 
many cases they could provide a profitable alternative to using 
traditional pipelines for capture and sale as a way to reduce waste, 
and operators should consider these approaches in assessing the 
opportunities to reduce waste from venting and flaring.
    In addition, there are a number of technologies that can improve 
the efficiency of flares and ensure that a flare combusts as large a 
proportion of the gas as possible. In particular, automatic igniters 
can be used to ensure that the flare is relit if the gas flow stops 
intermittently.
(c) Factors Driving Flaring
    In considering how to reduce flaring, it is important to recognize 
that gas is flared under a variety of circumstances, some of which are 
unplanned or unavoidable in the course of normal oil and gas 
production. Emergencies can occur through an unforeseen event, such as 
a weather-related incident or an accident that damages equipment 
resulting in the loss of gas.
    In other cases, operators flare gas because they, and the midstream 
processing companies that commonly build and operate gas gathering and 
processing infrastructure, do not yet know whether there will be a 
sufficient quantity of gas available to capture. Thus, companies have 
not yet invested in building gathering lines and processing plants to 
capture and sell gas for commercial use. For example, the well may be 
an exploration or wildcat well in a new field, far from existing 
capture infrastructure, and it is not yet known whether the field will 
produce much gas. Similarly, in some fields, the overall quantity of 
gas produced across multiple wells is sufficiently small that, even 
cumulatively, the wells do not produce enough natural gas to offset the 
costs of building pipeline infrastructure. While flaring in these 
situations has generally been considered unavoidable, the BLM believes 
this assumption is challenged by the development of the alternative 
capture technologies described above, which calls into question whether 
it remains reasonable to assume that there are no alternatives to 
flaring when a field produces only a small quantity of natural gas. The 
BLM requests comment on this point. In many instances, however, the 
decision to flare large quantities of associated gas is driven by an 
operator's economic calculation that the value of immediately producing 
the oil outweighs the value of the natural gas that could be captured. 
In addition,

[[Page 6638]]

inadequate maintenance or oversight can result in avoidable waste of 
gas.
    Two circumstances that result in substantial ongoing or 
intermittent flaring of associated gas on BLM-administered leases are: 
(1) Flaring in areas with existing capture infrastructure, but where 
the rate of new-well construction is outpacing the infrastructure 
capacity; and (2) Flaring in areas where capture and processing 
infrastructure has not yet been built out. While the majority of 
associated gas flaring on BLM-administered leases occurs in the first 
situation, our proposed approach to reducing flaring addresses both 
circumstances.
    The first situation occurs in areas that have extensive natural-gas 
gathering lines, which are connected to pipelines leading to processing 
plants. However, in many areas in recent years the rate of oil 
development and the rapid rise in quantities of associated gas have 
overwhelmed the capacity of the gathering lines and/or processing 
plants. New wells (especially in shale formations) often start out 
producing a relatively large amount of oil and/or gas at relatively 
high pressures, which then declines rapidly over time. Thus, each time 
a new oil well with associated gas connected to the gathering system 
starts production, it may increase the pressures on the system above 
the pressures generated by existing producing wells, pushing those 
wells off the gathering system. Operators of these existing wells then 
must choose between shutting in or throttling the well, employing other 
technologies to use the gas, reinjecting the gas, or flaring. This is 
the situation in the Permian basin in New Mexico, where almost all of 
the producing wells are connected to gas-gathering infrastructure, but 
substantial flaring still occurs due to inadequate capacity or pressure 
restrictions in the pipelines and/or processing plants. Much of the 
flaring in the Bakken basin is also driven by capacity constraints. In 
reviewing applications to vent or flare in North Dakota, the BLM found 
that out of 1,292 applications to vent or flare received between 
September 2012 and August 2014, 887, or about 70 percent, were from 
wells that were already connected to a gas pipeline, but had pipeline 
capacity or pressure restrictions.\215\
---------------------------------------------------------------------------

    \215\ Phone conversation with BLM, Planning and Environmental 
Coordinator, Miles City, MT, September 2014.
---------------------------------------------------------------------------

    Flaring also occurs in the second situation identified above, when 
gas capture infrastructure has not yet been built out to a particular 
field or well, even though the well is expected to produce substantial 
quantities of gas. In many instances, operators or midstream processing 
companies plan to construct gathering lines, but the rate of oil well 
development outpaces the rate of development of capture infrastructure.
    In both situations, lack of adequate planning and communication can 
result in flaring. North Dakota's recognition of this cause of flaring 
led the State to require an operator to provide an affidavit at the 
well permitting stage stating that the operator met with gathering 
companies and informed them of the operator's expected well development 
timing and production levels.\216\
---------------------------------------------------------------------------

    \216\ Letter from North Dakota Oil and Gas Division to 
Operators, Re: Gas Capture Plans Required on All APD's (May 8, 
2014).
---------------------------------------------------------------------------

    The BLM recognizes that in the aggregate, operators do not want to 
waste gas. It is a valuable commodity that operators can sell for a 
profit. But when the economic return on oil production is substantially 
higher than the economic return on gas production, as it has been in 
recent years, there is an economic incentive for individual operators 
to focus on oil development at the expense of gas-capture 
infrastructure. Thus, operators may not adequately plan and coordinate 
with midstream companies, schedule oil well development with gas 
capture capacity in mind, build infrastructure, or otherwise ensure 
adequate capacity. As the GAO noted, even though it would be profitable 
in many instances for a company to make investments to reduce venting 
and flaring, the operator may choose to invest instead in a new well 
that would be even more profitable.\217\ The GAO also identified a lack 
of operator awareness of the available cost savings, limited capital 
availability for small companies, and institutional inertia as reasons 
that companies fail to capture the economic benefits of investing in 
waste reduction measures.\218\ In addition, operators typically 
consider only the costs and revenues of gas capture with respect to 
their individual operation. But in many instances, when costs and 
revenues are evaluated across a larger area, such as a group of wells 
that would share access to a gas transmission line and processing 
plant, gas capture that may appear less economically attractive to an 
individual operator may be more economical if all of the wells in that 
area were capturing and selling their gas. This concept is recognized 
in the existing requirements under NTL-4A, which directs the Supervisor 
to consider ``the economics of a field wide plan'' in evaluating the 
feasibility of requiring capture.\219\
---------------------------------------------------------------------------

    \217\ GAO-11-34 (Oct. 2010) at 24.
    \218\ Ibid.
    \219\ 44 FR 76600 (Dec. 27, 1979).
---------------------------------------------------------------------------

(d) Proposals To Reduce Waste From Venting and Flaring
    A focus on oil development rather than gas capture may be a 
rational decision for an individual operator, but it does not account 
for the broader impacts of venting and flaring, including the costs to 
the public of losing gas that would otherwise be available for 
productive use, the loss of royalties that would otherwise be paid to 
States, tribes, and the Federal Government on the lost gas, and the air 
pollution and other impacts of gas wasted through venting or flaring. A 
single operator's focus on its own operations can also produce a skewed 
assessment of the returns on investment in capture infrastructure 
across an entire area, where shared infrastructure may lower costs 
relative to the returns from the sale of gas.
    Thus, a decision to vent or flare that may make sense to the 
individual operator may constitute an avoidable loss of gas and 
unreasonable waste when considered from a broader perspective and 
across an entire field. Further, as capture technologies improve, the 
economics of capture are improving for individual operators.
    The BLM's proposed approach would reduce venting and flaring 
through a combination of measures: Prohibiting venting except in a 
narrow range of circumstances; reducing flaring by limiting the per-
lease per-month rate of flaring; requiring operators to submit gas 
capture plans with their Applications for Permits to Drill new wells; 
requiring royalties on flared gas where appropriate; and simplifying 
both compliance with and administration of the venting and flaring 
requirements. The proposed rule would streamline the current regulatory 
regime by establishing thresholds and presumptions that initially apply 
across the board, but would maintain the BLM's ability to address 
individual situations through case-by-case determinations and 
exemptions where warranted.
(i) Phasing Out Routine Venting
    With respect to venting, the proposal specifies that an operator 
must flare rather than vent gas, except in four specified 
circumstances: (1) When flaring the gas is technically infeasible (for 
example, because there is insufficient volume of gas); (2) When

[[Page 6639]]

the loss of gas is uncontrollable or venting is necessary for the 
safety of workers and others on the site; (3) When the gas is leaking 
from a storage vessel under circumstances that do not trigger the 
flaring requirements of proposed Sec.  3179.203; or (4) When the gas is 
vented through operation of a natural gas-activated pneumatic 
controller or pneumatic pump that complies with the equipment 
requirements of proposed Sec.  3179.201. As a practical matter, the BLM 
believes that the great majority of associated gas routinely lost from 
oil production wells is flared, rather than vented, and the proposed 
prohibition on venting would further reduce losses through venting. 
Thus, the discussion that follows generally references flaring, which 
is the main focus of these provisions.
    The BLM is aware that venting may occur at gas gathering lines due 
to maintenance activities. We request comment on whether the proposed 
venting prohibition will sufficiently address these maintenance 
emissions.
(ii) Limits on Rates of Flaring
    The proposed requirements to reduce flaring focus on the routine 
flaring of associated gas from development oil wells. Associated gas 
represents the bulk of the current flared gas, and is easier to capture 
than other flared gas. To address this waste of gas, the BLM proposes 
to establish a limit on the average rate at which gas may be flared of 
1,800 Mcf per month per producing well on a lease.
    The BLM is proposing to retain the current exemptions from 
royalties and gas capture requirements for gas flared in other 
specified situations, as long as the operator has complied with the 
proposed requirements to minimize these losses. These exemptions 
include gas lost in the normal course of well drilling and well 
completion; well tests; emergencies, as defined in the regulations; and 
gas flared from exploration or wildcat wells, or from delineation wells 
(wells drilled to define the boundaries of a mineral deposit). As 
described in more detail below, these exemptions represent situations 
in which: (1) A well is least likely to be connected to a pipeline, and 
on-site capture technologies are least likely to be economical; or (2) 
Flaring is likely to be unavoidable or necessary for safety.
(a) Proposed Per-Well Flaring Limit
    As noted, the primary means by which the BLM proposes to reduce 
flaring is by limiting the average rate at which gas may be flared to 
1,800 Mcf/month, per producing well on a lease.
    In essence, the BLM is proposing that, subject to limited 
exceptions, very high rates of flaring from a lease--that is, rates 
above the proposed 1,800 Mcf/month threshold--constitute unreasonable 
waste under the MLA. As discussed above, operators have multiple 
avenues to reduce high levels of flaring. One is to speed up connection 
to pipelines, and another is to boost compression to access existing 
pipelines with capacity issues. BLM believes there are also other 
options available to avoid this waste. The economics of alternative on-
site capture technologies improve as quantities of gas increase. 
Imposing a limit on the overall rate of flaring on a lease would 
provide operators an incentive to implement these technologies, where 
net costs are not prohibitive, to allow the wells to produce oil at the 
maximum rate. Alternatively, an operator could slow production 
sufficiently to stay below a flaring limit. Slowing the rate of flaring 
is likely to conserve gas overall because less gas is lost before 
capture infrastructure comes on line (or is upgraded, in the case of a 
field with insufficient capacity).
    To select an appropriate numeric limit for flaring, the BLM 
analyzed data indicating the average flaring rates across wells. The 
BLM used venting and flaring data reported to ONRR by operators of oil 
and gas leases on Federal and Indian lands. For the analysis, the BLM 
used the most recent full fiscal year of available data--records 
covering the time period from October 1, 2013, through September 30, 
2014. The BLM extracted from the ONRR data 15,530 records that document 
more than 76 Bcf of natural gas flared from oil wells during the time 
period. These records represent monthly flared volumes on a lease or 
unit basis from over 2,000 unique leases or units that flared natural 
gas from Federal or Indian mineral estates. As the number of wells on a 
lease or unit that might contribute to the monthly flaring volume can 
affect the cost to capture, the BLM further reviewed the BLM Automated 
Fluid Minerals Support System database for the number of total active 
wells associated with the lease or unit. With the number of active 
wells linked to the lease or unit, the records were sorted in order of 
increasing average flare volume per month per well.
    These data indicate that in 2014:
     A 1,200 Mcf/month/well threshold would have impacted about 
20 percent of the oil wells flaring associated gas, which accounted for 
91 percent of the gas flared;
     A 1,800 Mcf/month/well threshold would have impacted about 
16 percent of the oil wells flaring associated gas, which accounted for 
87 percent of the gas flared;
     An 2,400 Mcf/month/well threshold would have impacted 
about 13 percent of the oil wells flaring associated gas, which 
accounted for 84 percent of the gas flared;
     A 3,000 Mcf/month/well threshold would have impacted about 
11 percent of the oil wells flaring associated gas, which accounted for 
81 percent of the gas flared.\220\
---------------------------------------------------------------------------

    \220\ RIA at 33-35.
---------------------------------------------------------------------------

    While these are average flaring volumes spread across all active 
wells, they represent an approximation of how oil well flaring is 
distributed across the spectrum of activity.\221\ Operators have full 
discretion in how they choose to meet a rate-based flaring limit, with 
the result that compliance strategies may vary. For example, operators 
with wells that are only slightly over the flaring limit may choose to 
comply by slowing the rate of production until either: (1) The well is 
connected to pipeline infrastructure; or (2) Well decline brings the 
rate of gas production under the flaring limit. In the first instance, 
the over-the-limit quantity of gas would ultimately be conserved--in 
fact, even more gas might be conserved because the operator is likely 
to capture all of the gas that would otherwise have been flared. In 
contrast, in the second instance, the over-the-limit quantity of gas 
would still be flared, just later in time. Thus, there is substantial 
uncertainty in analyzing the impact of a flaring limit.
---------------------------------------------------------------------------

    \221\ Data supplied by ONNR.
---------------------------------------------------------------------------

    The BLM has analyzed the impacts of alternative flaring limits by 
adopting two simplifying assumptions. First, the BLM assumed that all 
over-the-limit quantities of gas would be captured instead of flared 
(an assumption that tends to overstate reductions in flaring); second, 
the BLM assumed that operators would comply only down to the level of 
the flaring limit and not below (an assumption that tends to understate 
reductions in flaring). With these competing assumptions in place, the 
projected reductions in flaring that might be achieved under different 
numeric limits are:
     A 1,200 Mcf/month/producing well threshold could conserve 
80 percent of the gas flared;
     An 1,800 Mcf/month/producing well threshold could conserve 
74 percent of the gas flared;

[[Page 6640]]

     A 2,400 Mcf/month/producing well threshold could conserve 
69 percent of the gas flared; and
     A 3,000 Mcf/month/producing well threshold could conserve 
65 percent of the gas flared.
    These estimates were generated for the purpose of comparing 
alternative options for the flaring limit; the estimated overall 
impacts of the proposed flaring limit, combined with the effects on 
flaring of other elements of the rule, are presented in Section VI.B.4. 
of this preamble and Section 8.4.1. of the RIA. The BLM proposes in 
Sec.  3179.6(b) to set a flaring limit of 1,800 Mcf per month per well, 
averaged over all producing wells on a lease. We believe this limit 
would effectively maximize flaring reductions while minimizing the 
number of affected leases. This proposed limit is consistent with 
Wyoming's and Utah's approaches: Wyoming and Utah limit flaring from a 
well to 60 Mcf/day and 1,800 Mcf/month, respectively, unless the 
operator obtains State approval of a higher limit.\222\ As applied, the 
numeric limit proposed by the BLM would be somewhat less stringent than 
the State limits, because operators would be able to average flaring 
across all of the wells on a lease, rather than being required to meet 
the limit at each individual well. This approach incorporates some of 
the flexibility allowed by North Dakota, where operators can show 
compliance with the State's flaring limits on a field, county, or 
state-wide basis. In addition to reducing waste of gas through flaring, 
we believe this proposed approach would give operators more clarity 
about when they may flare, and reduce administrative burdens for the 
BLM, compared to the current approach to obtaining approval for flaring 
under NTL-4A. Operators would no longer have to submit applications to 
obtain approval for flaring from each individual well, and the BLM 
would no longer need to review and decide on each of those requests. 
Currently, some field offices receive hundreds of flaring applications 
each year, and processing these applications on a case-by-case basis 
uses BLM resources that could be used to process applications for 
permit to drill, process right-of-way applications, and conduct 
inspections, among other activities.
---------------------------------------------------------------------------

    \222\ 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.).
---------------------------------------------------------------------------

(b) Phase-In of the Proposed Limit
    The BLM recognizes that in the first few years of the rule, it may 
be difficult for operators to meet the newly proposed flaring limit 
across all of their existing operations, because operators of oil wells 
drilled prior to the effective date of this rule may not have planned 
for gas capture. To assist these operators in transitioning to the 
proposed flaring limits, we propose to phase in those limits over the 
first few years after the effective date of the rule. Specifically, we 
propose flaring limits of: 7,200 Mcf per month per well on average 
across a lease in the first 12 months in which the regulations are in 
effect; 3,600 Mcf per month per well on average across a lease in the 
second 12 months in which the regulations are in effect; and 1,800 Mcf 
per month per well on average across a lease thereafter. This approach 
of phasing in the flaring limits is intended to allow operators 
initially to focus their resources on addressing wells with the highest 
rates of flaring.
(c) Alternative Flaring Limits or Renewable, 2-Year Exemption
    Lessees that entered into Federal and Indian leases prior to the 
imposition of the proposed flaring limits (depending on the location of 
their wells) may have limited options for substantially minimizing 
waste. As a result, the BLM believes it is appropriate and necessary to 
provide an exemption to ensure that no lessee is entirely deprived of 
its ability to develop an existing Federal or Indian lease.
    Thus, the BLM proposes in Sec.  3179.7 to provide existing lease 
holders with the possibility of obtaining an exemption to the 
applicable flaring limit. Specifically, we propose to provide that an 
existing lease holder may apply for an alternative flaring limit or, 
under specific circumstances, may qualify for a renewable, 2-year 
exemption from the flaring limit. These provisions are intended to help 
existing operators transition to the proposed regulatory regime; 
operators on new leases would have more flexibility to plan for gas 
capture ahead of drilling, and thus would not be eligible for either 
form of exemption.
(i) Alternative Flaring Limits
    The alternative flaring limit provision would apply to any operator 
(operating on an existing lease) that demonstrates, to the BLM's 
satisfaction, that the flaring limit specified in the regulations would 
impose such costs as to cause the operator to cease production and 
abandon significant recoverable oil reserves under the lease.
    In making the determination of whether a lease qualifies for an 
alternative flaring limit, the BLM would consider the costs of capture 
and the costs and revenues of all oil and gas production on the lease. 
For any operator that made a sufficient showing, the BLM would set an 
alternative flaring limit. The BLM would aim to set this alternative 
limit at the lowest level that would not cause the operator to cease 
production and abandon significant recoverable oil reserves.
    The proposed standard for approving an alternative flaring limit is 
similar to the existing standard in NTL-4A for approving venting or 
flaring of oil well gas. NTL-4A allows the BLM to approve flaring if it 
is justified by data showing 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.'' \223\ Given the substantial 
variation in how the BLM has interpreted and applied this standard, the 
BLM is proposing to establish a refined formulation of this test, to 
allow for a more uniform interpretation going forward. In particular, 
in some instances in the past, even small net costs have been viewed as 
meeting the test under NTL-4A, as any net cost might theoretically 
cause an operator to abandon a well earlier than it otherwise would 
have. In light of the BLM's statutory obligation to reduce waste of 
natural gas from venting, flaring, and leaks, however, the BLM believes 
that an operator must demonstrate more than a negligible economic 
impact in order to qualify for an exemption from the flaring limit. 
Thus, we propose to allow an exemption only on a showing that the net 
costs of compliance with the flaring limit would be sufficient to cause 
the operator to cease production and abandon ``significant'' 
recoverable oil reserves. The BLM requests comment on this approach.
---------------------------------------------------------------------------

    \223\ NTL-4A, IV.B.
---------------------------------------------------------------------------

    To make the proposed showing, an operator would have to provide 
information about the quantity of flaring from the lease, projected 
costs of capture (including an evaluation of on-site approaches), and 
projected prices and returns on oil and gas production from the lease. 
Where operators need to project future costs and returns, the 
projections would be required to cover either the life of each lease or 
the next

[[Page 6641]]

15 years, whichever is less. This is similar to the information that 
NTL-4A currently requires operators to provide in a request for 
approval of flaring, although the proposed regulations are more 
specific. NTL-4A currently requires an applicant for royalty-free 
flaring to submit ``all appropriate engineering, geologic, and economic 
data in support of the applicant's determination that conservation of 
the gas is not viable from an economic standpoint and if approval is 
not granted to continue the venting or flaring of the gas, that it will 
result in the premature abandonment of oil production and/or the 
curtailment of lease development.'' \224\ Pursuant to this language in 
NTL-4A and guidance from individual BLM State offices, operators 
generally give the BLM information on projected oil and gas production, 
revenue projections, costs, and returns on investment under scenarios 
in which the gas is and is not captured, although the specific 
information submitted varies between applicants and across BLM field 
offices and States.
---------------------------------------------------------------------------

    \224\ 44 FR at 76600 (Dec. 27, 1979).
---------------------------------------------------------------------------

    The BLM believes that requiring the information specified in this 
proposal to support a request for an alternative flaring limit would 
not impose substantial new paperwork burdens on operators, given the 
information currently required to be submitted under NTL-4A. In 
addition, given the rigor of the qualifying requirements, we do not 
expect many lease holders to apply for an alternative flaring limit, 
further limiting the potential burden. We request comment, however, on 
this point.
(ii) Renewable, 2-Year Exemption
    Unlike the alternative flaring limit, the renewable exemption would 
provide certain operators with a complete exemption from the flaring 
limit, for a period of 2 years. The BLM generally prefers to assess the 
need for alternative flaring limits on a case-by-case basis, but we 
recognize that it may be more efficient to grant a short-lived, across-
the-board exemption to a small class of operators that are: (1) 
Operating at significant distances from gas processing facilities, and 
(2) Generating high volumes of associated gas, such that capture and 
sale of the gas is plainly infeasible with current technologies.Thus, 
the proposed rule identifies three criteria that an operator must meet 
to qualify for an exemption from the flaring limit. Specifically, the 
BLM proposes that operations on an existing lease would qualify for an 
exemption from the flaring limit if: (1) The lease is not connected to 
a gas pipeline; (2) The closest point on the lease is located more than 
50 straight-line miles from the nearest gas processing plant; and (3) 
The rate of flaring or venting from the lease exceeds the applicable 
flaring limit by at least 50 percent.
    There are two reasons why the BLM believes that meeting all three 
of these criteria would be sufficient to demonstrate that an operator 
on an existing lease would be unlikely to be able to meet the flaring 
limit with today's technologies. First, a 2015 study by the entity 
Carbon Limits AS, titled Improving Utilization of Associated Gas in US 
Tight Oil Fields,\225\ suggests that on-site capture is most cost-
effective within a 20-25 mile radius of gas processing facilities.\226\ 
Existing leases located more than 50 miles from such facilities are 
thus unlikely to be able to avail themselves of this technology. (While 
leases located more than 25 but less than 50 miles from gas processing 
facilities might similarly find on-site capture less cost-effective, 
that might not always be the case. Those leases could make a case-by-
case showing under the proposed provision for alternative flaring 
limits.)
---------------------------------------------------------------------------

    \225\ Hereinafter ``Carbon Limits.'' The study is available at 
http://www.catf.us/resources/publications/files/Flaring_Report.pdf.
    \226\ Ibid. at 34.
---------------------------------------------------------------------------

    Second, while operators could respond to the flaring limit by 
deferring production, that is unlikely to be an option for operators on 
existing leases that are flaring more than 50 percent above the 
applicable limit. For these operators, reducing flaring below the limit 
would require reducing production by one-third or more. Thus, the BLM 
believes that leases meeting these distance and flaring rate criteria 
should qualify for an automatic exemption from the flaring limit.
    To obtain the exemption, the BLM proposes to require that an 
operator submit a Sundry Notice with an affidavit certifying that the 
lease meets the specified criteria. The authorizing officer would then 
have the opportunity to verify the accuracy of the submission.
    Because the circumstances supporting an exemption may change over 
time, the BLM proposes that the exemption would extend for 2 years, and 
could be renewed by the operator with submission and BLM approval of a 
new Sundry Notice.
(d) Request for Comments
    To assist the BLM in finalizing the proposed flaring limit, we 
request comment on:
     The proposed 1,800 Mcf/month/well limit on the quantity of 
flared gas;
     Whether the flaring limit should be 1,200 Mcf/month/well, 
which would likely further reduce flaring, or 2,400 Mcf/month/well, 
which would likely reduce compliance costs for operators, but increase 
flaring above the amount anticipated by the proposed rule;
     Operators' likely response(s) to the proposed 1,800 Mcf/
month/well limit (that is, the degree to which operators would respond 
by deploying on-site capture technologies, increasing capture capacity, 
speeding connections to pipelines, or slowing production, or with some 
combination of those responses);
     The proposal to phase-in the flaring limits and the 
specific limits proposed for year-one and year-two;
     The proposed provisions for operators to obtain an 
alternative flaring limit; and
     The proposed criteria for operators to qualify for the 
renewable, 2-year exemption, as well as the proposed 2-year duration of 
the exemption and the opportunity for renewal.
(iii) Waste Minimization Plans for Applications for Permit To Drill
    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 APD.
    The BLM proposes to amend Sec.  3162.3-1 to require an operator to 
submit along with its APD a plan to minimize waste of gas from the well 
to the degree reasonably possible. Failure to submit a complete and 
adequate waste minimization plan would be grounds for denying or 
disapproving an APD.
    The plan must set forth a strategy for how the operator will comply 
with the proposed requirements to control waste from venting, flaring, 
and leaks, and it must explain how the operator plans to capture 
associated gas upon the start of oil production, or as soon thereafter 
as reasonably possible. The waste minimization plan must include 
specified information, including: Anticipated well completion timing; 
anticipated gas production rates, durations, and declines; a map and 
information on the locations and operators of nearby gas pipelines and 
processing plants; proposed routes and tie-in points; pipeline 
capacities, throughputs, and expansion plans, if known; an evaluation 
of opportunities for alternative on-site capture approaches, if 
pipeline transport is

[[Page 6642]]

unavailable; and the volume and percentage of produced gas that the 
operator is currently flaring from wells in the same field. In 
addition, the operator must certify that it has provided one or more 
midstream processing companies with information about its production 
plans, including the anticipated completion dates and gas production 
rates of the proposed well or wells. We request comment on whether the 
waste minimization plan provisions should also require an operator to 
identify the projected gas production volumes that would be moved by 
pipeline or by truck.
    While the BLM is proposing to require submission of a waste 
minimization plan together with the APD, we are not proposing to 
include the submitted plan as an element of the APD or otherwise to 
enforce the terms of the plan.
    The BLM believes that requiring submission of a waste minimization 
plan would ensure that as an operator plans a new well, the operator 
has the information necessary to evaluate and plan for gas capture. 
This requirement would also ensure that the operator provides this 
information to the companies most likely to install and operate the 
necessary gas capture infrastructure--namely, midstream processing 
companies operating in the area. Both procedural steps are vitally 
important to development of a robust gas capture system for a new well.
    As with development of an environmental analysis under the National 
Environmental Policy Act, the BLM believe that significant progress can 
be made by requiring that operators take these procedural steps prior 
to drilling. Further, the BLM believes that making the elements of the 
plan enforceable (for example, by incorporating it in the APD) might 
create an unintended incentive for operators to understate the degree 
of capture they anticipate achieving, or to write a very general plan, 
with few specifics. As a result, the BLM believes more can be achieved 
by requiring operators to develop a thorough and practical plan prior 
to submitting their Applications for Permits to Drill. The plan 
requirement is intended to assist operators in better preparing to 
comply with the proposed flaring limits.
    The information required by this proposed provision is comparable 
to the information North Dakota requires to be included in the gas 
capture plan that each operator must provide. North Dakota requires 
that the gas capture plan include: A detailed gas gathering pipeline 
system location map identifying the location of connections to the 
gathering system and processing plants, as well as the names of gas 
gatherers and locations of lines for each gas gatherer in the vicinity; 
information on the existing line to which the operator proposes to 
connect, including the maximum current capacity, current throughput, 
and gas gatherer issues or expansion plans for the area (if known); a 
flowback strategy including the anticipated date of first production, 
and anticipated oil and gas rates and duration; the amount of gas the 
applicant is currently flaring; and alternatives to flaring, including 
specific alternate systems available for consideration and the expected 
flaring reductions if such plans are implemented.\227\ North Dakota 
regulators have identified the requirement for gas capture plans as a 
highly effective element of their requirements to reduce flaring.\228\
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    \227\ Letter from North Dakota Industrial Commission, Department 
of Mineral Resources, Oil and Gas Division to all Hearing 
Applicants, re Gas Capture Plan Required Hearing Exhibit (Sept. 16, 
2014).
    \228\ Telephone Communication from North Dakota Industrial 
Commission, Department of Mineral Resources, Oil and Gas Division to 
BLM Staff, (May 13, 2015).
---------------------------------------------------------------------------

(iv) Estimating or Measuring Quantities of Flared or Vented Gas
    Under proposed Sec.  3179.8, the BLM would require operators to 
report the quantities of all flared and vented gas. In determining the 
quantity of gas flared or vented, operators either estimate the volumes 
using engineering protocols or measure the volumes with gas meters. 
Meters generally produce more accurate results, but are also more 
costly. Thus, the BLM proposes to specify when operators may estimate 
the volumes of flared or vented gas, and when operators must measure 
the quantities for reporting purposes. Specifically, the BLM proposes 
that when the combined total of an operator's flaring and venting 
reaches least 50 Mcf of gas per day from a flare stack or manifold, the 
operator must measure rather than estimate the volume lost (i.e., 
flared and/or vented) from that flare stack or manifold.
    The BLM believes that in calculating small volumes of lost gas, any 
additional accuracy provided by meters may not justify their additional 
cost. Accordingly, the proposed rule would allow operators to estimate 
rather than measure volumes of lost gas below 50 Mcf. The BLM proposes 
to require measurement when gas losses are at least 50 Mcf per day 
because as the volume of gas flared nears 60 Mcf/day it is effectively 
nearing the 1,800 Mcf/month limit, and at that point accurate 
measurement of that volume becomes increasingly important for 
compliance and enforcement purposes. Moreover, as the volumes of gas 
flared increase, the economics of gas capture become more favorable, 
and the importance of using more refined data increases. We request 
comment on this proposed approach.
(v) Costs and Benefits of These Proposals
    The requirement to meter flares is estimated to pose compliance 
costs of $7,500 per meter and operating costs of about $500 per meter 
per year. Assuming an equipment life of 10 years, the cost per meter is 
about $1,570 per year when costs are annualized using a 7 percent 
interest rate, or $1,380 per year using a 3 percent interest rate. In 
total, we estimate that the proposed flare metering requirement would 
impact 635 operations in 2017, with that number increasing on an annual 
basis to an estimated 1,175 operations in 2026. 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. Since these sources are not addressed 
by the EPA's proposed 40 CFR part 60 subpart OOOOa, the estimated 
impacts of the requirements are not influenced by that proposal.\229\
---------------------------------------------------------------------------

    \229\ RIA at 69.
---------------------------------------------------------------------------

    The requirement to limit gas flaring to 1,800 Mcf/month per average 
well on a lease may result in a range of potential benefits and costs 
depending on operator response, commodity prices, and the levels of 
flaring in future years. Operators could choose to comply by 
immediately using the excess gas on-site or deploying on-site capture 
technologies; they could briefly slow oil production while they expand 
capture capacity, where such expansion is cost-effective; or they could 
defer some portion of their production. We request comment on the 
likely balance among these response approaches, and the likely volume 
and duration of any partial deferment in oil production.
    We considered this range of responses in estimating the costs and 
benefits of the flaring provisions, although we recognize that these 
estimates are subject to significant uncertainty, given the uncertainty 
about operator response. In designing the analysis, we looked at data 
for leases in North Dakota and New Mexico with respect to 
characteristics that might influence an operator's choice of how to 
comply with the flaring limits. Specifically, we identified whether 
wells on the lease were

[[Page 6643]]

connected to pipeline infrastructure, the rate of flaring 
(specifically, whether the rate was at least 50 percent above the 
flaring limit, or whether the rate was within 40 Mcf/day of the flaring 
limit), and the distance from the nearest gas processing plant 
(specifically whether the well was more than 50 miles, less than 20 
miles, or between 20 and 50 miles from the nearest gas processing 
plant) for each lease where these data were available. We then 
constructed eight possible operator response scenarios based on 
combinations of these characteristics. We evaluated how operators in 
each scenario might respond to the flaring limit (e.g., by deferring 
production, conducting on-site capture, or obtaining an exemption), 
assigned costs for each type of response, calculated the number of 
leases that would fall into each response category, and derived an 
estimate of overall costs. The RIA provides additional detail on our 
analysis.
    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). Also, we expect there would be 
additional environmental benefits associated with the productive use of 
the gas downstream.\230\
---------------------------------------------------------------------------

    \230\ RIA at 60.
---------------------------------------------------------------------------

(e) When Flared Gas Is Subject to Royalties
    Along with the other aspects of NTL-4A, it is necessary to update 
the NTL-4A provisions regarding the applicability of royalties. As 
noted above, this proposal would clarify the determination of whether 
routine flaring from a production well is considered an avoidable waste 
of gas subject to royalties. Requiring royalty payments on wasted 
quantities of gas does not compensate for all the harm to the public 
from that waste, but it at least ensures that the public does not lose 
the royalty revenue they would have received had the gas been put to 
productive use.
    The BLM is proposing in Sec.  3179.4 to maintain the general 
approach of NTL-4A for distinguishing between avoidable and unavoidable 
losses of gas. The proposed rule would reduce regulatory burden and 
confusion, however, by providing additional and more specific 
requirements, and it would modify the NTL-4A approach with respect to 
flaring from wells that are already connected to gas capture 
infrastructure.
(i) Unavoidable Losses of Gas
    The BLM proposes to determine that a loss of gas is unavoidable if 
all of the following four conditions are met. (1) The operator has not 
been negligent; (2) The operator has complied with all applicable 
requirements; (3) The operator has taken prudent and reasonable steps 
to avoid waste; and (4) The gas is lost from any of the following 
specified operations or sources, subject to the applicable limits or 
conditions 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 conforming pneumatic devices in the 
normal course of operation; evaporation from storage vessels; and 
downhole well maintenance and liquids unloading. Where these losses 
result from flaring, the BLM is proposing to establish quantity and/or 
timing limits on gas that may be flared royalty-free, such as the 
definition of what is considered an emergency and the limits on 
royalty-free flaring for well testing. Beyond these limits, continued 
losses would generally be considered avoidable and subject to 
royalties, except that, with respect to testing, the BLM may approve an 
operator's request for royalty-free flaring beyond the specified 
limits.
    In addition, the BLM is proposing to find a loss of gas unavoidable 
where produced gas is flared from a well not connected to gas capture 
infrastructure, as long as the BLM has not otherwise determined that 
the loss of gas is avoidable, subject to the 1,800 Mcf/month limit in 
Sec.  3179.6. In some cases, the effectiveness and affordability of on-
site capture technology may mean that an operator could avoid flaring 
gas from a well not connected to capture infrastructure. At this time, 
however, on-site capture technology is not always effective and 
affordable; thus, the BLM is not proposing to find all flaring of 
associated gas from development wells to be avoidable.
    The specifics of the proposal with respect to unavoidable losses 
depend on the category of loss. With respect to emergencies, NTL-4A 
currently authorizes royalty-free flaring of gas without approval from 
the BLM, but the proposed rule would clarify and narrow the scope of 
this exemption. As proposed under Sec.  3179.105, emergencies result in 
infrequent and unavoidable flaring (or venting), and they may include 
failures of equipment located on the lease, relief of abnormal system 
pressures, or other unanticipated conditions. Operators may flare under 
this exemption for up to 24 hours per incident, and for no more than 
three emergencies per lease within a 30-day period. The BLM proposes to 
clarify that emergencies do not include: More than three failures of 
the same equipment within 365 days; failure to install adequate 
equipment to capture the gas; failure to limit production when the 
production rate exceeds the capacity of the related equipment; 
scheduled maintenance (whether by the operator or downstream 
facilities); or operator negligence. The BLM believes that repeated 
failure of the same piece of equipment within a given span of time 
indicates that the equipment is not properly sized or may need to be 
replaced, and that the operator should have taken action to address the 
problem. The BLM requests comment on the specific failure frequencies 
over a given time-period that would tend to indicate avoidable 
incidents.
    With respect to flaring during well drilling and completion, the 
BLM proposes under Sec.  3179.101 that gas produced during normal well 
drilling operations and then flared would be deemed unavoidably lost. 
Similarly, under proposed Sec.  3179.102, gas produced during well 
completion and post-completion drilling fluid recovery or fracturing 
fluid recovery operations would be deemed unavoidably lost when flared, 
subject to a volume limit. Under proposed Sec.  3179.103, gas from 
initial production testing may be flared and deemed unavoidably lost 
until the first of the following occurs: (1) The operator has adequate 
reservoir information for the well; (2) 30 days (90 for coal-bed 
methane dewatering) have passed; (3) The operator has flared 20 MMcf of 
gas, including any gas flared that was produced during well completion 
and post-completion fluid recovery; or (4) Production begins.
    The 20 MMcf limit is lower than the maximum volume of royalty-free 
flaring authorized under NTL-4A (50 MMcf). The BLM's experience in the 
field

[[Page 6644]]

indicates that adequate testing to determine a well's production 
capacity can almost always be conducted within the 20 MMcf volume 
threshold. The current 50 MMcf threshold is seldom, if ever, exceeded 
in actual well testing operations. The BLM specifically seeks comments 
on the amount of gas that should be allowed to be flared royalty-free 
during initial production testing.
    Under proposed Sec.  3179.104, during well tests subsequent to the 
initial production test, the operator may only flare gas for 24 hours 
royalty free, unless the BLM approves otherwise.
    Operators would no longer need to apply for approval of flaring 
under the preceding conditions. Any gas flared in excess of these 
limits, however, would be deemed avoidably lost and subject to 
royalties, except where the BLM approved a request to extend the 
limits. In addition, regardless of whether the gas is subject to 
royalties, BLM also proposes under Sec.  3179.8 that the operator must 
measure or estimate all quantities of gas flared and vented, including 
those that are deemed unavoidably lost, and report these quantities to 
ONRR.
(ii) Avoidable Losses of Gas
    Under proposed Sec.  3179.4(b), all losses of gas not specifically 
found to be unavoidable would be considered avoidable. Proposed Sec.  
3179.5(a) would subject all avoidably lost gas to royalties. One key 
consequence of this proposal is that royalties would apply to 
associated gas flared from a development well that is already connected 
to capture infrastructure.
    The BLM believes that where operators are connected to capture 
infrastructure, but are nevertheless flaring, they have made an 
economic choice to flare, and flaring in those instances should not be 
considered an unavoidable consequence of oil production. Most flaring 
at wells already connected to pipelines occurs when wells are bumped 
off the pipeline due to pressure or capacity constraints, or when 
downstream equipment is brought down for maintenance. Where wells are 
already connected to gas capture infrastructure, midstream companies 
and operators have presumably already found that gas capture pays for 
itself. Nonetheless, operators may choose to expand production beyond 
the capacity of existing capture infrastructure, or to do so faster 
than capture infrastructure can be expanded (where capacity issues can 
be addressed with installation of additional compression, the rate of 
expansion is often in the operator's control). This may be a rational 
business decision for an operator, but with better planning or more 
deliberate development, both the oil and gas resources could be 
developed without waste.
    Further, operators may be able to use alternative on-site gas 
capture equipment to put the gas to productive use during any period in 
which gas production exceeds transport capacity. Similarly, when 
downstream equipment is temporarily brought down for maintenance, 
operators could curtail production for a short period or use on-site 
capture equipment to avoid wasting gas in the interim.
(f) Alternative and Additional Approaches
    The BLM considered, but did not include in the proposed rule text, 
a range of supplemental or alternative approaches to the flaring limit 
and royalty provisions described above. For example, one alternative 
approach that BLM considered for increasing capture of associated gas 
was to rely solely on royalties on flared gas to discourage flaring. 
Under this approach, all flaring of associated gas would be 
presumptively subject to royalties. Similar to the current standard 
under NTL-4A, operators could then obtain an exemption to the 
requirement to pay royalties by showing that a requirement to conserve 
the gas would cause the operator to cease production and abandon 
significant recoverable oil reserves. To support such a claim, the 
operator could be required to provide: The projected costs of each 
technically viable method of capturing and/or using the gas (including, 
if applicable, pipelines, removal of NGLs, CNG, LNG, and electricity 
generation); the current return on investment for the oil and gas 
operation on the lease; the projected return on investment for the oil 
and gas operation if some or all of the gas were captured; projected 
oil and gas prices and production volumes; the location and capacity of 
the closest pipelines; and other relevant information. In making the 
determination, the BLM would consider the costs of capture, and the 
costs and revenues of all oil and gas production on the lease.
    While market-based mechanisms, such as royalty imposition, can be 
highly effective policy instruments, and we do propose to charge 
royalties on gas flared above the 1,800 Mcf/month limit because we 
believe flaring above that level is avoidable, we do not believe that 
royalties on flared gas alone would curtail flaring. At current gas 
prices, oil prices, and royalty rates, applying royalties to flared gas 
does not provide a sufficient incentive for operators to invest in gas 
capture to any appreciable degree. This is evident in areas such as 
Carlsbad, New Mexico, where most operators are currently paying 
royalties on associated gas that is flared, and in spite of those 
payments, rates of flaring have not changed appreciably since 2013. The 
BLM would not expect the imposition of royalties at the current royalty 
rate to lead to a significant increase in gas capture as long as the 
economic return on the oil production is substantially higher than the 
economic loss from the flared gas. The BLM requests comments on this 
conclusion.
    A more significant royalty-based approach to flaring would be to 
apply a higher royalty rate to all production from a lease on which the 
operator is routinely flaring gas from development wells. This concept 
is discussed in more detail in Section V.C. of this preamble.
    Another alternative to the proposed approach to flaring would be to 
distinguish between new and existing wells. The current proposal 
applies the same flaring requirements to both. The BLM is, however, 
considering including a complete prohibition on routine flaring of 
associated gas from new development wells. This approach would shift 
the burden of flaring from the public, which currently absorbs the 
costs of flaring, to operators, which have greater capacity to 
anticipate and plan for capture infrastructure to be ready at the time 
they shift from exploration to development in a given field. The BLM 
requests comment on this approach.
    Finally, the BLM is requesting comment on other innovative 
approaches to reduce wasteful flaring and determine when flaring should 
be subject to royalties. In evaluating alternative approaches suggested 
in comments, we would consider a variety of factors, including the 
approach's effectiveness in: Increasing gas capture; reducing waste and 
compensating the public through royalties; enhancing regulatory clarity 
and transparency; reducing uncertainty for operators; minimizing 
inconsistency across BLM offices; minimizing cost, paperwork, and any 
other burdens on operators; minimizing administrative burden on the 
BLM; increasing overall practical workability; and satisfying existing 
legal authorities.
2. Leaks
(a) Estimates of Quantities of Gas Leaked
    As discussed in detail in the RIA, using data from the EPA GHG 
Inventory, we estimate that about 4.35 Bcf of natural gas was lost in 
2013 as a result

[[Page 6645]]

of leaks or other fugitive emissions from various components, including 
valves, fittings, pumps, storage vessels and compressors on well site 
operations on BLM-administered leases.\231\ This quantity of gas would 
supply nearly 60,000 homes each year.\232\
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    \231\ RIA at 19.
    \232\ Based on an estimate of 74 Mcf of gas used per household 
per year. See footnote 2.
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(b) Technologies and Practices To Reduce Leaks
    Multiple studies have found that once leaks are detected, the vast 
majority of them can be repaired at low enough cost that the captured 
gas provides a positive return to the operator. For example, the Carbon 
Limits study found that 97 percent of the total leak rate could be 
repaired with a positive return, even at low producer gas prices of $3 
per Mcf.\233\ Further, over 90 percent of gas leak emissions are from 
leaks that could be repaired with less than a 1-year payback 
period.\234\ Given that leak repair is generally economical, the key 
question is how the cost of leak detection compares with the value of 
the gas that could potentially be saved by repairing leaks.
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    \233\ Carbon Limits, 16.
    \234\ Carbon Limits, 16.
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    The term ``Leak Detection and Repair'' (LDAR) refers to both the 
practices and programs that operators put in place to inspect for and 
repair leaks, and the specific technologies and methods the operators 
use to detect leaks during inspections. Recent technological 
developments have reduced the cost of leak detection while 
simultaneously improving operators' ability to detect less obvious 
leaks. Traditional methods coupled with new technology can also be 
effective.
    States are beginning to take advantage of these new technologies. 
Colorado, for example, requires instrument-based emission monitoring as 
part of an LDAR program that applies to well production facilities and 
compressor stations.\235\ Also, Wyoming has regulations that require 
operators in the Upper Green River Basin nonattainment area to develop 
LDAR programs if their facilities emit more than an estimated 4 tons of 
VOCs each year.\236\
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    \235\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9, Section XVII.F.
    \236\ Wyoming Operational Rules, Drilling Rules Section Ch. 8, 
Section 6(g), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.
---------------------------------------------------------------------------

(i) Auditory, Visual, and Olfactory (AVO) Method
    The AVO method consists of physically inspecting the facilities--
looking, listening, and smelling for leaks. AVO inspections have 
traditionally been the backbone of an inspection program, and BLM 
inspectors typically use this method when inspecting well and facility 
sites. The use of AVO inspections is most effective in detecting 
obvious and significant emissions-release events, resulting in the 
cost-effective reduction of high-volume leaks. The BLM believes AVO is 
affordable for the many small operators that only operate a few well 
sites each. Costs associated with the AVO method are largely for labor, 
paying for qualified technicians and their mileage to and from the well 
or facility sites.\237\ AVO inspections are not, however, very 
effective at catching smaller or less obvious leaks, which can be a 
source of significant wasted gas.
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    \237\ API, 2014.
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(ii) Portable Analyzers
    Portable monitoring instruments or portable analyzers detect 
hydrocarbon leaks from individual pieces of equipment. These analyzers 
may use any of a variety of methods of detection, including catalytic 
ionization, flame ionization, photoionization, infrared absorption, and 
combustion, and they are generally used only to detect and measure the 
quantity of a single component of the vapor, such as methane. These 
analyzers are sensitive and can detect emissions at extremely low 
concentration levels. Typical portable analyzers range in cost from 
$3,000-$12,000.\238\
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    \238\ API, 2014.
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    One standard approach for using portable analyzers is ``Method 
21,'' the EPA's method for detecting VOC emissions from leaking 
equipment.\239\ Method 21 provides the specifications and performance 
criteria that must be used under EPA's regulations to detect leaks 
using portable analyzers.
---------------------------------------------------------------------------

    \239\ 40 CFR part 60, App. A-7.
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(iii) Optical Gas Imaging (Infrared Camera)
    A newer technology that operators and inspectors are increasingly 
using for leak detection is optical gas imaging (OGI). OGI uses 
infrared detectors (commonly called ``infrared cameras'') to provide 
visual images of gas emissions in real time. The OGI instrument can be 
used to monitor a wide range of oilfield equipment and its 
effectiveness as a means for detecting leaks is widely recognized.
    OGI costs more than AVO approaches, but it also detects more leaks, 
which can result in additional gas savings. The GAO noted that infrared 
cameras allow users to rapidly scan and detect vented gas or leaks 
across wide production areas. The GAO specifically recommended that the 
BLM consider the expanded use of infrared cameras, where economical, to 
improve reporting of emission sources and to identify opportunities to 
minimize lost gas.\240\ In its recent proposed rule, EPA also notes the 
advantages of OGI compared to a portable analyzer.\241\ Several studies 
discussed in EPA's white paper on leak detection estimated that OGI can 
monitor 1,875-2,100 components per hour.\242\ In comparison, the 
average screening rate using a portable analyzer is roughly 700 
components per day.\243\ Although EPA noted that these studies may 
underestimate the amount of time necessary to thoroughly monitor for 
fugitive emissions using OGI instruments, EPA stated that it still 
believes that the use of OGI can reduce the amount of time (and 
therefore the cost) necessary to conduct fugitive emissions monitoring, 
because multiple fugitive emissions components can be surveyed 
simultaneously.\244\
---------------------------------------------------------------------------

    \240\ GAO-11-34 (Oct. 2010) at 34.
    \241\ 80 FR 56593, 56634.
    \242\ Ibid.
    \243\ Ibid.
    \244\ Ibid.
---------------------------------------------------------------------------

    Infrared cameras have high capital costs, and they also require 
calibration, maintenance, and training. As a result, while some 
operators purchase and operate this equipment themselves, others 
contract with specialized firms for leak detection surveys using this 
equipment. For example, the equipment may cost from $85,000 to $100,000 
or more, with packages that include many peripherals costing upwards of 
$125,000. Batteries, chargers, and other required peripherals can add 
$5,000 to $10,000. Service provider rates may be in the range of $500 
per day to $2,000 per week, while annual service contracts may range 
from $5,000 to $10,000.\245\ Calculated on an individual facility 
basis, another study found that the average cost of hiring an external 
service provider to conduct a leak survey and provide a report is: $400 
per individual well site (with a single well); $600 per single well 
battery, which includes additional equipment on site; $1,200 per multi-
well battery; and $2,300 per compressor station.\246\ The BLM has also 
received information from external service providers indicating that 
costs can be substantially lower than these, and we request comment on 
this point.
---------------------------------------------------------------------------

    \245\ API, 2014.
    \246\ Carbon Limits, 14, 32.

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[[Page 6646]]

    Studies and some operators' experiences indicate that LDAR programs 
based on the use of infrared cameras actually save operators money 
overall, while substantially reducing waste. For example, the Carbon 
Limits study found that because leaks are not evenly distributed across 
all facilities, not every leak survey finds leaks and saves money for 
the particular operator. But when considered across a broader set of 
facilities (such as those located on BLM-administered leases or a set 
of facilities owned by a single operator), the study found that these 
programs have either cost-neutral or positive returns on average, 
depending on the type of facility surveyed.
    Specifically, the Carbon Limits study found that for well sites and 
groups of wells, about one-third of the facilities had no detectable 
leaks, 7 percent had leaks above 500 Mcf per year, and the remainder 
had leaks of less than 500 Mcf per year. (To put this number into 
perspective, a typical home uses 74 Mcf of gas a year.\247\) For 
compressor stations, roughly 10 percent had no leaks, while almost 25 
percent leaked at 500 Mcf per year or more.
---------------------------------------------------------------------------

    \247\ See footnote 2.
---------------------------------------------------------------------------

    When aggregated across a larger group of facilities, rather than 
being evaluated on a facility-by-facility basis, the Carbon Limits 
study found that these infrared camera leak surveys produce net cost 
savings.\248\ Broken down by facility type, it found that surveys at 
well sites are cost-neutral measured on a ton of avoided 
CO2-e basis, and that surveys at compression stations 
produce net savings. Specifically, on average, the net present value 
(NPV) of applying LDAR to an individual well site or well battery was a 
loss of $35, assuming recovered gas at $4 per Mcf. The average cost 
saving across all compressor stations surveyed was $3,376. Moreover, 
the authors note that most of the facilities in the study were Canadian 
facilities that are already inspected for leaks every 1 to 2 years, and 
thus the current leak rates--and, consequently, proceeds from repairs--
at U.S. facilities without leak inspection programs would be expected 
to be higher.\249\
---------------------------------------------------------------------------

    \248\ Carbon Limits. The study increased the cost estimates by 
50 percent to account for the internal costs to a firm of arranging 
for this work, and it assumed a 7 percent discount rate and $4 per 
Mcf value of gas.
    \249\ Ibid.
---------------------------------------------------------------------------

(iv) Continuous Emissions Monitoring Systems and Other New Technologies
    Another possibility for leak detection is continuous emissions 
monitoring. Continuous Emissions Monitoring Systems (CEMS) are commonly 
used as a means of monitoring various components of a large industrial 
source's emissions stream, including oxygen, carbon monoxide and carbon 
dioxide, for compliance with EPA or State air emissions standards. More 
recently, researchers have been evaluating the possibility of adapting 
the technology for use in identifying leaks in and around oil and gas 
operations.\250\ Due to the dispersed nature of potential leaks within 
the area of concern (compared to the concentrated gases in a flue gas 
stream), challenges remain in developing a CEMS (standalone or mobile) 
that has the requisite sensitivity to detect leaks under a variety of 
atmospheric and field conditions. One possibility is to use a CEMS as 
an area monitor for fugitive emissions, which would then alert the 
operator for the need to use a more focused leak detection device to 
pinpoint the leak needing repair. Research is continuing to determine 
if CEMS could supplement or be a viable alternative to current leak 
detection instruments.
---------------------------------------------------------------------------

    \250\ Briefing from Dr. Bryan Wilson, Program Director, Advanced 
Research Projects Agency--Energy on O&G emission projects the agency 
is funding, August 3, 2015.
---------------------------------------------------------------------------

    There is also extensive ongoing work to develop other, more 
effective and less costly advanced leak detection technologies. For 
example, DOE initiated an effort to advance methane-sensing 
technologies through the Advanced Research Projects Agency--Energy 
(ARPA-E) MONITOR (Methane Observation Networks with Innovative 
Technology to Obtain Reductions) program.\251\ In December 2014, this 
$30-million, 3-year program announced support for 11 new projects that 
are developing low-cost, highly sensitive systems that detect and 
measure methane associated with the production and transportation of 
oil and natural gas.\252\
---------------------------------------------------------------------------

    \251\ ARPA-E, http://arpa-e.energy.gov/?q=arpa-e-programs/monitor.
    \252\ Briefing from Dr. Bryan Wilson, Program Director, Advanced 
Research Projects Agency--Energy on O&G emission projects the agency 
is funding, August 3, 2015.
---------------------------------------------------------------------------

(iv) LDAR Programs
    An effective LDAR program depends not just on the technology used 
to detect leaks, but also on the overall approach an operator uses to 
inspect for leaks, conduct preventative maintenance, and repair leaks 
that are found. Two of the largest operators in one of BLM's field 
offices conduct routine operations checks, which typically use AVO 
inspection methods. In addition to well site inspections, a 
preventative maintenance program is often used. Adherence to a properly 
designed preventive maintenance program proactively minimizes equipment 
failures and gas losses from leaks. In general, a maintenance program 
may consist of a variety of activities that are applicable to operating 
location, type of operations, and equipment used. An operator will 
design the preventive maintenance program that is most suitable for the 
site. These efforts include periodic inspection (AVO inspection and 
general equipment inspection on at least a monthly basis) and service 
of components that are not leaking, material selection appropriate to 
service (i.e., alloys, gaskets, filters, etc. that are wear and/or leak 
resistant), active corrosion monitoring, the application of corrosion 
and scale inhibitors, use of maintenance records to identify components 
at risk of failure, and pre-emptive replacement of at-risk 
equipment.\253\
---------------------------------------------------------------------------

    \253\ API, June 13, 2014. Re: EPA VOC/Methane White Paper on Oil 
and Natural Gas Sector Leaks. Pages 7-9.
---------------------------------------------------------------------------

    For example, one major operator in northwest New Mexico, which 
oversees 10,000 wells in the San Juan Basin, has its lease operators 
visit each well site each week.\254\ The visits are tracked using GPS, 
which is installed in each truck.\255\ According to the operator, any 
leaks are fixed within days, new facilities are leak-tested prior to 
production, and most wells have Remote Terminal Units installed, which 
monitor gas flow rate and volume, static pressure, differential 
pressure, temperature, controller settings, plunger arrivals/rod pump 
status/compressor status and both oil and water tank levels.\256\ The 
data flow via solar-powered telemetry at 1-minute intervals. Alarms are 
triggered if there are sudden pressure changes or tank level drops, and 
a lease operator can be dispatched to the well site to 
investigate.\257\
---------------------------------------------------------------------------

    \254\ Phone conversation with Conoco Phillips on San Juan Basin 
operation, February 2015.
    \255\ Phone conversation with Conoco Phillips on San Juan Basin 
operation, February 2015.
    \256\ Phone conversations with Conoco Phillips and WPX energy on 
San Juan Basin operations, February 2015.
    \257\ Ibid.
---------------------------------------------------------------------------

(c) Proposals To Reduce Waste From Leaks--Leak Detection and Repair 
Programs
    The BLM believes that LDAR programs are a cost-effective means of 
reducing waste of gas in the oil and gas production process, based on 
the State programs, studies, and findings discussed above. Thus, the 
BLM is

[[Page 6647]]

proposing under Sec. Sec.  3179.301 through 3179.305 to require that 
each operator on a Federal or Indian lease institute an LDAR program 
that meets specified standards for detection methodology, frequency, 
and leak repairs, and use this program to inspect each of the 
operator's well sites and compressor locations.
    The BLM's proposed approach, outlined below, is similar to the 
requirements adopted by Colorado and Wyoming. EPA's proposed 
regulations to reduce methane emissions from the oil and gas production 
sector also include fugitive emission requirements, which would apply 
to certain new and modified oil and gas production facilities. 
Specifically, the EPA's September 18, 2015 proposal, if finalized, 
would require that new, reconstructed, and modified well sites and 
compressor stations conduct regular (semi-annual, annual, or quarterly) 
fugitive emissions surveys using optical gas imaging technologies.\258\ 
As both agencies have worked to develop their proposed rules, we have 
shared technical information and communicated extensively. We share the 
goal of aligning the final requirements for LDAR in the two rules to 
the maximum extent practicable. At minimum, we would seek to ensure 
that operators could develop a single LDAR program that meets the 
requirements of both agencies. We will continue to focus on this issue 
over the course of the rulemaking process, and we request public 
comment on how best to achieve this goal.
---------------------------------------------------------------------------

    \258\ 80 FR 56593, 56611-56614.
---------------------------------------------------------------------------

(i) LDAR Options in the Proposed Rule
    The BLM proposes under Sec.  3179.302 to require that operators use 
an instrument-based approach to leak detection. Advances in OGI leak 
detection technology, in particular, now allow for affordable detection 
of more, smaller, and less accessible leaks, compared to what would be 
identified through a pure AVO approach. Both Colorado and Wyoming 
require operators to use an instrument-based approach.\259\ In the EPA 
40 CFR part 60 subpart OOOOa rulemaking, OGI is the proposed technology 
for detecting fugitive emissions.
---------------------------------------------------------------------------

    \259\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9, Section XVII.F.3; Wyoming Operational 
Rules, Drilling Rules Section Ch. 8, Section 6(g).
---------------------------------------------------------------------------

    The BLM believes that optical gas imaging is currently the most 
effective instrument for leak detection, but infrared cameras may be 
more expensive than portable analyzers, which are also reasonably 
effective in certain situations. As infrared cameras are used more 
commonly, and the capacity to conduct infrared-based surveys increases, 
the BLM believes that the economics of this method will become 
increasingly favorable for identifying leaks at a wide variety of 
operations. At present, however, infrared cameras are most cost-
effective when used to inspect large numbers of facilities. Thus, the 
BLM believes it is appropriate to require an infrared camera-based 
program for operators with larger numbers of wells, and to allow 
operators with fewer wells to use portable analyzers instead.
    The BLM also seeks to account for advances in continuous emissions 
monitoring technology, and also for other advances in leak detection 
technologies, which may result from ongoing technology development 
efforts such as the DOE ARPA-E MONITOR program. We believe it is 
important to ensure that operators be allowed to take advantage of any 
new, more effective, and less expensive technologies, as they become 
available. Accordingly, the BLM is proposing to require, under Sec.  
3179.302(b), that operators that have 500 or more wells within a BLM 
field office jurisdiction must use one of the following three 
approaches to LDAR: (1) An optical gas imaging device like an infrared 
camera; (2) A new, equally advanced and effective monitoring device, 
not yet developed and therefore not listed in the rule text, which the 
BLM would review and approve for use by any operator; \260\ or (3) A 
comprehensive LDAR program, approved by the BLM, that includes the use 
of instrument-based monitoring devices. The standard for approval of 
options (2) and (3) would be a BLM determination that the alternative 
device or program meets or exceeds the effectiveness for leak detection 
of an optical gas imaging device used with the frequency specified in 
proposed Sec.  3179.303(a).
---------------------------------------------------------------------------

    \260\ The BLM could provide notice to all operators that it had 
found that a specified new technology would satisfy these 
requirements.
---------------------------------------------------------------------------

    Operators with fewer than 500 wells located within a single BLM 
field office's jurisdiction could use any of these three LDAR 
approaches, but they would also have the option of using a portable 
analyzer device, such as a catalytic oxidation, flame ionization, 
infrared absorption or photoionization device, operated according to 
manufacturer specifications, and assisted by AVO inspection.
    The BLM requests comment on the above LDAR proposal. In particular, 
comments should address the appropriateness of requiring the use of 
optical gas imaging devices in some or all circumstances. We request 
data and comment on the appropriateness of using the 500-well threshold 
to identify those larger operators for whom the economics of these 
devices may be more favorable, whether optical gas imaging is cost-
effective for operators with a smaller number of wells, and should 
therefore be required for all operators.
    Further, the BLM requests comment on whether the above suite of 
options for LDAR (three options for large operators, four for smaller 
operators) is reasonable to allow operators flexibility to design and 
implement leak detection programs that work for them, while still 
setting sufficiently rigorous minimum standards to ensure that all such 
programs are comprehensive and effective. In particular, we request 
comment on whether the standard for BLM approval of an alternative 
approach (that it meets or exceeds the effectiveness of an optical gas 
imaging device used at the frequency specified in proposed Sec.  
3179.303(a)) provides sufficient guidance to the BLM, and whether the 
standard would result in adequate consistency across field offices.
    The BLM is also proposing under Sec.  3179.302(a)(4) that operators 
who choose to use portable analyzers would be required to use them 
according to manufacturers' specifications. The EPA's Method 21, 
discussed above, is one specific method for ensuring that portable 
analyzers that are capable of detecting fugitive emissions (or leaks) 
are used in a manner that produces accurate results. The BLM is not 
proposing to require the use of Method 21. The BLM requests comments 
on: (1) Whether this rule should require the use of Method 21 if an 
operator chooses to use a portable analyzer; (2) The adequacy of 
manufacturers' use specifications to produce accurate results regarding 
the presence or absence of a leak; and (3) Whether there are other use 
protocols for portable analyzers that produce accurate results for leak 
detection purposes.
    The BLM also requests comment on whether the regulations should 
include a threshold volume of gas that will be deemed a leak with 
respect to gas losses detected by portable analyzers, and if so, what 
that threshold volume should be. In contrast to optical gas imaging, 
portable analyzers are so sensitive that, at the lowest measured 
levels, it may be difficult to tell whether the analyzer is detecting a 
leak or simply registering background levels of the measured gas. The 
BLM requests comment on whether it should provide that a release of gas

[[Page 6648]]

would be considered a leak if the detected concentration were 500 ppm 
or more above the measured background levels. This would be consistent 
with the EPA's proposed approach, which provides that a leak would be 
considered repaired if a portable analyzer, used according to Method 
21, indicates concentrations less than 500 ppm above background levels.
(ii) Frequency of LDAR Inspections
    Another key element of an effective LDAR program is to define the 
frequency of inspections. Colorado bases its frequency-of-inspection 
requirement on the level of estimated uncontrolled emissions from 
storage vessels or the potential to emit VOCs from all facility 
components.\261\ Inspection frequency can vary from monthly to annually 
depending on the magnitude of the emissions.\262\ Wyoming simply 
requires quarterly inspections.\263\
---------------------------------------------------------------------------

    \261\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9 at Section XVIII.F.3.
    \262\ Ibid.
    \263\ Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015), 
Section 6(g), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.
---------------------------------------------------------------------------

    Multiple studies have found that a relatively small percentage of 
facilities are responsible for the majority of leaks and for most of 
the wasted gas (this is known as a ``fat-tail'' problem).\264\ If some 
operators, in fact, experience proportionally fewer leaks than others, 
this would support allowing the frequency of periodic screening to vary 
depending on the operator's past history of leak detections. Based on 
experience in the field, the BLM believes that there are systematic 
differences among operators' leak rates, but we understand that some 
recent studies indicate that leak rates are random.\265\
---------------------------------------------------------------------------

    \264\ See Zavala-Araiza, et al., Reconciling divergent estimates 
of oil and gas methane emissions, Proceedings of the National 
Academy of Sciences, vol. 112, no. 51, at 15600 (Dec. 22, 2015
    \265\ Ibid.
---------------------------------------------------------------------------

    Increasing survey frequency allows more leaks to be found, but also 
increases costs. Accordingly, the BLM aims to establish an approach to 
survey frequency that reduces the most waste at the lowest cost. The 
Carbon Limits study analyzed the impact of survey frequency by 
analyzing over 400 annual surveys.\266\ This study found that annual or 
semi-annual (twice-yearly) surveys generally resulted in net benefits 
to the operator--the benefits of leaks avoided exceeded the costs of 
the surveys--whereas quarterly or more regular surveys imposed net 
costs on the operator--the costs of the frequent surveys outweighed the 
benefits of leaks avoided. This study supports starting with a 
frequency of annual or semi-annual surveys. We request data and comment 
on the data, methodology, and analysis used in this study.
---------------------------------------------------------------------------

    \266\ Carbon Limits.
---------------------------------------------------------------------------

    Thus, the BLM is proposing under Sec.  3179.303 to require all 
operators to conduct semi-annual surveys of their sites--defined in 
proposed Sec.  3179.303 to mean a discrete area suitable for inspection 
in a single visit and containing wellhead equipment, compressors, and 
facilities \267\ (which would include, for example, separators, heater/
treaters, and liquids unloading equipment). If an operator finds no 
more than two leaks at a site for two consecutive inspections, it may 
change to annual inspections at that site. If the operator is 
inspecting semi-annually and finds three or more leaks at a site for 
two consecutive inspections, it must inspect quarterly. The quarterly 
rate would continue unless and until an operator finds no more than two 
leaks in two sequential inspections, at which point it could revert 
back to twice-yearly inspections. On the other hand, if the operator is 
inspecting semi-annually and finds no more than two leaks for two 
consecutive inspections, the operator may reduce the frequency of 
inspections to once per year, unless and until it finds more than two 
leaks for two consecutive inspections, which would require it to revert 
back to semi-annual inspections.
---------------------------------------------------------------------------

    \267\ Note that the BLM has proposed to define ``facility'' in 
part 3170 as ``(1) A site and associated equipment used to process, 
treat, store, or measure production from or allocated to a Federal 
or Indian lease, unit, or CA that is located upstream of or at (and 
including) the approved point of royalty measurement; and (2) A site 
and associated equipment used to store, measure, or dispose of 
produced water that is located on a lease, unit, or CA.'' 80 FR 
40767 (July 13, 2015).
---------------------------------------------------------------------------

    The BLM has proposed three or more leaks at a site as the threshold 
for increasing the frequency of inspections, and two or fewer as the 
threshold for decreasing the frequency of inspections, as a possible 
way to distinguish between sites with very little loss from leaks and 
sites with more significant leak problems. The BLM requests comment on 
whether these are the appropriate numbers of leaks to use as 
thresholds, and if not, what the threshold levels should be.
    Once a leak is identified, the BLM proposes under Sec.  3179.304 
that the operator would be required to repair the leak as soon as 
practicable, but no later than 15 calendar days after discovery, unless 
there is a good cause necessitating a longer period. The BLM believes 
that a ``good cause'' for a longer period would be something that 
prevents the operator from repairing the leak within the 15 calendar 
day period and that the operator could not reasonably have prevented. 
Examples of potential good cause for a longer period include the 
unavailability of a needed part or severe weather conditions that 
prevent safe access to the site. Preferred scheduling for maintenance 
would not be an example of good cause for delay in leak repair. If a 
delay in repair is attributable to good cause, the operator must notify 
the BLM of the cause and must complete repairs within 15 calendar days 
after the cause of delay ceases to exist. The BLM proposes to require 
operators to verify the effectiveness of a repair within 15 calendar 
days after completion using the same leak detection method used to find 
the leak.
    The BLM proposes under Sec.  3179.305 that operators be required to 
keep and make available to inspectors records documenting the dates of 
leak inspections, the sites where any leaks are found, and a 
description of each leak. Operators would also need to record when 
leaks were repaired, and the dates and results of follow-up inspections 
to verify the effectiveness of the repairs.
    The BLM is aware that some well sites and compressor stations could 
be subject to both the fugitive emission requirements of the proposed 
EPA rule and the requirements of the proposed BLM rule. In addition to 
our request for comments discussed above, regarding further alignment 
of the BLM rule and the EPA rule, we are proposing that an operator may 
demonstrate to the BLM that it is complying with the EPA LDAR 
requirements in lieu of the BLM LDAR requirements, for some or all of 
the operator's sites. We specifically request comment on this element 
of the proposal, including whether it would help to reduce the 
compliance burden on operators, whether it could compromise program 
effectiveness in any way, and whether it may present challenges for BLM 
and EPA to administer and enforce. The BLM expects that the LDAR 
requirements ultimately adopted by the EPA for new and modified well 
sites would be as effective in minimizing the volume of gas lost 
through leaks as the final BLM requirements, and we should be able to 
confirm this expectation prior to finalizing this proposed provision.
(iii) Possible Alternatives to the Proposed LDAR Provisions
    In addition to the BLM's proposed approach, we are taking comments 
on other possible approaches to reducing waste through LDAR 
requirements.

[[Page 6649]]

These include variations on the proposed approach, an alternative 
approach suggested by a stakeholder, and an alternative method of 
establishing the inspection frequency.
    One small variation on the proposed LDAR approach would be to 
require that LDAR inspections be conducted by third parties. Requiring 
third parties to conduct inspections could provide additional assurance 
that surveys are conducted effectively and produce accurate results. 
While some operators conduct their own inspections, many already 
contract with third parties that provide the equipment, trained 
operators, and detailed reports. The BLM acknowledges, however, that 
third-party contracting might in some instances be more costly and 
might prove unnecessary for operators that have their own equipment and 
substantial in-house expertise. A variation on this option would 
require periodic third party inspections as a means of confirming the 
efficacy of an operator's internal leak detection program, while still 
allowing most inspections to be conducted in-house, if an operator so 
chooses. For example, the BLM could require that operators contract 
with a third-party to perform at least one annual or biannual 
inspection. The BLM requests comments on these options.
    A second possible variation would be to constrain approval of 
alternative leak detection approaches. For example, the BLM could limit 
authorization of alternatives to new technologies and devices, rather 
than new detection programs. (That is, the final rule could eliminate 
proposed Sec.  3179.302(a)(3).) Another approach would be to limit 
authorization for an alternative leak detection program under proposed 
Sec.  3179.302(a)(3) to operators that already have an effective 
program in place as of the effective date of this rule. That approach 
would reward operators that proactively invest in leak detection, but 
would require operators that do not make that proactive investment to 
comply with the standards established in the regulation. The BLM 
requests comment on these variations.
    A third possible variation would be to focus operators' LDAR 
efforts on higher production wells. For example, a stakeholder 
suggested that the BLM could require the development of an LDAR program 
at those wells in the top 75 percent of an operator's inventory, in 
terms of production volume, and address storage vessels separately. 
Under this suggested approach, the operator would be required to 
conduct an initial survey of its top-producing wells, and would then 
design an appropriate leak detection program, with a specified 
frequency based on the results of that survey.
    Others have suggested modifying or waiving the LDAR requirements 
for stripper wells--a specific category of low-yield wells producing 15 
bbl of oil-equivalent per day or less. In its 40 CFR part 60 subpart 
OOOOa rulemaking, for example, EPA proposed that new and modified wells 
producing 15 bbl of oil-equivalent per day or less be exempted from the 
LDAR requirements, or allowed to inspect less frequently, such as 
annually or on a one-time basis. Presumably, modifying the LDAR 
requirements for stripper wells relies on an assumption that the amount 
of leaked methane correlates with well production, and therefore 
frequent LDAR is not a cost-effective means of reducing methane 
emissions from low-producing wells. In addition, proponents of this 
approach assert that LDAR requirements for marginal wells would 
disproportionately impact small businesses.
    This rulemaking does not propose a modified standard for stripper 
wells, because 85 percent of oil wells and 73 percent of gas wells on 
Federal and Indian leases meet the definition of stripper wells.\268\
---------------------------------------------------------------------------

    \268\ U.S. Energy Information Administration. United States 
Total 2009 Distribution of Wells by Production Rate Bracket, 
available at http://www.eia.gov/pub/oil_gas/petrosystem/us_table.html.
---------------------------------------------------------------------------

    Thus, while reducing the frequency of leak detection inspections 
for stripper wells might decrease the costs of the leak detection 
requirement, we believe that approach would negate most of the expected 
benefits of the LDAR requirement for existing leases on Federal and 
Indian lands.
    Moreover, the factual record available to the BLM indicates that 
requiring leak detection at stripper wells would produce significant 
gas savings. Recent studies do not support the suggestion that leak 
rate correlates with yield. Rather, these studies suggest that even 
low-yield wells can leak at significant rates.\269\ Based on these 
studies, DOI does not believe it is appropriate to exclude low-yield 
wells from any instrument-based inspection requirement, or to allow 
those wells to be inspected less frequently.
---------------------------------------------------------------------------

    \269\ See Zavala-Araiza et al., Reconciling divergent estimates 
of oil and gas methane emissions, Proceedings of the National 
Academy of Sciences, vol. 112, no. 51, at 15600 (Dec. 22, 2015).
---------------------------------------------------------------------------

    Establishing a separate standard for stripper wells also would not 
align the proposed BLM requirements with the proposed EPA requirements. 
The EPA's standard for stripper wells applies only to new or modified 
wells that come online as stripper wells, not to wells that initially 
produce at higher rates, but eventually decline to stripper status. 
Based on our experience in the field, we believe that a very small 
number of wells would qualify for a relaxed standard under the EPA 
proposal. In our experience, most new wells produce at rates higher 
than 15 barrels-of-oil-equivalent per day, because operators are 
unlikely to invest in completing newly drilled wells that produce at 
very low rates.
    Many of the stripper wells producing from Federal and Indian leases 
are existing wells that once produced at higher rates, but have 
declined to stripper status, and they therefore would not qualify for 
the EPA's LDAR standards for stripper wells. Thus, although the BLM 
recognizes the importance of harmonizing this rule with EPA's proposed 
40 CFR part 60 subpart OOOOa rulemaking, establishing a different LDAR 
standard for existing stripper wells on Federal or Indian leases would 
not, in fact, advance that goal.
    Another alternative approach to the proposed LDAR requirements 
would be to retain all of the elements of the proposed approach, except 
the basis for setting the required frequency of inspections. 
Specifically, rather than having the frequency vary based on the 
results of previous surveys, the inspection frequency would be set 
based on the type of facility being inspected. As noted previously, 
Colorado uses this method, with frequencies that range from monthly to 
one-time, depending on the type of facility and the level of 
uncontrolled VOC emissions.
    One simplification of the Colorado approach would be to focus on 
sites with vibrating equipment or storage vessels. Industry 
stakeholders have stated that they find most leaks at sites with 
equipment that vibrates (e.g., compressors), and at sites with storage 
vessels. Thus, requiring more frequent inspections at sites with those 
characteristics, and less frequent inspections at other sites, might be 
a way to increase the cost effectiveness of the LDAR program by 
targeting inspections to the sites most likely to produce the largest 
losses through leaks.
    A different simplification of Colorado's system would be to 
distinguish between gas wells and oil wells, requiring more frequent 
inspections at gas wells and less frequent inspections at oil wells. 
EPA's emissions factors indicate generally higher volumes of fugitive 
emissions

[[Page 6650]]

from gas wells, compared to oil wells.\270\ Assuming these emissions 
factors are accurate, this indicates that focusing more inspection 
resources on gas than oil wells would identify and save a relatively 
larger volume of gas at roughly the same cost.
---------------------------------------------------------------------------

    \270\ 80 FR 56593, 56635.
---------------------------------------------------------------------------

(iv) Requests for Comments on LDAR Alternatives
    The BLM requests comment on all of the LDAR variations discussed 
above. In particular, the BLM requests comment on:
     The initial frequency of surveys;
     Requiring more frequent surveys, such as quarterly;
     The concept of changing inspection frequency depending on 
the operators' record of past leaks;
     The triggers for increasing and decreasing inspection 
frequency (e.g., whether finding a certain number of leaks is the 
appropriate trigger for changing inspection frequency); and
     Whether the frequency of inspections should be the same 
across all of the sites on a lease, and if so, how to operationalize 
that requirement.
    In connection with any comments related to modifying the inspection 
frequency for stripper wells, the BLM specifically requests submission 
of data regarding the relationship between well production and levels 
of leaked methane from a well site. The BLM also requests comment on 
whether it should require gas wells to be inspected quarterly and oil 
wells annually. While there is substantial uncertainty in the cost-
benefit analysis of these provisions, with certain simplifying 
assumptions, the analysis indicates that this alternative approach 
could increase net benefits, compared to the proposed approach. As 
detailed in the RIA, the projected annual net benefits for a semi-
annual inspection requirement for all wells range from $19-48 million, 
with the range largely depending on the year, compared to annual net 
benefits of $3-43 million (again largely depending on the year) with 
quarterly inspections for gas wells and annual inspections for oil 
wells.\271\
---------------------------------------------------------------------------

    \271\ RIA at 113.
---------------------------------------------------------------------------

    In addition, the BLM requests comment on simply requiring semi-
annual or quarterly inspections for all well sites, facilities, and 
compressor stations subject to the LDAR requirements, with no mechanism 
to increase or decrease inspection frequency based on how many leaks 
are found. A quarterly inspection requirement would track the Wyoming 
approach for the Upper Green River Basin. Requiring semi-annual or 
quarterly inspections for all sites would reduce the potential 
confusion of inspection frequencies that vary over time and across an 
operator's well sites. Tracking the required frequency for each 
discrete leak inspection site could be burdensome and prone to error 
and confusion. Requiring quarterly inspections would also maximize the 
gas savings from avoided leaks, although it would have higher costs 
than the other approaches discussed here. As with setting different 
frequencies for gas and oil wells, this approach would not track with 
the EPA's LDAR requirements, assuming that the EPA finalizes its 
proposed approach.
    The BLM also requests comment on the approach of focusing the LDAR 
requirement on sites with vibrating equipment or storage tanks, perhaps 
by requiring a one-time inspection of all sites, but quarterly 
inspections of sites with such equipment. Would that approach 
successfully target sites that are most prone to significant leaks? 
Would it reduce costs for operators? And finally, could it readily be 
enforced?
    Finally, the BLM notes that many of these LDAR approaches deviate 
from EPA's proposed approach. The BLM requests comment on the 
importance and implications of aligning BLM and EPA LDAR requirements.
(v) Costs of the LDAR Provisions
    Assuming that the EPA finalizes its 40 CFR part 60 subpart OOOOa 
rulemaking, then the BLM expects that its proposed requirements would 
affect 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 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.\272\ We request data and comment on whether 
this analysis fully captures the benefits of identifying and fixing 
high-volume leaks.
---------------------------------------------------------------------------

    \272\ 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 from our proposed LDAR requirements. We project that the 
proposed 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 they would 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 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.\273\
---------------------------------------------------------------------------

    \273\ RIA at 108-109.
---------------------------------------------------------------------------

    As noted, some operators reportedly already have leak detection 
programs in place. To the extent that these operators currently have 
LDAR programs that are approved by the BLM, the actual impacts of this 
proposal would be lower than these estimates.
3. Pneumatic Controllers and Pneumatic Pumps
    Pneumatic controllers are automated instruments that control 
certain processes or conditions, such as liquid level, pressure, and 
temperature in oil and gas production, treatment, storage, and handling 
operations. Pneumatic controllers are operated by gas pressure, and the 
gas is emitted from the device when the device is active. Some types of 
controllers ``bleed'' gas continuously as part of their normal 
operations, while others emit gas intermittently. While these 
controllers can operate using any pressurized gas, for the purposes of 
this proposed rule, the term pneumatic controller means an instrument 
that is operated by natural gas pressure and emits natural gas.
    Pneumatic pumps of different varieties are commonly used in oil and 
gas production and treating operations. For example, gas-assist glycol 
dehydrator pumps are used to circulate glycol in dehydrators. Chemical 
injection pumps are used to pump chemicals down a well to facilitate 
production or into a pipeline to prevent

[[Page 6651]]

freezing. Diaphragm pumps are used to move larger volumes of liquids, 
such as to circulate heat trace medium at well sites during cold winter 
conditions, or to pump out sumps. Similar to pneumatic controllers, 
pneumatic pumps can operate on gas pressure and emit that same gas from 
the pump. For the purposes of this proposed rule, the term pneumatic 
pump means a pump that is operated by natural gas pressure and emits 
natural gas.
(a) Estimates of Gas Released From Pneumatic Controllers and Pneumatic 
Pumps
    As described in the RIA, using data from the EPA GHG Inventory, we 
estimate that about 5.4 Bcf of natural gas was lost in 2013 from 
pneumatic controllers on BLM-administered leases.\274\ That volume 
includes releases from high bleed continuous controllers, low bleed 
continuous controllers, and intermittent controllers. Using prevalence 
data from the EPA and an analysis of EPA GHGRP data conducted by ICF, 
we estimate that there are 18,150 high bleed pneumatic controllers on 
BLM-administered leases, or about 19 percent of the total number of 
pneumatic controllers on these leases. In addition, using data from the 
EPA's GHG Inventory, we estimate that about 2.5 Bcf of natural gas was 
lost in 2013 from pneumatic pumps on BLM-administered leases. That 
volume includes releases from chemical injection pumps, diaphragm 
pumps, and gas-assist glycol dehydrator pumps.
---------------------------------------------------------------------------

    \274\ RIA at 18.
---------------------------------------------------------------------------

(b) Technologies To Reduce Quantities of Gas Released From Pneumatic 
Controllers and Pneumatic Pumps
    Pneumatic controllers and pneumatic pumps are common equipment at 
well site facilities. For well sites without electrical service, gas 
pressure is used as a ready energy source to operate this equipment. 
There are several options for minimizing the amount of natural gas that 
is used and emitted from existing controllers and pneumatic pumps, 
which bear a range of associated cost and practicality considerations.
    As discussed earlier in Sec.  III.I.3, in the existing EPA NSPS 
rule (40 CFR part 60 subpart OOOO) for the oil and gas sector, the EPA 
established an emissions rate of 6 scf/hour as the upper limit for new 
and replacement pneumatic controllers (pneumatic controllers meeting 
this standard are referred to as ``low-bleed'' pneumatic 
controllers).\275\ The EPA NSPS requires new and replacement natural-
gas-operated pneumatic controllers at natural gas well sites and 
gathering and boosting stations to meet the 6 scf/hour limit, unless a 
higher bleed rate is necessary for safety or to perform the designed 
function. The EPA NSPS requirement does not currently apply to 
intermittent pneumatic controllers nor to pneumatic pumps, but the 
EPA's proposed 40 CFR part 60 subpart OOOOa rulemaking would extend to 
new or modified pneumatic pumps.\276\
---------------------------------------------------------------------------

    \275\ 40 CFR 60.5390.
    \276\ 80 FR 56593, 56610.
---------------------------------------------------------------------------

    Existing high-bleed controllers can generally be replaced with 
models that use and emit less natural gas. For most applications, low-
bleed controllers are available and make suitable replacements for 
high-bleed controllers. At facilities with a gas sales line, the 
replacement cost of low-bleed controllers is generally rapidly offset 
by gas savings. ICF identified replacement of high-bleed pneumatic 
controllers with low-bleed pneumatic controllers as one of the most 
cost-effective options for reducing methane. Specifically, ICF 
estimated that the replacement would save industry $2.65 per Mcf of 
avoided methane emissions.\277\
---------------------------------------------------------------------------

    \277\ ICF economic analysis, at 4-4 (base case assumed $4/Mcf 
price for recovered gas and a 10 percent discount rate/cost of 
capital).
---------------------------------------------------------------------------

    The State of Colorado has prohibited use of ``high bleed'' 
pneumatic controllers, with limited exemptions.\278\ Colorado adopted 
the existing EPA NSPS standards for new pneumatic controllers, 
prohibiting operators from installing new ``high bleed'' controllers, 
and the State required operators to replace all existing high bleed 
controllers with low-bleed or no-bleed controllers by May 1, 2015.\279\ 
The operator may request an exception on the grounds that use of a 
high-bleed controller is needed for safety or process purposes. As of 
April 2015, however, the State had not received a single request to use 
or keep high bleed controllers under this provision.\280\
---------------------------------------------------------------------------

    \278\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9, Section XVIII, available at https://www.colorado.gov/pacific/sites/default/files/5-CCR-1001-9_0.pdf.
    \279\ Ibid. at Section XVIII.C.2.
    \280\ Email from Daniel Bon, Air Quality Planner, Planning and 
Policy, Air Pollution Control Division, Colorado Department of 
Public Health and Environment, to Alexandra Teitz, BLM (April 27, 
2015).
---------------------------------------------------------------------------

    In May of this year, the State of Wyoming adopted regulations that 
require operators in the Upper Green River Basin to replace high-bleed 
pneumatic controllers with low-bleed controllers by January 1, 
2017.\281\
---------------------------------------------------------------------------

    \281\ Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015), 
Section 6(f), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.
---------------------------------------------------------------------------

    Another option that is available in some situations is adding 
electrical service (power line, generator, or solar array) and 
replacing pneumatic controllers and/or pneumatic pumps with electric or 
compressed air controllers and pumps, which do not release any natural 
gas. Where electrical service is available, existing pneumatic 
controllers and pneumatic pumps could be operated by the addition of a 
compressed air system. Installing a compressed air system would involve 
adding a compressor and tubing to connect each controller and pump to 
the system. Alternatively, pneumatic controllers and pneumatic pumps 
could be replaced by electric models. At facilities with a gas sales 
line, the cost of replacing electric controllers and operating the 
power system would be at least partially offset by sale of the gas that 
would otherwise have been vented through operation of the pneumatic 
controllers and pneumatic pumps. Natural gas could be used to generate 
electricity to operate electronic controllers; based on the typical 
number of controllers at a well site and the energy requirements of 
controllers, however, the BLM does not believe this is the most 
efficient means of completing the operational objective.
    One of the more common applications of this approach is to use 
solar powered electric controllers and pumps to replace individual 
pneumatic controllers and pneumatic pumps without replacing the power 
system for the whole facility. Solar pumps are often used to replace 
pneumatic chemical injection pumps, in particular. Chemical injection 
pumps are smaller pumps that inject chemicals into a pipeline to, e.g., 
to inhibit freezing, and they do not require as much power as larger 
pumps used in other applications. The EPA's Natural Gas STAR program 
cites the costs to replace a pneumatic pump with a solar-charged 
electric pump as about $2,000. Operating costs are minimal, and the 
lifespans of the solar panels and electric motors are up to 15 and 5 
years, respectively. The EPA estimates potential annual natural gas 
savings of 183 Mcf per pneumatic pump replaced--a volume that would 
have a sales value of $732 (at $4/Mcf).\282\
---------------------------------------------------------------------------

    \282\ U.S. EPA, Office of Air Quality Planning and Standards, 
Oil and Natural Gas Sector Pneumatic Devices Report for Oil and 
Natural Gas Sector Pneumatic Devices Review Panel (April 2014) at 
53.
---------------------------------------------------------------------------

    A third option for reducing gas losses from pneumatic controllers 
and pneumatic pumps is to add a low-pressure collection system that 
would capture the natural gas emitted from pneumatic controllers and 
pneumatic

[[Page 6652]]

pumps and either combust it or re-pressure and route it into the 
natural gas sales stream.
    The State of Wyoming has adopted 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.\283\
---------------------------------------------------------------------------

    \283\ Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015), 
Section 6(e), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.
---------------------------------------------------------------------------

(c) Proposals To Reduce Waste From Pneumatic Controllers and Pneumatic 
Pumps
    The BLM believes that replacing high-bleed pneumatic controllers 
with low- or no-bleed controllers is a cost-effective way to reduce 
waste of natural gas. In most cases, this is projected to increase 
operators' net profits. We have heard from one company that has already 
voluntarily replaced all of its high-bleed pneumatic controllers 
because it found that the new equipment more than paid for itself 
within 3 to 6 months.\284\ Given the EPA requirements for new pneumatic 
controllers and the fact that, on average, this waste-reduction measure 
would save companies money, the BLM believes that continued reliance on 
high-bleed pneumatic controllers leads to avoidable waste of public 
resources, except in limited situations.
---------------------------------------------------------------------------

    \284\ Phone conversation with Conoco Phillips on San Juan Basin 
operation, February 2015.
---------------------------------------------------------------------------

    Under proposed Sec.  3179.201, the BLM would require operators to 
replace all pneumatic controllers that have bleed rates greater than 6 
scf/hour with low-bleed or no-bleed pneumatic controllers within 1 year 
of the effective date of the final rule. This rule would apply only to 
pneumatic controllers that are not subject to the EPA regulations at 40 
CFR 60.5360 through 60.5390. We request comment on whether 1 year is an 
appropriate amount of time for compliance, and whether we should 
include interim deadlines for the replacement requirement such that 
operators must replace certain percentages of their pneumatic 
controllers within specified timeframes.
    In Sec.  3179.201(b), the BLM is proposing several exemptions to 
the replacement requirement. Like the existing EPA NSPS, this proposed 
rule would allow an exception to the maximum emission rate for a 
pneumatic controller when the operator demonstrates, and the BLM 
concurs, that a higher emission rate is necessary for response time, 
safety, and positive actuation. The proposed rule would also provide 
for an exception from the replacement requirement if the requirement 
would 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.
    In addition, under proposed Sec.  3179.201(c), the BLM would allow 
an operator to retain a high-bleed pneumatic controller for up to 3 
years from the effective date of the final rule, if the well or 
facility served by the controller has an estimated remaining productive 
life of no more than 3 years from the effective date of the final rule. 
The BLM believes the 3-year threshold represents the typical payback 
period for a replacement controller, given an average-cost replacement 
device, average reduction in waste gas, and an average value for the 
recovered gas. We request comment on whether this extension is needed 
and whether it would meaningfully reduce costs for operators with wells 
and facilities with remaining productive lives less than 3 years from 
the effective date of this rule. We also request comment on whether 
providing this extension would increase waste of gas and make 
implementation of the replacement requirement more difficult, as the 
actual remaining productive life of a well or facility may be longer 
than projected. We note that neither Colorado nor Wyoming provides for 
such an extension.
    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 (using a 7 percent 
discount rate) or $5 million per year (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 (including the cost savings from the value of the gas) 
would be $53-68 million per year (using a 7 percent discount rate) or 
$54-73 million per year (using a 3 percent discount rate), along with a 
reduction in VOC emissions of about 200,000 tpy.\285\
---------------------------------------------------------------------------

    \285\ RIA at 78.
---------------------------------------------------------------------------

    For pneumatic chemical injection pumps, the BLM believes that in 
many instances the function performed by such a pump could be performed 
by a zero-emissions pump (typically solar) instead. The BLM believes 
that the replacement costs in these situations are relatively modest 
and would be at least partially offset by the value of the saved gas. 
Where a zero-emissions pump could not perform the function, but a flare 
is available on-site, the cost of routing the gas from either a 
chemical injection pump or a diaphragm pump to a flare is expected to 
be quite small.
    Thus, the BLM is proposing under Sec.  3179.202 to require the 
operator either: (1) To replace a pneumatic chemical injection or 
diaphragm pump with a zero-emissions pump; or (2) To route the 
pneumatic chemical injection or diaphragm pump to a flare. Under 
proposed Sec.  3179.202(c), an operator would be exempt from this 
requirement if it demonstrates, and the BLM concurs, that: (1) There is 
no existing flare device on site, or routing to such a device is 
technically infeasible; and (2) A zero-emission pump is not a viable 
alternative because a pneumatic pump is necessary based on functional 
needs. 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. This rule would 
apply only to pneumatic pumps that are not subject to the EPA 
regulations. As with pneumatic controllers, the BLM proposes that 
operators must replace pneumatic pumps or route to a flare device, 
subject to this proposed section, within 1 year of the effective date 
of the rule, or within 3 years of the effective date of the rule if the 
pneumatic pump serves a well or facility with an estimated remaining 
productive life of 3 years or less. We request comment on whether this 
extended time-period for replacement is needed or whether a shorter 
time-period would be sufficient. In Wyoming, pneumatic pump replacement 
is now required by regulation by January 1, 2017.\286\
---------------------------------------------------------------------------

    \286\ Wyoming, Nonattainment Area Regulations Ch. 8, Section 
6(e) (June 2015), available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.

---------------------------------------------------------------------------

[[Page 6653]]

    If the EPA finalizes its concurrent 40 CFR part 60 subpart OOOOa 
rulemaking, the BLM estimates that the proposed 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 $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.\287\
---------------------------------------------------------------------------

    \287\ 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.\288\
---------------------------------------------------------------------------

    \288\ RIA at 81.
---------------------------------------------------------------------------

    We request comment on the practicality and costs of replacing 
pneumatic chemical injection and diaphragm pumps with solar pumps or 
routing the pump exhaust to a flare that is already installed on-site, 
including whether 1 year is an appropriate amount of time for 
compliance.
    Unlike pneumatic chemical injection and diaphragm pumps, the BLM 
has not identified a cost-effective means to reduce gas releases from 
gas-assist glycol dehydrator pumps at sites that are not connected to 
the electric grid, and thus we are not proposing any requirements to 
reduce gas losses from gas-assist glycol dehydrator pumps. The BLM 
requests comment, however, on whether there are additional measures 
that could further reduce gas lost from pneumatic pumps.
4. Storage Vessels
    Storage vessels are ubiquitous in oil and gas production. Crude oil 
and condensate storage vessels are designed to hold a slight back-
pressure. When the pressure in the vessel exceeds the back-pressure--
due to fluids being added or an increase in temperature of the vessel 
contents--vapors are allowed to escape, thereby equalizing the pressure 
inside the vessel. Released vapors are a lost source of energy and 
revenue, and they also represent a safety and health concern for on-
site workers. In addition, these vapors, which may contain methane, 
ethane, and a variety of VOCs, contribute to local air pollution 
problems. The significance of vapor loss, in terms of energy losses, 
revenue losses, safety risks and environmental impacts, depends upon 
the volume and composition of the released vapors.
    New, modified, and reconstructed storage vessels used in oil and 
natural gas production, natural gas processing, and natural gas 
transmission and storage are already subject to emissions limits under 
the EPA NSPS, which requires that individual storage vessels with 
potential to emit VOC emissions equal to or greater than 6 tpy achieve 
at least a 95 percent reduction in VOC emissions.\289\ The EPA 
standards also provide that if a storage tank that initially emitted at 
least 6 tpy of VOCs now emits less than 4 tpy without considering any 
emission controls in place for a period of 12 consecutive months, 
emission controls are not required if the operator monitors regularly 
to ensure that emissions do not exceed 4 tpy.\290\ Unmodified storage 
vessels that were in place as of August 23, 2011, are currently allowed 
to vent vapors uncontrolled, unless subject to State controls.\291\ EPA 
requires operators to determine the VOC emission rate within 30 days, 
and storage vessels must have a cover and closed vent system that meets 
specifications.\292\
---------------------------------------------------------------------------

    \289\ 40 CFR 60.5395.
    \290\ Ibid.
    \291\ Ibid.
    \292\ 40 CFR 60.5395, 60.5415-5416.
---------------------------------------------------------------------------

    Colorado requires the capture or combustion of vapors from storage 
vessels with a capacity to emit 6 tpy VOC or more.\293\ The control 
equipment must reduce hydrocarbons by 95 percent, or by 98 percent if 
the operator uses a combustion device.\294\ Storage vessels that 
require emission control systems are also subject to increased 
monitoring, and Colorado requires operators to develop STEM plans.\295\
---------------------------------------------------------------------------

    \293\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9, Section XVII.C.
    \294\ Ibid.
    \295\ Ibid.
---------------------------------------------------------------------------

    In the Upper Green River Basin, Wyoming requires that when VOC 
emissions from vessels or glycol dehydrators are at least 4 tpy, the 
operator must reduce those emissions by 98 percent.\296\
---------------------------------------------------------------------------

    \296\ Wyoming Operational Rules, Drilling Rules Section Ch. 8, 
Section 6(d).
---------------------------------------------------------------------------

(a) Estimates of Quantities of Gas Lost From Storage Vessels
    The quantity of gas released from condensate and storage vessels 
depends on the throughput volumes of those vessels and how much gas is 
lost for a given volume of throughput. These loss rates vary depending 
on whether the vessel is controlled or uncontrolled and on the region 
of the country in which it is located. We estimate that 2.77 Bcf of 
natural gas was lost in 2013 from storage vessels venting on Federal 
and Indian lands.\297\ These estimates were calculated using data from 
the 2015 GHG Inventory and the share of natural gas and crude oil 
production coming from Federal and Indian lands.
---------------------------------------------------------------------------

    \297\ RIA at 18.
---------------------------------------------------------------------------

(b) Technologies and Practices To Reduce Gas Losses From Storage 
Vessels
    Storage vessel vapors can be controlled by routing them to a flare 
or combustor, or by installing a VRU, which collects and compresses the 
vapors and returns them to the vessel or into a natural gas sales line.
    Where a well facility is equipped with a flare pit or flare stack, 
tank vapors could be routed to that flare device. With a properly 
designed manifold, these flare devices can meet the 95 percent emission 
control standard established in the current EPA NSPS.\298\
---------------------------------------------------------------------------

    \298\ 40 CFR part 60 subpart OOOO.
---------------------------------------------------------------------------

    Combustors are enclosed devices that efficiently combust tank 
vapors by ensuring an optimal mix of air and flammable vapor entering 
the combustion chamber. Combustors meet the 95 percent emission control 
standard established in the existing EPA NSPS. Combustors can be sized 
for a specific volume of natural gas/vapors, or can be operated in 
series to accommodate a wide volume range. Combustors are not dependent 
on other equipment or operating conditions and therefore have wide 
applicability.
    In proposing the existing NSPS rule, EPA estimated that the average 
operating cost of a flare device (which

[[Page 6654]]

includes both flares and combustors) is $8,900 per year, assuming that 
a flare device is already in place at the facility.\299\
---------------------------------------------------------------------------

    \299\ 76 FR 52738 (Aug. 23, 2011).
---------------------------------------------------------------------------

    VRUs meet the 95 percent emission control standard established in 
the EPA NSPS, and because the vapors are captured, there are no 
combustion emissions. Applicability of VRUs is limited by a number of 
conditions. VRUs require a power source, and a gas line must be 
available into which the controlled vapors can be directed. Due to 
their relatively high cost of operation (which EPA estimated at $18,900 
per year in proposing its 2012 NSPS rule\300\), the economic viability 
of a VRU as a storage tank emission control device depends on high 
production throughput. In other words, net VRU costs rise as production 
volumes decline.
---------------------------------------------------------------------------

    \300\ Ibid.
---------------------------------------------------------------------------

(c) Proposals To Minimize Vapor Losses From Storage Vessels
    Under proposed Sec.  3179.203, the BLM would address gas losses 
from storage vessels that are not covered by the EPA standards for new 
and modified storage vessels--or, by and large, existing, unmodified 
storage vessels. The BLM believes that reducing venting from existing 
storage vessels with higher rates of venting is a reasonably cost-
effective means of reducing gas losses. We also believe that rather 
than establishing new and separate standards for venting from existing 
vessels, it would be easier for operators to comply if we require 
existing vessels on Federal and Indian leases to meet the same 
standards that already apply to new, rebuilt, and modified vessels on 
those leases.
    The aim of this proposed rule is to reduce waste of whole gas. 
Nevertheless, the BLM believes that it may be appropriate to express 
the requirements for storage vessels as a VOC standard (as a proxy) 
rather than a whole gas standard, as EPA and Colorado do. There is no 
uniform conversion factor to translate a VOC standard like that 
established by EPA and Colorado into a whole gas standard. The ratio of 
VOCs leaked to hydrocarbons leaked depends on the makeup of the gas in 
the particular vessel. We propose to adopt the same standard that EPA 
applies to new storage vessels. Specifically, the BLM proposes to 
require, under Sec.  3179.203(c), that VOC emissions from existing 
vessels with VOC emissions equal to or greater than 6 tpy be routed to 
a combustion device, continuous flare, or sales line. Under proposed 
Sec.  3179.203(d), these requirements would no longer apply if the 
uncontrolled VOC emissions fall below 4 tpy for 12 months. This 
proposed lower bound addresses the fact that well production, and hence 
gas losses from vessels, are expected to decline over time, and it is 
less cost-effective to require control of lower volumes of tank 
venting. The 6 tpy and 4 tpy thresholds are consistent with EPA 
regulations.\301\
---------------------------------------------------------------------------

    \301\ 40 CFR 60.5395.
---------------------------------------------------------------------------

    We request comments on the approach of applying EPA's new source 
threshold to existing storage vessels, to facilitate efficient 
compliance for the industry.
    The proposed 6 tpy threshold tracks Colorado's standard for new 
storage vessels.\302\ The threshold is somewhat less stringent than 
Wyoming's requirements, which apply to facilities with VOC emissions of 
4 tpy or more and extend to glycol dehydrators, which the BLM does not 
propose to regulate.\303\ The BLM also requests comment on applying a 
more stringent threshold consistent with Wyoming's requirements.
---------------------------------------------------------------------------

    \302\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9, Section XVII.C.
    \303\ Wyoming Operational Rules, Drilling Rules Section Ch. 8, 
Section 6(d).
---------------------------------------------------------------------------

    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).\304\ 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.\305\
---------------------------------------------------------------------------

    \304\ RIA at 95.
    \305\ Ibid.
---------------------------------------------------------------------------

5. Well Maintenance and Liquids Unloading
    Over time, as well pressure in a natural gas well drops, liquids 
often start accumulating at the bottom of the well, which can then slow 
or halt gas production. Operators must remove or ``unload'' the liquids 
to maintain or restore production. Some of the methods used for liquids 
unloading can release substantial quantities of natural gas into the 
environment. In particular, operators sometimes allow the bottom hole 
pressure to increase and then vent or ``blow down'' or ``purge'' the 
well.
(a) Estimates of Quantities of Gas Lost Through Well Maintenance and 
Liquids Unloading
    The amount of gas lost through liquids unloading varies 
substantially across regions, and also depends on whether wells are 
equipped with plunger lifts. We estimate that 3.26 Bcf of natural gas 
was lost in 2013 during liquids unloading operations on Federal and 
Indian lands, with 1.1 Bcf lost from wells with plunger lifts and 2.16 
Bcf lost from wells without plunger lifts.\306\ These estimates were 
calculated using data from the GHG Inventory, including the regional 
prevalence of wells with and without plunger lifts, and emissions 
factors for each. We chose to calculate emissions using a bottom-up 
approach for this emissions source because the prevalence of liquids 
unloading with and without plunger lifts and the emissions factors for 
each vary across regions. We then applied the prevalence and emissions 
factors to the number of producing gas wells on Federal and Indian 
lands as of January 1, 2014.
---------------------------------------------------------------------------

    \306\ RIA at 128-129.
---------------------------------------------------------------------------

(b) Technologies and Practices To Reduce Gas Losses From Well 
Maintenance and Liquids Unloading
    Technological developments have reduced the need for operators to 
unload liquids by venting a well to the atmosphere. Many companies use 
automated systems that rely on well pressure or timers to unload 
liquids using plunger lifts. More recent technology allows companies to 
use well data to optimize liquids unloading, a technique sometimes 
called ``smart'' automation. These ``smart'' systems reduce unnecessary 
unloading events and can dramatically cut venting from liquids 
unloading. For example, according to the Natural Gas STAR Report in 
2006, BP reported installing plunger lifts with smart automated control 
systems on approximately 2,200 wells, which resulted in annual savings 
of 900 Mcf per well.\307\ For a $12 million capital investment, BP 
realized a $6 million total annual savings.\308\ Automated systems, 
whether ``smart'' or more conventional, are particularly useful for 
wells located in remote areas, typical of BLM lands, as they help

[[Page 6655]]

maintain the well even when operators are not present.
---------------------------------------------------------------------------

    \307\ EPA PowerPoint presentation found at http://www3.epa.gov/gasstar/documents/workshops/fortworth-2006/gremillion.pdf.
    \308\ Ibid.
---------------------------------------------------------------------------

    Advanced reservoir-energy management and optimized liquids-
unloading management can reduce the frequency of well venting and the 
quantity of resulting emissions. These management practices can reduce 
venting from wells with or without plunger lifts. There are a wide 
variety of artificial lift systems to unload gas wells, which may be 
applied based on the specific mechanical conditions of the well and the 
conditions of the reservoir. Some of these methods are described below.
    One method that can be effective when a well first exhibits signs 
of liquid loading is to temporarily shut-in the well to allow the 
pressure to increase. The well is then cycled on at a high rate to 
unload the well. This method is inexpensive, but as pressures in the 
well decline, it becomes less effective.
    Using surfactants (or soap injection) is another option. With this 
method, a foaming agent is injected in the casing/tubing annulus by a 
chemical pump on a timer. The gas bubbling through the soap-water 
solution creates gas-water foam, which is more easily lifted to the 
surface for water removal. Capital and startup costs to install soap 
launchers range from $500-$3,880 per well.\309\
---------------------------------------------------------------------------

    \309\ EPA, Natural Gas STAR Program, 2011, http://www3.epa.gov/gasstar/documents/ll_options.pdf.
---------------------------------------------------------------------------

    Another option is to change the tubing in a well to smaller 
diameter ``velocity strings.'' Much like a narrowing in a river, these 
smaller diameter strings result in a higher fluid velocity at any given 
volumetric flow rate, and as a result these strings provide higher 
liquid lift capabilities. As reservoir pressure decreases, however, 
this method is less effective because of the increased friction in the 
smaller diameter tubing. Capital and installation costs provided from 
industry range from $7,000-$64,000 per well.\310\ Other operators use 
compression to reduce flowing operating pressure, thus reducing flowing 
bottomhole pressure, which increases inflow from the reservoir. This is 
a means of achieving higher well-bore velocities. Compression can be 
used in conjunction with other artificial lift methods.
---------------------------------------------------------------------------

    \310\ Ibid.
---------------------------------------------------------------------------

    A plunger lift is used in conjunction with a lower-flowing tubing 
pressure (compression) and intermittent flow (shut-in cycle/smart 
automation) to lift liquids. Plungers have a wide operating range, but 
require a minimum gas-liquid ratio, so they are not appropriate for all 
applications. Plungers are most successful in low volume gas wells 
(e.g., 30 bbl of liquid or less per day). The capital, installation and 
startup cost of a plunger lift is estimated at $1,900-$7,800,\311\ but 
it can reach as high as $20,000.\312\ Adding a smart automation system 
is estimated to cost $4,700-$18,000.\313\
---------------------------------------------------------------------------

    \311\ EPA (2014). Oil and Natural Gas Sector Liquids Unloading 
Process; Report for Oil and Natural Gas Sector Liquids Unloading 
Process Review Panel. April 2014. Available at http://www3.epa.gov/airquality/oilandgas/pdfs/20140415liquids.pdf, p. 16.
    \312\ ICF International (2014) Economic Analysis of Methane 
Emission Reduction Opportunities in the U.S. Onshore Oil and Natural 
Gas Industries, March (2014), p.p. 3-17.
    \313\ EPA, Natural Gas STAR Program (2011). http://www3.epa.gov/gasstar/documents/ll_options.pdf.
---------------------------------------------------------------------------

    Another alternative is a gas lift, which is used to raise gas 
velocity in the production tubing by injecting gas down the space 
between the tubing and surrounding casing and combining it with gas 
from the reservoir to assist in lifting liquid accumulations. Gas lift 
typically requires additional compression and piping at the surface. 
The additional compression would either be electrical- or natural-gas 
powered, adding to emissions, complexity, reliability, and operating 
costs. Also, gas lift is limited to those reservoir/well combinations 
that are configured in such a way that the gas injected down the well 
will flow up the well-bore and not simply dissipate into the formation.
    Finally, operators may also use artificial lifts (e.g., rod pumps, 
beam lift pumps, pumpjacks, and downhole separator pumps). Downhole 
pumps require an external power source to operate in order to remove 
the liquid buildup from the well tubing. Capital and installation costs 
(including location preparation, well clean out, artificial lift 
equipment, and pumping unit) is estimated at $41,000-$62,000 per 
well.\314\
---------------------------------------------------------------------------

    \314\ Ibid.
---------------------------------------------------------------------------

    Besides these measures to reduce gas losses, operators may also 
minimize the impact of well purging by flaring rather than venting the 
released gas through use of a mobile flare, but it can be difficult to 
separate purged gas from purged liquids.
    Colorado allows an operator to vent during unloading of liquids 
from the wellbore only after the operator has unsuccessfully attempted 
to unload liquids without venting.\315\ To minimize venting associated 
with liquids unloading, Colorado also requires an operator 
representative to remain on site during the unloading event.\316\ The 
EPA's proposed 40 CFR part 60 subpart OOOOa rulemaking requests comment 
on ``nationally applicable technologies and techniques that reduce 
methane and VOC emissions'' during liquids unloading, but the EPA does 
not believe it has sufficient data to propose a standard for unloading 
events.\317\
---------------------------------------------------------------------------

    \315\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9, Sections XVII.
    \316\ Ibid.
    \317\ 80 FR 56593, 56614.
---------------------------------------------------------------------------

(c) Proposals To Reduce Waste From Well Maintenance and Liquids 
Unloading
    Recent technological developments 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 should be deemed avoidable waste subject to royalties. Under 
proposed Sec.  3179.204, except in specified circumstances, the BLM 
would prohibit new wells from unloading liquids by simply purging the 
well. While the BLM believes that the alternative technologies 
discussed above now generally make well-purging unnecessary, some of 
these alternatives are less costly to plan and install at the design 
stage, and they are therefore more appropriate for new than for 
existing wells. In addition, some options, such as installing an 
automated plunger lift, may make less sense at a well that is already 
nearing the end of its productive life. Thus, the BLM is proposing to 
limit the prohibition on well purging to new wells drilled after the 
effective date of this rule. We request comment on whether we should 
also prohibit well purging at existing wells.
    In addition, under proposed Sec.  3179.204(c), the BLM would 
require specified best management practices to minimize venting from 
liquids unloading at both new and existing wells. Specifically, the BLM 
proposes to require that the operator be on-site during well purging 
events for monitoring and reporting, unless the operator uses an 
automatic control system. Note that automatic control systems may vent 
more or less depending on the setting. We request comment on whether 
BLM should also require that wells with automatic control systems 
optimize the automatic settings so as to minimize venting.
    Also, the BLM proposes under Sec. Sec.  3179.204(d) and (e) to 
require that operators maintain certain records to document liquids 
unloading events.

[[Page 6656]]

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 are seeking comments on the 
appropriate level and extent of required recordkeeping in the proposed 
rule, as well as other aspects of this approach to reducing waste from 
well maintenance and liquids unloading.
    We estimate that there are currently about 8,500 operating gas 
wells where gas is vented during liquids unloading. Of those wells, we 
estimate that about 6,950 wells (or 82 percent) are equipped with 
plunger lifts, while 1,550 wells (or 18 percent) are not.\318\ The 
proposed requirements would impact the 1,550 wells that are not 
equipped with plunger lifts, as well as any of the wells equipped with 
plunger lifts that lack automation (a number the BLM cannot accurately 
estimate at this time). In addition to the 8,500 wells currently 
venting during liquids unloading, there is the potential that a number 
of additional, producing gas wells will develop liquids accumulation 
issues in the future. Depending on how the operator removes the liquids 
from the wellbore, those wells could potentially be impacted by the 
requirements.
---------------------------------------------------------------------------

    \318\ RIA at 216.
---------------------------------------------------------------------------

    Under the proposed rule, we expect most new wells would use plunger 
lifts for liquids unloading, except where those lifts are technically 
infeasible or unduly costly. Plunger lifts are already used 
widely,\319\ suggesting that under many circumstances their benefits--
in terms of increased gas recovery, slowed declines in production, and 
improved well productivity--exceed their costs.
---------------------------------------------------------------------------

    \319\ According to the 2015 GHG Inventory, 13 percent of the gas 
wells nationwide vent to the atmosphere during liquids unloading, 
and of those, more than 60 percent lack plunger lifts. RIA at 216. 
In the Rocky Mountain region, however, where over 90 percent of the 
gas wells on Federal and Indian lands are located, plunger lifts are 
far more common than elsewhere in the country. RIA at 217.
---------------------------------------------------------------------------

    The proposed rule would require monitoring and reporting if the 
operator does not use an automated system, to minimize the venting and 
loss of gas during liquids unloading to the minimum amount necessary to 
bring the well back into production. The operator may choose to install 
an automated system and avoid the monitoring and reporting requirements 
altogether. Both approaches are likely to reduce venting or loss of 
gas, but we are unable to estimate annual incremental production, 
royalty, or emissions reductions because we cannot accurately predict 
how many operators will choose to install an automated system.
    We do not anticipate that the additional monitoring requirements 
would substantially increase burdens on operators, because the 
available data indicate that average vent times are relatively short. 
In the Rocky Mountain region, for example, one industry survey 
indicates that wells without plunger lifts vent for an average of 1.76 
hours.\320\ The BLM does not expect that requiring operators to remain 
at the well site for such short periods would impose a significant 
financial burden.
---------------------------------------------------------------------------

    \320\ RIA at 217. Source is Shires & Lev-on analysis of API/ANGA 
survey data.
---------------------------------------------------------------------------

    Since the gas wells that encounter liquids accumulation problems 
generally do so after well production starts to decline, the timing of 
any future impacts of this rule is also uncertain. The EPA's Natural 
Gas STAR Program has shown, however, that investing in liquids removal 
processes at the start of a well's decline is more successful than 
making similar investments later in the productive life of the well. 
This suggests that it is reasonable to apply a more stringent 
requirement for new wells drilled after the effective date of this 
rule, as we have proposed, but we specifically request comment on this 
point.
    There are a range of costs for various alternatives to uncontrolled 
liquids unloading. The annualized cost of a plunger lift is estimated 
to be $1,845-$2,816 using a 7 percent discount rate or $1,788-$2,587 
using a 3 percent discount rate. The annualized cost of a ``smart'' (or 
automated) plunger lift is estimated to be $2,471-$4,520 using a 7 
percent discount rate or $2,303-$3,900 using a 3 percent discount rate. 
All estimates are in 2012 dollars and are based on an equipment life of 
10 years.\321\
---------------------------------------------------------------------------

    \321\ RIA at 85.
---------------------------------------------------------------------------

    We note that these cost estimates do not include sales of the 
recovered gas. The EPA Natural Gas STAR program information indicates 
that operators that install plunger lifts may experience increases in 
production from two effects--the capture of gas that would otherwise 
have been vented, and improvements in well performance due to the 
operation of the lifts. The gains are well-specific, but the Natural 
Gas STAR partners found that the additional sales of gas generally 
offset the costs of the lifts.\322\
---------------------------------------------------------------------------

    \322\ EPA Natural Gas STAR, Lessons Learned from Natural Gas 
STAR Partners, available at http://www3.epa.gov/gasstar/documents/ll_plungerlift.pdf.
---------------------------------------------------------------------------

    Overall, based on the experiences of the Natural Gas STAR Program 
partners, we would expect that the boost in well productivity and the 
sale of recovered gas associated with the use of plunger lifts and 
other well-maintenance equipment would pay for the capital costs of 
purchasing and installing the equipment. We request comments on this 
point, both in general, and specifically with respect to the proposed 
prohibition on the use of well purging to unload liquids from new 
wells.
    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 (using a 7 
percent discount rate) or $5-6 million per year (using a 3 percent 
discount rate). We project that the requirements 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.\323\
---------------------------------------------------------------------------

    \323\ 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 (often referred to as ``workover'') 
operations. As explained in the RIA, we estimate that in 2013, up to 
2.08 Bcf of natural gas was lost from these operations on BLM-
administered leases. Of this, we estimate that completion emissions 
from hydraulically fractured oil wells accounted for 1.4 Bcf of the 
loss, while all other completions accounted for about 0.7 Bcf of the 
loss.\324\
---------------------------------------------------------------------------

    \324\ RIA at 205.
---------------------------------------------------------------------------

    As discussed above, the EPA requires new hydraulically fractured 
and refractured gas wells to undergo green completions to capture or 
flare gas that otherwise would be released during drilling and 
completion operations. On September 18, 2015, the EPA proposed to 
extend these requirements to new hydraulically fractured and 
refractured

[[Page 6657]]

oil wells.\325\ If the EPA finalizes that proposal, it appears likely 
that all new hydraulically fractured or refractured oil and gas wells, 
other than wildcat and delineation wells, would be required to capture 
or flare the gas produced from these drilling operations. 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 conventional and 
hydraulically fractured and refractured wells. The BLM has an 
independent statutory obligation to minimize waste of oil and gas 
resources on BLM-administered leases. As proposed, we expect that the 
BLM waste requirements for well drilling, and completions at both 
conventional and hydraulically fractured wells would apply to a broader 
set of wells than the EPA proposal would cover. Finally, if the EPA 
finalizes a rule regulating hydraulically fractured and refractured oil 
wells, the BLM anticipates that any operator subject to both sets of 
requirements (i.e., an operator completing a hydraulically fractured 
oil well) could satisfy both agencies' requirements by either capturing 
or flaring the gas that would otherwise be released. 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 complied with any EPA 
requirements on well completions.
---------------------------------------------------------------------------

    \325\ 80 FR 56593.
---------------------------------------------------------------------------

    Proposed Sec.  3179.101 would generally require operators to 
capture or flare gas generated during drilling operations. 
Alternatively, the operator could inject the gas or use it for 
production purposes. We estimate that the rule would apply to up to 
about 3,000 wells per year, and would contribute to the BLM's overall 
effort to comprehensively address associated gas venting and flaring 
during all phases of oil and gas production. Based on our experience in 
the field, the BLM believes, however, that most operators are already 
diverting and flaring much of the gas from drilling operations as a 
matter of safety and operating practice, under Onshore Oil and Gas 
Order No. 2. As such, we do not estimate significant costs associated 
with this requirement.
    Proposed Sec.  3179.102 would similarly require operators to 
capture or flare gas generated during well completions and well 
fracturing or refracturing operations. Alternatively, the operator may 
inject the gas or use it for production purposes.
    We believe that the compliance costs associated with a requirement 
to flare gas would be minimal, especially for hydraulically fractured 
oil wells, where the equipment needed to flare is commonly already on 
site. We believe that operators generally direct (or may easily direct) 
the gas coming off of the separator to a flare pit. If this is 
infeasible, then the operator would likely bring a combustor to the 
site for the duration of the completion or direct the gases to a 
combustor that it would have on site to fulfill other regulatory 
requirements.
    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.\326\
---------------------------------------------------------------------------

    \326\ 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 million per year (using a 7 percent discount rate) or $2-3 
million per year (using a 3 percent discount rate). 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 $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.\327\
---------------------------------------------------------------------------

    \327\ Ibid.
---------------------------------------------------------------------------

7. Additional Opportunities To Reduce Waste From Venting
    The BLM requests comment on whether there are additional 
opportunities to reduce waste from venting through reasonable and cost-
effective measures. For example, there are several categories of 
sources discussed in the EPA white papers and ICF studies on venting 
that this proposal does not currently address, including gas-assist 
glycol dehydrator pumps, intermittent bleed pneumatic devices, 
compressor stations (with respect to specific interventions that could 
be required), glycol dehydrators, and pipeline venting. The proposal 
does not currently extend to these sources for one of two reasons: 
Either we do not believe that the source commonly occurs on BLM-
administered leases, or we are still reviewing possible approaches to 
reduce venting from the source. We solicit additional information on 
these points, and also request comments on whether any of these sources 
should be addressed (or addressed differently) in the final rule.
    The EPA and various studies have identified operational losses (in 
addition to leaks) from compressors as significant sources of methane 
emissions, and the EPA NSPS rule establishes requirements for new and 
modified centrifugal wet seal compressors and reciprocating 
compressors.\328\ Specifically, that rule requires compressors with wet 
seals to reduce VOC emissions by 95 percent, which can be met through 
flaring or gas capture.\329\ The EPA rule also requires operators of 
reciprocating compressors to replace the rod packing systems every 
26,000 hours of operation or every 36 months, and requires initial 
performance testing and reporting.\330\ The BLM has not proposed to 
adopt similar requirements for operational losses from existing 
compressors on BLM-administered leases, as we believe that these losses 
from compressors are not a significant source of waste on those leases. 
We request comment on whether adopting similar requirements for 
existing compressors would significantly reduce waste of gas from BLM-
administered leases in a reasonable and cost-effective manner.
---------------------------------------------------------------------------

    \328\ 40 CFR 60.5380-5385.
    \329\ 40 CFR 60.5380.
    \330\ 40 CFR 60.5385.
---------------------------------------------------------------------------

    In addition, the BLM requests comment on whether the rule should 
require operators to use automatic igniters on their flares and other 
combustion devices, and if so, under what circumstances those should be 
required. The proposed provisions on

[[Page 6658]]

well drilling, Sec.  3179.101, and completions, Sec.  3179.102, include 
requirements for the associated flare device to be equipped with an 
automatic igniter, as we believe that these activities involve more 
sporadic gas releases, such that an automatic igniter could be helpful 
in avoiding venting. However, we request comment on whether there are 
other situations under which automatic igniters should be required, and 
if so, what deadline should be imposed for the retrofit. For example, 
the State of Colorado requires that all combustion devices used to 
control emissions of hydrocarbons be equipped with automatic igniters, 
and the State gave operators 2 years (until May 1, 2016) to retrofit 
existing combustion devices.\331\
---------------------------------------------------------------------------

    \331\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9, Sections XII.C.1.e, XVII.B.2.d.
---------------------------------------------------------------------------

    Other approaches to address venting from flare malfunctions include 
requiring operators to install malfunction alarms with remote 
notification systems, and/or to use enclosed combustors rather than 
open flares. We request comment on whether the BLM should include these 
requirements as well.
    In addition, the BLM requests comment on whether we should require 
flares to achieve a specified level of performance in eliminating 
venting, and if so, what level. Under the 2012 NSPS rules, EPA requires 
95 percent control of VOCs from vessels and other sources, and 
operators may use flares to meet this standard.\332\ To the extent that 
operators do so, the flares must achieve at least a 95 percent removal 
efficiency for VOCs. Colorado and Wyoming both require combustion 
devices used to control hydrocarbons from vessels and other sources to 
achieve at least a 98 percent ``design destruction efficiency'' or 
``destruction removal efficiency'' for VOCs.\333\
---------------------------------------------------------------------------

    \332\ 40 CFR part 60, subpart OOOO.
    \333\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9, Section XVII.G; Wyoming Operational 
Rules, Drilling Rules Section Ch. 8, Section 6(c)(1)(A).
---------------------------------------------------------------------------

B. Royalty-Free Use of Production

    As noted above in Section III.F of this preamble, the MLA's 
reference to applying royalties to production ``removed or sold from 
the lease'' has long been interpreted to allow for both royalty-free 
``unavoidable'' losses of gas (see discussion above in Section IV.A.1.e 
of this preamble), and royalty-free on-site use of gas production 
(discussed here). For example, operators commonly combust a portion of 
the produced oil or gas to run production equipment, such as to power 
artificial lift equipment and drilling rigs, or to heat, separate, or 
dehydrate production. Operators also use gas pressure to activate 
pneumatic controllers and pneumatic pumps. This royalty exemption for 
on-site use is not unlimited, however, as the requirement to prevent 
waste limits royalty-free on-site use to reasonable uses that are not 
wasteful. Today's proposal would clarify the scope of the royalty 
exemption for on-site use and resolve ambiguities that have arisen 
under NTL-4A.
    Specifically, subpart 3178 of the proposed rule would identify the 
oil and gas uses that would qualify for royalty-free treatment and 
explain related requirements. In addition, proposed Sec.  3178.8 would 
specify how an operator must determine and report royalty-free volumes. 
Among other issues, the proposed rule addresses the following:
     Use of produced oil or gas at locations beyond the 
boundary of the producing lease, unit or communitized area (CA);
     Use of produced oil or gas to power equipment that the 
operator does not own; and
     The practice of ``hot oiling,'' in which oil used in the 
operation is not consumed.
    To prevent unreasonably high royalty-free use, we considered 
proposing a limit, in the form of a maximum volume or maximum 
percentage of production. We concluded, however, that it is too 
difficult to identify specific volume or production percentage 
thresholds that would appropriately distinguish between reasonable and 
unreasonable quantities of on-site use. Instead, the proposed rule 
would directly address the royalty-free treatment of various uses of 
lease production and identify the situations in which prior written BLM 
approval would be required for royalty-free treatment of production 
used.
    The proposed rule states that qualifying royalty-free uses must be 
for operations and production purposes, including placing oil and gas 
into marketable condition. The lessee ordinarily bears the 
responsibility for placing oil and gas into marketable condition at no 
cost to the lessor.\334\ When a particular operation involved in 
placing the oil and gas into marketable condition is performed on the 
producing lease, unit participating area (PA), or CA, and the operator 
has met all other requirements, however, it is an appropriate royalty-
free use. The production used in that operation is not royalty-bearing 
because the production is not removed from the lease, unit, or CA.\335\
---------------------------------------------------------------------------

    \334\ See, e.g., 30 CFR 1206.55 (Indian oil); 1206.106 (Federal 
oil); 1206.152(i) and 1206.153(i) (Federal gas); 
1206.172(e)(3)(iii)(B) and 1206.174(h) (Indian gas); Devon Energy 
Corp. v. Kempthorne, 551 F.3d 1030 (D.C. Cir. 2008); Amoco 
Production Co. v. Watson. 410 F.3d 722 (D.C. Cir. 2005); Amerada 
Hess Corp. v. Dep't. of the Interior, 170 F.3d 1032 (10th Cir. 
1999); Mesa Operating Limited Partnership. v. Dep't. of the 
Interior, 931 F.2d 318 (5th Cir. 1991); Shoshone and Arapaho Tribes 
v. Hodel, 903 F.2d 784 (10th Cir. 1990).
    \335\ See Plains Exploration & Production Co., 178 IBLA 327, 
335-336, 341-343 (2010).
---------------------------------------------------------------------------

C. Royalty Rates on New Competitive Leases

    In addition to clarifying the scope of the royalty exemption for 
on-site use and resolving ambiguities that have arisen under NTL-4A, 
the BLM also proposes to conform its regulatory provisions governing 
royalty rates for new competitive leases to the corresponding rate 
provisions in the MLA. The MLA directs the BLM to set the royalty rate 
for all new competitively-issued leases ``at a rate of not less than 
12.5 percent in amount or value of the production removed or sold from 
the lease.'' \336\ Despite the inherent flexibility of this statutory 
language, the BLM's existing royalty regulation sets a flat rate of 
12.5 percent for all new competitive leases.\337\ The proposed rule 
would adopt the statutory language, with the result that the ``base'' 
royalty rate on competitive oil and gas leases issued after the 
effective date of this rule would be ``not less than'' 12.5 percent.
---------------------------------------------------------------------------

    \336\ 30 U.S.C. 226(b)(1)(A) (emphasis added); see also 30 
U.S.C. 352 (applying the Section 226 royalty provisions to leases on 
acquired land).
    \337\ 43 CFR 3103.3 1(a)(1).
---------------------------------------------------------------------------

    As noted, this proposed change would align the BLM's royalty 
authority with that delegated by Congress. In addition, the change 
would also respond to concerns expressed by the GAO and others about 
the adequacy of the BLM's onshore oil and gas fiscal system. In 2007 
and 2008, the GAO released two reports addressing the United States' 
oil and gas fiscal system. The first report compared oil and gas 
revenues received by the Federal Government to the revenues that 
foreign governments receive from the development of their public oil 
and gas resources.\338\ That report concluded that the United States' 
oil and gas ``take'' is among the lowest in the world.\339\ The second 
report, which focused on whether the Department of the Interior 
receives a fair

[[Page 6659]]

return on the resources it manages, cited the ``lack of price 
flexibility in royalty rates,'' and the ``inability to change fiscal 
terms on existing leases,'' in support of a finding that the United 
States could be foregoing significant revenue from the production of 
onshore Federal oil and gas resources.\340\ Based on that finding, the 
second GAO report recommended that the U.S. Congress direct the 
Secretary of the Interior to convene an independent panel to review the 
Federal oil and gas fiscal system and establish procedures for periodic 
evaluation of the system going forward.
---------------------------------------------------------------------------

    \338\ GAO, Oil and Gas Royalties: A Comparison of the Share of 
Revenue Received from Oil and Gas Production by the Federal 
Government and Other Resource Owners, GAO 07 676R, May 2007.
    \339\ GAO-07-676R at 2.
    \340\ GAO-08-691 at 6.
---------------------------------------------------------------------------

    Congress did not act on the recommendation in the second GAO 
report, but the Department nevertheless undertook its own review. 
Specifically, the BLM and the BOEM contracted with the consulting firm 
Information Handling Services' Cambridge Energy Research Associates 
(IHS CERA) for a comparative assessment of the fiscal systems 
applicable to certain Federal, State, private, and foreign oil and gas 
resources (``IHS CERA Study'').\341\ The IHS CERA Study identified four 
factors amenable to comparison: Government take, internal rate of 
return, profit-investment ratio, and progressivity.\342\ The IHS CERA 
Study also considered measures of revenue risk and fiscal system 
stability. Overall, the IHS CERA Study found that, as of the time of 
the study, the Federal Government's fiscal system and overall take, in 
aggregate, were in the mainstream both nationally and internationally. 
Even within specific geographic regions, however, the IHS CERA Study 
estimated a wide range of government take, and its authors acknowledged 
that take varies with a variety of factors, including commodity prices, 
reserve size, reservoir characteristics, resource location, and water 
depth. As a result, the IHS CERA Study's authors favored a sliding-
scale royalty system, because a sliding-scale royalty is more 
progressive than a fixed-rate royalty, and can also respond to changes 
in commodity market conditions.
---------------------------------------------------------------------------

    \341\ Agalliu, I. (2011). Comparative Assessment of the Federal 
Oil and Gas Fiscal Systems. U.S. Department of the Interior, Bureau 
of Ocean Energy Management, OCS Study, BOEM 2011-xxx, available at 
http://www.energy.senate.gov/public/index.cfm/files/serve?File_id=d174971c-4682-4d96-b194-a85fa2b86774.
    \342\ A ``progressive'' royalty rate refers to a rate that 
increases with the quantity of the resource being sold.
---------------------------------------------------------------------------

    In addition to the IHS CERA Study, the BLM also reviewed a separate 
study conducted by industry, the ``Van Meurs Study.'' \343\ The Van 
Meurs Study looked at a range of jurisdictions and regions across North 
America and provided a comparison of the oil and gas fiscal systems on 
Federal, State, and private lands throughout the United States and the 
provinces in Canada. The Van Meurs Study suggested that as of 2011, 
Federal Government take on Federal lands was generally lower than the 
corresponding take on State or private lands. The Van Meurs Study also 
made several recommendations to State and Federal Governments in the 
United States and Canada, including that governments apply different 
fiscal terms to oil leases than to gas leases, based on the differing 
prices of oil and gas at the time the report was published.
---------------------------------------------------------------------------

    \343\ PFC Energy, Van Meurs Corporation, and Rodgers Oil & Gas 
Consulting (2011). World Rating of Oil and Gas Terms: Volume 1--
Rating of North American Terms for Oil and Gas Wells with a Special 
Report on Shale Plays.
---------------------------------------------------------------------------

    In 2013, the GAO issued another report identifying specific actions 
for the Department to take to ensure that the Federal Government 
receives a fair return on the resources it manages for the American 
public.\344\ The GAO acknowledged that actions had been taken in 
response to its prior recommendations, but remained concerned that the 
Department had not taken steps to change its onshore royalty rate 
regulations to provide flexibility with respect to fiscal terms for oil 
and gas leases.\345\
---------------------------------------------------------------------------

    \344\ GAO, Oil and Gas Resources--Actions Needed for Interior to 
Better Ensure a Fair Return, GAO-14-50, (Dec. 2013), 11.
    \345\ Ibid. At 23.
---------------------------------------------------------------------------

    In April 2015, as an initial response to these various studies and 
reports, the BLM published an Advance Notice of Proposed Rulemaking 
(ANPR) to solicit public comments and suggestions that might be used to 
update the BLM's regulations related to royalty rates, annual rental 
payments, minimum acceptable bids, and other financial measures.\346\ 
In preparing the ANPR, the BLM gathered information about royalty rates 
charged by States and private mineral holders for oil and gas 
activities on State and private lands, and compared those rates to 
rates charged for Federal oil and gas resources. The data showed that 
the royalty rates charged on private and State lands range from 12.5 to 
25 percent, and that the average rate assessed exceeds 16.67 
percent.\347\
---------------------------------------------------------------------------

    \346\ 80 FR 22148 (April 21, 2015).
    \347\ 80 FR at 22151-52 (April 21, 2015).
---------------------------------------------------------------------------

    The comment period on the ANPR closed on June 19, 2015. BLM 
received 82,074 comments, many of which were form letters, including 
thousands of comments from NGOs. In addition to the NGO comments, 
individual companies and industry trade groups, including the American 
Petroleum Institute, Independent Petroleum Association of America, and 
Western Energy Alliance, submitted comments on behalf of their members. 
Most of the comments focused on lease fiscal terms--royalty rates, 
rentals, and minimum bids.
    With respect to royalty rates, comments ran the gamut from 
supporting increases to opposing any such changes. Commenters 
supporting changes to the BLM's royalty rate regulations noted that the 
regulations are decades old and set a rate that is generally lower then 
rates for comparable State and private land leases. These commenters 
expressed concerns about whether, in light of these facts, the BLM is 
obtaining a fair return for the American taxpayer from Federal oil and 
gas leases. A number of these commenters suggested that the BLM should, 
at a minimum, increase the onshore royalty rate to match the rate 
currently set by BOEM offshore (18.75 percent). Other commenters 
suggested that royalty rates should be increased in order to account 
for the social and environmental costs of oil and gas development.
    Many commenters took the opposite view, however, opposing any 
changes in royalty rates and arguing that higher regulatory costs, 
operating costs, and uncertainty on Federal lands justify royalty rates 
lower than those on State and private lands. These commenters also 
asserted that any increase in royalty rates for Federal oil and gas 
leases would lead to an overall decrease in government revenue by 
discouraging exploration and development of Federal oil and gas 
resources.
    Finally, some commenters offered input on alternate royalty rate 
structures, focusing in particular on sliding scale systems. Some 
commenters encouraged the BLM to consider such a system, especially a 
sliding scale based on market price or regional location. Other 
commenters were opposed to a sliding scale approach, due to perceived 
implementation challenges and uncertainty in reporting. These 
commenters also questioned the appropriateness of setting up a royalty 
regime in which the Federal Government shares with investors some of 
the risk of fluctuating gas and oil prices. Overall, most individual 
commenters appeared to agree generally with giving BLM the flexibility 
to change fiscal terms at the lease sale stage, rather than fixing 
royalty rates by rule.

[[Page 6660]]

    Based on the GAO's repeated recommendations, the IHS CERA Study, 
the royalty rate data collected by the BLM, and the comments received 
in response to the ANPR--and in light of the volatile nature of oil and 
gas markets--the BLM has determined that its regulations should provide 
for maximum flexibility to adjust royalty rate terms for new 
competitively issued oil and gas leases. Accordingly, this proposed 
rule would revise the existing regulations to track statutory 
authority.
    The BLM does not currently anticipate increasing the base royalty 
rate for new competitively issued leases above 12.5 percent. Before 
making such a change, the BLM would announce the change prior to the 
effective date, and would provide for a public comment period. Any 
proposed change would be based on relevant factors, potentially 
including an assessment of comparable onshore State and private fiscal 
systems, and an assessment of the proposed impacts of the change on 
Federal revenue, on production from Federal lands, and on demand for 
Federal oil and gas leases relative to State and private leases.
    The BLM requests input on this proposed change to the royalty 
provisions. In particular, commenters should address the merits of the 
proposed change to conform to statutory language, suggest the proper 
factors for the BLM to consider if and when it decides to adjust 
royalty rates for new competitive leases, and evaluate the adequacy of 
the public process outlined above.
    At present this is the only change the BLM proposes to make to its 
royalty regulations. The BLM is, however, considering a provision that 
would allow royalty rates on new competitively issued leases to vary 
after the first year, based on the lease holder's record of routine 
flaring of associated gas from the lease during the previous year. 
Implementation of such a royalty ``adder'' provision would involve a 
``look back'' at each lease holder's venting and flaring activity over 
a 12-month period. On October 1st of each year, a lease holder would 
evaluate its record of routine flaring of associated gas from the lease 
over the prior 12-month period. If a lease holder flared above a de 
minimis threshold for at least 6 months of that 12-month period, then 
its royalty rate for the subsequent calendar year would increase by 
some increment (for example, 4 percent). In all other cases, the 
royalty rate would remain at, or revert to, the base rate specified in 
the lease.
    To make this idea more concrete, suppose the BLM finalizes the 
proposed changes to the existing royalty provisions in 43 CFR 3103.3-
1(a)(1) and (2), detailed below in the section-by-section analysis 
(Discussion of the Proposed Rule, V.I.1.) and laid out in the proposed 
regulation text.\348\ In that case, the additional regulatory language 
implementing a royalty adder could take the following form:
---------------------------------------------------------------------------

    \348\ See footnote 64.
---------------------------------------------------------------------------

    1. Amend Sec.  3103.3-1(a)(2) to add the following subparagraphs:
    (iii) An additional 4 percent above the base rate on all 
competitively-issued leases for any calendar year in which the operator 
reported above-threshold flaring of associated gas during at least six 
of the 12 months preceding October 1st;
    (iv) The threshold flaring rate for purposes of paragraph (iii) is 
300 Mcf/month multiplied by the number of wells on the lease that 
produced for at least 10 days during the month.
    (v) For communitized or unitized leases, the threshold flaring rate 
for purposes of paragraph (iii) is 300 Mcf/month multiplied by the sum 
of the number of stand-alone wells on the lease and the number of wells 
on each agreement from which the lease is receiving an allocation. To 
be counted, each well must have produced for at least 10 days during 
the relevant month. The flaring volume used to assess exceedance of the 
threshold will be determined using the same allocation formula that 
each agreement uses to allocate production to the lease under 
consideration.
    In this illustrative regulatory text, the royalty ``adder'' is 4 
percent, and the threshold, de minimis flaring rate that would trigger 
application of the adder is 300 Mcf/producing well/month (or 
approximately 10 Mcf/producing well/day). Assuming the current base 
rate of 12.5 percent, a lease holder would continue to pay 12.5 percent 
for any year in which routine flaring of associated gas from its lease 
did not exceed the threshold rate during at least six of the 12 months 
preceding October 1st. On the other hand, any lease holder that 
reported above-threshold flaring of associated gas during at least 6 
months of a calendar year would be obligated to pay a 16.5 percent 
royalty rate on all oil and gas production removed or sold from the 
lease during the subsequent calendar year. The rate would then revert 
back to 12.5 percent, for any year in which the lease holder reported 
at- or below-threshold flaring of associated gas during at least 6 of 
the 12 months preceding October 1st. Note that the 16.5 percent rate 
would be less than the average royalty rate that lease holders 
currently pay on oil and gas production removed or sold from onshore 
State and private leases (16.67 percent).\349\ As noted previously, 
this provision, if adopted in the final rule, would apply only to new 
competitively issued leases issued after the effective date of the 
rule, and would not apply to existing leases.
---------------------------------------------------------------------------

    \349\ 80 FR at 22151-52 (April 21, 2015).
---------------------------------------------------------------------------

    The purpose of the royalty adder provision would be: (1) To create 
an incentive for bidders to consider the availability of gas capture 
infrastructure and the proximity of gas processing facilities as 
attributes that add significant value to Federal oil development 
leases; and (2) To create an incentive for Federal lease holders to 
plan for gas capture prior to or in conjunction with the development of 
oil wells.
    The BLM requests comment on both the concept and the implementation 
of the royalty adder. Would a royalty adder accomplish the purposes 
outlined above? If so, is the structure suggested above appropriate? 
Does a 4 percent adder provide adequate incentive to lease holders to 
plan for gas capture at the same time they plan for oil development? Is 
a threshold rate of 10 Mcf/producing well/day (or 300 Mcf/producing 
well/month) over 6 months of the previous calendar year an 
appropriately de minimis rate to trigger the adder? Is an annual ``look 
back'' mechanism that focuses on production over the 12 months prior to 
October 1 workable given how oil and gas production volumes, and 
flaring levels, are currently reported to ONRR, or would a different 
12-month period be easier to implement? Would there be a simpler and/or 
more effective way to implement a royalty adder concept?

D. Record Keeping Requirements

    The BLM is proposing to require operators to keep records 
documenting their compliance with several provisions of this rule. 
Under proposed Sec.  3179.8, for example, operators would need to 
estimate or measure all volumes of gas vented or flared, and report 
those volumes under applicable ONRR reporting requirements. This 
includes flaring of associated gas, and flaring that occurs during well 
drilling (proposed Sec.  3179.101), well completions (proposed Sec.  
3179.102), initial production testing (proposed Sec.  3179.103), and 
subsequent well testing (proposed Sec.  3179.104). With respect to 
venting and flaring during emergencies (proposed Sec.  3179.105), the 
BLM is proposing to require the operator also to estimate and report to 
the BLM on a Sundry Notice the volumes flared or vented beyond

[[Page 6661]]

specified timeframes. We are also soliciting comment on the most 
efficient and least burdensome means to make appropriate data available 
to the public.
    In addition, with respect to venting during well maintenance and 
liquids unloading under proposed Sec.  3179.204, the BLM is proposing 
to require operators to keep records on the cause, date, time, and 
duration of each venting event, as well as estimates of the quantities 
released. The BLM is also proposing to require operators to keep 
records on the dates, equipment covered, monitoring methods used, and 
results of the leak inspections required under proposed Sec.  3179.305, 
as well as the dates that repairs are attempted, completed, and 
confirmed. We request comment on whether operators should be required 
to provide this information in an annual report, consistent with 
Colorado's requirements.\350\
---------------------------------------------------------------------------

    \350\ Colorado Air Quality Control Commission Regulations, 
Regulation 7, 5 CCR 1001-9 at Section XVII.H.1.c. and XVII.F.8 for 
proposed Sec. Sec.  3179.204 and 3179.305 respectively.
---------------------------------------------------------------------------

E. Reporting and Information Availability

    Currently, relatively little information on waste from venting and 
flaring at specific sites is directly provided to the public. The 
public may request information held by the BLM and ONRR through a 
request under the Freedom of Information Act (FOIA), but this can be 
more time-consuming and costly than accessing information publicly 
posted on Web sites.
    Under existing Sec.  3162.3-1(g), upon receiving an Application for 
a Permit to Drill (APD) on Federal lands, the BLM must post information 
for public inspection for at least 30 days before taking action. The 
information includes: (1) The company/operator name; (2) The well name/
number; (3) The well location; and (4) Maps of the affected lands. The 
information must be posted in the local office of the BLM and in the 
appropriate surface managing agency office, if other than the BLM. Some 
BLM field offices also make this information available on their Web 
sites. The BLM has been working to upgrade its systems for accepting 
and processing APDs and Sundry Notices. The new APD acceptance process 
will allow the BLM to more easily post general information about those 
APDs to the Internet for public notice purposes.
    With respect to venting and flaring, in some situations, such as 
emergencies, the operator is not currently required to provide any 
information to the BLM. In other situations, such as when BLM approval 
is required, operators typically file a Sundry Notice requesting the 
approval. When the BLM approves or disapproves the request, the BLM 
notifies the company. Neither the Sundry Notice nor the BLM disposition 
is currently posted, although to the extent that the information is not 
confidential business information, it would be available to the public 
through a FOIA request. Likewise, although operators are currently 
required to report gas vented and flared to ONRR on a lease or 
agreement basis, this information is currently only available to the 
public through a FOIA request. This information also does not include 
quantities of gas released through leaks or during routine operation of 
equipment, such as pneumatic devices.
    In recent years, there has been strong and growing public interest 
in venting and flaring at oil and gas operations. In particular, the 
public has been calling for more complete, reliable, and available 
information on the quantities of natural gas vented and flared from 
BLM-administered leases. The BLM believes it is appropriate for the 
public to have access to information on venting and flaring from BLM-
administered leases. The BLM also wants to be as responsive to 
reasonable public requests as possible given resource constraints.
    Since at least a portion of the data on venting and flaring is 
already reported to and available from ONRR, the BLM believes that the 
least burdensome approach to increasing data access would be to expand 
the information that must be reported to ONRR. The goal would be to 
ensure that all quantities of gas vented and flared that ONRR requires 
to be reported are reported on ONRR's Oil and Gas Operations Report 
(OGOR), form ONRR-4054. Thus, the BLM proposes in Sec. Sec.  3179.8 and 
3179.204 to clarify the reporting requirements to ensure that operators 
report to ONRR measurements or estimates of all volumes of gas vented 
or flared. The BLM requests comment on this proposal and whether 
operators should report any additional information on losses of gas, 
such as from storage vessels or pneumatic controllers and pneumatic 
pumps. Several other categories of information may also generate public 
interest. For example, the proposed rule would require operators to 
provide significant new information related to plans for disposition of 
associated gas at the APD phase. In addition, there is already public 
interest in industry requests for approvals to flare and BLM responses. 
If this proposal is finalized, the BLM expects that there would be far 
fewer applications for alternative flaring limits compared to the 
current level of requests for approval to flare, but that there still 
might be substantial public interest in the applications for 
alternative flaring limits that BLM would receive.
    To ensure transparency about the use of public resources, the BLM 
is considering ways to make these kinds of information publicly 
available online, where appropriate, without requiring interested 
members of the public to submit FOIA requests. The BLM requests comment 
on the types of data that are most useful to the public, the types of 
data that operators believe should remain private, and the most 
efficient and least burdensome approaches to making appropriate data 
available to the public. The BLM recognizes, however, that it must 
balance this interest in open government with the need to protect 
operators' confidential business information, and with the substantial 
administrative burden and costs of posting large amounts of information 
online.

F. Planning Process

    During public outreach for the venting and flaring rule, multiple 
stakeholders asked the BLM to address the waste issue not only through 
requirements under the MLA, but also through the BLM's land-use 
planning and environmental review processes. Pointing to the BLM's 
authorities under FLPMA, procedural statutes such as the National 
Environmental Policy Act (NEPA), and DOI policies such as the 
Secretarial Orders that address climate change,\351\ these commenters 
asked the BLM to use landscape-scale planning tools to complement the 
MLA waste prevention provisions.
---------------------------------------------------------------------------

    \351\ See, e.g., Secretarial Order Nos. 3289 (Sept. 14, 2009) 
(updated by Amendment No. 1, Feb. 22, 2010) and 3226 (Jan. 19, 
2001).
---------------------------------------------------------------------------

    These stakeholders recommended that the BLM integrate the waste 
prevention provisions of the MLA with the planning and management 
framework informed by FLPMA and NEPA. Commenters specifically suggested 
that the BLM develop a new rule requiring field offices to integrate 
waste prevention into planning and management. More broadly, the 
stakeholders asked the BLM to ``craft its rule to make full use of its 
`front end' planning and management tools'' to prevent oil and natural 
gas waste.\352\ They highlighted tools that allow the BLM to plan, 
manage for, and review the impacts of proposed actions before

[[Page 6662]]

issuing leases or approving oil and gas development projects, in 
contrast to the ``back end'' application of specific technologies or 
practices to such projects.\353\ For example, these commenters 
suggested that by providing information to inform oil and gas 
development decisions, BLM inventories of the resource and other values 
of specific lands prepared under FLPMA Section 201(a) \354\ could 
facilitate implementation and enforcement of the venting and flaring 
rule. They further suggested that by providing for public involvement, 
``front end'' tools would facilitate public transparency and 
accountability and help to identify unexpected opportunities to prevent 
methane waste (such as in NEPA alternatives analyses).\355\
---------------------------------------------------------------------------

    \352\ Letter from the Western Environmental Law Center (WELC) et 
al. to Secretary Sally Jewell, DOI, Jan. 27, 2014, p. ii and 
Attached Core Principles, pp. 23-24 (hereinafter WELC Jan. 27 
Letter).
    \353\ Letter from WELC et al. to Secretary Sally Jewell, DOI, 
May 30, 2014, Attached Comments, p. 11, n. 6 (hereinafter WELC May 
30 Letter).
    \354\ 43 U.S.C. 1711(a).
    \355\ WELC Jan. 27 Letter, p. 23.
---------------------------------------------------------------------------

    Among other tools, these stakeholders suggested that resource 
management plans (RMP) offer an opportunity to ensure ``orderly and 
efficient'' oil and gas development by governing the scale, pace, and 
nature of exploration, development, and production, and by facilitating 
the construction of necessary infrastructure for routing captured gas 
to processing and storage facilities.\356\ They also encouraged the BLM 
to use master leasing plans (MLP) ``to establish front-end waste 
prevention goals'' when planning for oil and gas development in a 
defined area and to identify specific best management practices or 
mitigation measures to prevent waste.\357\ These stakeholders argued 
that these and other tools would enable the BLM to ``prevent methane 
waste at a broad basin- or field-level scale.'' \358\
---------------------------------------------------------------------------

    \356\ WELC Jan. 27 Letter, pp. 23-24; see also Letter from WELC 
and Clean Air Task Force to Director Neil Kornze, BLM, Dec. 5, 2014, 
pp. 2 and 4 (hereinafter WELC Dec. 5 Letter).
    \357\ WELC Jan. 27 Letter, p. 24.
    \358\ WELC May 30 Letter, pp. 11-12.
---------------------------------------------------------------------------

    In addition, these stakeholders asked the BLM to use NEPA reviews 
to prevent methane waste. For example, they encouraged the BLM to 
consider methane waste from all sources in its NEPA analyses, including 
when considering alternatives and mitigation measures and when 
analyzing cumulative impacts.\359\ These stakeholders also asked that 
the BLM ``expressly coordinate its planning and management efforts with 
Federal, State, and local agencies that regulate downstream activities, 
as well as with industry segments responsible for downstream 
activities'' to ensure that methane waste prevention actions are 
effective.\360\
---------------------------------------------------------------------------

    \359\ WELC Jan. 27 Letter, pp. 20-21; WELC May 30 Letter, pp. 
21-22; WELC Dec. 5 Letter, p. 4 (urging the BLM to consider and 
require technologies and practices to prevent waste that are deemed 
reasonable in the context of basin- or field-specific conditions).
    \360\ WELC Jan. 27 Letter, p. 20.
---------------------------------------------------------------------------

    Similarly, in evaluating opportunities for the BLM to reduce 
venting and flaring of gas, the GAO found that the agency does not as a 
general matter assess options for reducing venting and flaring in 
advance of oil and gas production. The GAO pointed out that there are 
two phases in advance of production where the BLM could assess venting 
and flaring reduction options--during the environmental review phase 
and when the operator applies to drill a new well. The GAO found, 
however, that the BLM largely fails to take advantage of these 
opportunities to reduce methane waste, instead using its pre-production 
authority solely to ensure that air quality standards are not violated. 
The GAO recommended that the BLM assess the potential use of venting 
and flaring reduction technologies to minimize the waste of natural gas 
in advance of production wherever applicable.\361\
---------------------------------------------------------------------------

    \361\ GAO-11-34, 34.
---------------------------------------------------------------------------

    The BLM is considering the integrated approach suggested by the 
commenters. The BLM agrees that the land use planning and NEPA 
processes are important to sound oil and gas development on Federal 
land. Flaring sometimes results from development of oil wells in 
advance of gas capture infrastructure. In other cases, flaring occurs 
when existing gas capture and processing infrastructure is inadequate, 
or when operators find flaring easier or less costly than connecting to 
existing gas capture infrastructure. Part of the solution to flaring, 
therefore, is to align the timing of well development with that of 
capture and processing infrastructure development, and to create 
incentives for operators to capture rather than flare.
    The land use planning and NEPA review processes could be used to 
achieve these improvements, but the BLM does not intend to make any 
changes to BLM land use planning regulations (43 CFR subparts 1601 and 
1610) or to any BLM planning or NEPA guidance as part of this 
rulemaking. This proposed rule focuses on the requirements that apply 
to operators as they develop wells and produce oil and gas from lands 
under Federal leases (43 CFR chapter II, subparts 3178 and 3179). The 
regulatory changes under consideration in this rulemaking are limited 
to these provisions.

G. Facilities in Rights-of-Way

    In response to the BLM's solicitation of stakeholder views, various 
stakeholders also submitted comments urging the BLM to address not only 
losses of natural gas from BLM-administered leases, but also losses of 
natural gas from facilities located in rights-of-way granted by the BLM 
on Federal and Indian land. As of FY 2014, the BLM had over 33,700 
approved rights-of-way in place under the MLA.\362\ Facilities located 
in rights-of-way include gas gathering and transmission pipelines and 
compressors, which are used to maintain pressure in the pipelines. Of 
these, it appears that compressors are likely to be the largest source 
of natural gas losses. Further, it appears that losses from sources 
located on rights-of-way could be addressed through available 
technologies and practices, such as LDAR programs.
---------------------------------------------------------------------------

    \362\ BLM Public Land Statistics, 2014 Table 3-4, column (c), 
Mineral Leasing Act.
---------------------------------------------------------------------------

    In evaluating the merits of the stakeholders' suggestion, the BLM 
believes that relevant considerations include, among others: The 
quantity of gas lost from these sources, the costs and feasibility of 
technologies to reduce waste of gas from these sources, and the 
administrative burden of doing so.
    Based on the currently available information, the BLM believes that 
there are only a small number of sources of lost gas on BLM-managed 
rights-of-way, and that these sources do not contribute significantly 
to the problem of waste. The BLM analyzed potential losses from 
compressors, as the likely largest sources of loss located on BLM-
managed rights-of-way. There are an estimated 386 compressors located 
on BLM-managed rights-of-way, and most of these are believed to be 
small compressors used for gathering systems (as opposed to the larger 
compressors used for transmission pipelines). Using EPA GHG Inventory 
data on emissions from small compressors, the compressors located in 
BLM-administered rights-of-way are estimated to release approximately 
47 MMcf of natural gas per year. This quantity of gas is several orders 
of magnitude smaller than the on-lease sources of losses on which this 
proposal focuses--not surprising given that the number of compressors 
located on BLM-administered rights-of-way is only about 4 percent of 
the total number of small compressors in the Rocky Mountain region 
(9,260), and emissions from these

[[Page 6663]]

compressors only total about 1 percent of small compressor emissions in 
the U.S. according to the latest GHG Inventory.\363\ Given the limited 
impact of these rights-of-way facilities, and the fact that the BLM can 
already reach the facilities' emissions via conditions on rights-of-
way, we are not proposing to address these facilities in this 
rulemaking. We request comment on this approach.
---------------------------------------------------------------------------

    \363\ BLM analysis of EPA GHG Inventory data applied against the 
estimated number of compressors located on BLM-managed ROW 
authorizations.
---------------------------------------------------------------------------

H. State or Tribal Variances

    Several States and tribes have worked to address concerns about 
venting and flaring from oil and gas production, and others are 
considering action on this front. The BLM believes that it is important 
to include in this rule a provision for recognizing highly effective 
State or tribal requirements that reduce flaring and/or venting as much 
as, or more than, the proposed rule. Under proposed Sec.  3179.401, 
such State or tribal provisions could, upon BLM approval, apply in 
place of a provision or provisions of subpart 3179. To apply for a 
variance, a State or tribe would have to: Identify the specific 
provisions of the BLM requirements for which the variance is requested; 
identify the specific State or tribal regulation that would serve as a 
substitute; explain why the variance is needed; and demonstrate how 
that regulation would serve the purposes of the supplanted BLM 
requirements.
    The relevant BLM State Director would review a State or tribal 
variance request and assess whether the State or tribal regulation 
meets or exceeds the requirements of the BLM provisions for which the 
State or tribe sought a variance. The proposed rule would retain the 
BLM's authority to rescind a variance or modify any condition of 
approval in a variance.

I. Section-by-Section Discussion

1. Sec.  3103.3-1 Royalty on Production
    The proposed revisions to Sec.  3103.3-1(a)(1) and (2) do four 
things: (1) Remove two provisions of the existing regulations that are 
no longer necessary (Sec.  3103.3-1(a)(1)(i) and (ii)); (2) Specify 
that the rate on all leases existing at the time the rule becomes 
effective would remain at the rate ``prescribed in the lease or in 
applicable regulations at the time of lease issuance''; (3) Specify the 
statutory rate of 12.5 percent for all noncompetitive leases issued 
after the effective date of the final rule; and (4) Conform the 
regulatory regime for competitive leases issued after the effective 
date of the rule to the regime envisioned by the MLA, which specifies 
that the royalty rate for all new competitively issued leases be set 
``at a rate of not less than 12.5 percent.'' \364\
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    \364\ See footnote 64.
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2. Sec.  3160.0-5 Definitions
    This proposed amendment to Sec.  3160.0-5 would delete a definition 
of ``avoidably lost'' that by its terms applies to part 3160. A 
definition of ``avoidably lost'' is no longer needed for part 3160, and 
this definition would be superseded by the provisions in proposed 
subparts 3178 and 3179 governing when the loss of oil or gas is 
avoidable. In particular, proposed Sec.  3179.4 delineates when the 
loss of oil or gas is avoidable or unavoidable.
3. Sec.  3162.3-1 Drilling Applications and Plans
    This proposed section describes the requirements for drilling 
applications and plans, including specifying the information that an 
operator must provide with an APD. We propose to amend this section to 
require that when submitting an APD for a development oil well, an 
operator must also submit a waste minimization plan, which would not be 
part of the APD, and the execution of which would not be enforceable. 
The waste minimization plan would have to include information 
regarding: The pipeline infrastructure location and capacity in the 
area of the well or wells; the anticipated timing, quantity, and 
production decline curve of oil and gas production from the well or 
wells; a gas pipeline system location map showing the operator's wells, 
gas pipelines, gas processing plant(s), and proposed routes for 
connection to the pipeline; certification that the operator has 
provided one or more midstream processing companies with information 
about the operator's production plans, including the anticipated 
completion dates and gas production rates of the proposed well or 
wells; the volume and percentage of produced gas the operator is 
currently flaring or venting from wells in the same field and any wells 
within a 20-mile radius of that field; and an evaluation of 
opportunities for alternative on-site capture approaches, if pipeline 
transport is unavailable.
4. Subpart 3178--Royalty-Free Use of Lease Production
(a) Sec.  3178.1 Purpose
    This proposed section states that the purpose of the subpart is to 
address circumstances in which oil and gas produced from Federal and 
Indian leases may be used royalty-free. This subpart would supersede 
those parts of NTL-4A pertaining to oil or gas used for ``beneficial 
purposes.''
(b) Sec.  3178.2 Scope of This Subpart
    This proposed section specifies which leases, agreements, tracts, 
facilities, and gas lines are covered by this subpart. The proposed 
section also states that the term ``lease'' in this subpart includes 
IMDA agreements as consistent with those agreements and with principles 
of Federal Indian law--an edit intended to enhance the clarity and 
brevity of these provisions.
(c) Sec.  3178.3 Production on Which Royalty Is Not Due
    This proposed section would set forth the general rule that royalty 
is not due on oil or gas that is produced from a lease or CA and used 
for operations and production purposes (including placing oil or gas in 
marketable condition) on the same lease or CA without being removed 
from the lease or CA.
    This section also addresses a similar issue with respect to unit 
PAs--that is, the productive areas on a unit. Units often include 
different PAs composed of multiple leases with varied ownership. This 
section would therefore limit the royalty-free use of gas from a 
particular PA to uses that are made on the same unit, to support 
production from the same unit PA. The reason for this limitation is to 
prevent excessive use of royalty-free gas by prohibiting a unit 
operator from using royalty-free production from one PA to power 
operations on, or treat production from, another PA on the same unit, 
to the benefit of different owners and to the detriment of the public 
interest.
    Proposed Sec.  3178.5 would qualify the general provisions of 
proposed Sec.  3178.3 by listing specific operations for which prior 
written BLM approval would be required for royalty-free use.
(d) Sec.  3178.4 Uses of Oil or Gas on a Lease, Unit, or CA That Do Not 
Require Prior Written BLM Approval for Royalty-Free Treatment of 
Volumes Used
    This proposed section identifies uses of produced oil or gas that 
would not require prior written BLM approval for royalty-free 
treatment. The uses listed in this section involve standard and routine 
production and related operations. In addition, proposed paragraph (b) 
clarifies that the authorization to use production without payment of 
royalties is limited to the amount of fuel reasonably necessary to 
perform the operation on the lease using appropriately sized equipment. 
This

[[Page 6664]]

ensures that royalty-free on-site use remains subject to the 
requirement to avoid waste of the resource.
    While the royalty-free uses proposed here are generally similar to 
the uses identified in the definition of ``beneficial purposes'' in 
NTL-4A, this rulemaking would clarify which uses warrant royalty-free 
treatment. This proposed rule would not address some uses that are 
defined as royalty-free under ONRR provisions, such as the royalty-free 
use of residue gas to fuel gas plant operations as provided in 30 CFR 
1202.151(b). In addition, this proposed section would clarify that hot 
oil treatment is an accepted on-lease use of produced crude oil that 
does not require prior approval to be royalty-free. In this treatment, 
oil is not consumed as fuel. Rather, after the oil is pumped back into 
the well to stimulate production, it is produced again. Although the 
use of produced crude oil for hot oil treatments on the producing 
lease, unit, or CA has historically been understood by the BLM and by 
operators as a royalty-free use, it is not specifically addressed in 
NTL-4A.
(e) Sec.  3178.5 Uses of Oil or Gas on a Lease, Unit, or CA That 
Require Prior Written BLM Approval for Royalty-Free Treatment of 
Volumes Used
    This proposed section identifies uses of oil or gas that would 
require prior written BLM approval to be deemed royalty-free. The aim 
of this section is three-fold: (1) To ensure that the BLM retains 
discretion to grant royalty-free use where the BLM deems the use to be 
consistent with the MLA's royalty requirement for oil or gas that is 
produced and then removed from the lease and sold; (2) To increase 
uniformity in the administration of the royalty-provisions by 
specifying circumstances that warrant particular BLM attention; and (3) 
To ensure the BLM's awareness of unusual uses that risk the loss or 
waste of oil and gas.
    For two of the identified uses, existing regulations already 
require BLM approval before the operator may conduct the operation. For 
all of the identified uses, operators would be required to submit a 
Sundry Notice requesting BLM approval to conduct royalty-free 
activities.
    The potentially royalty-free uses identified in this section are as 
follows:
     Using oil as a circulating medium in drilling operations. 
This use is expressly described as royalty-free under NTL-4A. Because 
using produced oil as a circulating medium is rare and creates a 
possibility of loss, the proposal would require that the BLM evaluate 
each request and approve the request in writing only when appropriate.
     Injecting gas produced from a lease, unit PA, or CA into 
the same lease, unit PA, or CA to increase the recovery of oil or gas. 
An operator must also obtain BLM approval for this use under existing 
regulations at 43 CFR 3162.3-2. The substance of this provision would 
not change from NTL-4A.
     Using oil or gas that was removed from the pipeline at a 
location downstream of the approved facility measurement point (FMP), 
provided that both removal and use occur on the lease, unit, or CA. The 
BLM anticipates that these situations would be quite rare because the 
tap that operators use to extract and measure gas is generally upstream 
of the FMP.
     Using produced gas for operations on the lease, unit PA, 
or CA, after it is returned from off-site treatment or processing to 
address a particular physical characteristic of the gas. Physical 
characteristics that might preclude initial use of gas in lease 
operations and necessitate off-lease treatment or processing include an 
unusually high concentration of hydrogen sulfide, or the presence of 
inert gases or liquid fractions that limit the gas's utility as a fuel. 
The operator would bear the burden of establishing the necessity of 
off-lease treatment; the BLM typically would not approve, as a royalty-
free use, return of production to the lease for use in operations 
necessary to put production into marketable condition.
     Any other type of use that is consistent with proposed 
Sec.  3178.3, but is not specifically identified in proposed Sec.  
3178.4. This provision would clarify that the BLM retains discretion to 
consider approving royalty-free use under circumstances that are not 
now anticipated.
(f) Sec.  3178.6 Uses of Oil or Gas Moved Off the Lease, Unit, or CA 
That Do Not Require Prior Written Approval for Royalty-Free Treatment 
of Volumes Used
    This proposed section identifies two circumstances in which 
royalty-free use of oil or gas that has been moved off the lease, unit, 
or CA would be permitted without prior BLM approval.
    The first situation is where an individual lease, unit, or CA 
includes non-contiguous areas, and oil or gas is piped directly from 
one area of the lease, unit, or CA to another area where it is used, 
without oil or gas being added to or removed from the pipeline, even 
though the oil or gas crosses lands that are not part of the lease, 
unit, or CA. Under this proposed section, the BLM would consider such 
production as not having been ``removed from the lease.'' This would 
provide the lessee or operator the same opportunity for royalty-free 
use as if the lease, unit, or CA were one contiguous parcel. The second 
situation is where a well is directionally drilled, and the wellhead is 
not located on the producing lease, unit, or CA, but produced oil or 
gas is used on the same well pad for operations and production purposes 
for that well. In such situations, the proposed rule would allow for 
royalty-free use at the well pad because, as the IBLA noted in Plains 
Exploration & Production Co., ``(t)he gas (is) not produced (extracted 
from the ground) until after it (has) crossed the lease line. 
Production and removal from the lease are both requisite to triggering 
the royalty obligation. . . . Thus, gas used in wellhead production 
operations would be regarded as used for the benefit of the lease.'' 
\365\
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    \365\ Plains Exploration & Production Co., 178 IBLA 327, 341 
n.16 (2010).
---------------------------------------------------------------------------

(g) Sec.  3178.7 Uses of Oil or Gas Moved Off the Lease, Unit, or CA 
That Require Prior Written Approval for Royalty-Free Treatment of 
Volumes Used
    This proposed section would address the royalty treatment of oil or 
gas used in operations conducted off the lease, unit, or CA. When 
production is removed from the lease, unit, or CA, it becomes royalty-
bearing unless otherwise provided. This principle is reflected in 
paragraph (a) of this proposed section, which would provide that with 
only limited exceptions, royalty is owed on all oil or gas used in 
operations conducted off the lease, unit, or CA (referred to here as 
``off-lease royalty-free use'').
    Paragraph (b) of this proposed section identifies circumstances in 
which, despite the principle articulated in paragraph (a), the BLM 
would consider approving off-lease royalty-free use. These include 
situations in which the operation is conducted using equipment or at a 
facility that is located off the lease, unit, or CA (under an approved 
permit or plan of operations, or at the agency's request) because of 
engineering, economic, resource protection, or physical accessibility 
considerations. For example, a compressor that otherwise would have 
been located on a lease may be sited off the lease because the 
topography of the lease is not conducive to equipment siting. To be 
approved for off-lease royalty-free use, the operation would also have 
to be conducted upstream of the approved FMP. This proposed

[[Page 6665]]

paragraph reflects the BLM's policy to encourage operators to reduce 
the amount of surface disturbance associated with oil and gas 
exploration and development projects. In some cases, centralizing 
production facilities at a location off the lease may serve that 
objective.
    Paragraph (c) would require the operator to obtain BLM approval for 
off-lease royalty-free use via a Sundry Notice containing the 
information required under proposed section 3178.9 of this subpart. The 
BLM anticipates that generally such approval would be appropriate only 
in some of the situations in which the BLM also approves measurement at 
a location off the lease, unit, or CA, or when the BLM has granted 
approval to commingle production off the lease, unit, or CA, and to 
allocate production back to the producing properties.
    Paragraph (d) of this proposed section would clarify that approval 
of off-lease measurement or commingling under other regulatory 
provisions does not constitute approval of off-lease royalty-free use. 
An operator or lessee must expressly request, and submit its 
justification for, approval of off-lease royalty-free use.
    Paragraph (e) of this proposed section addresses circumstances in 
which equipment located on a lease, unit, or CA also treats production 
from other properties that are not unitized or communitized with the 
property on which the equipment is located. Unless the BLM approves 
off-lease royalty-free use in such situations, an operator could report 
as royalty-free only that portion of the oil or gas used that is 
properly allocable to the share of production contributed by the lease, 
unit or CA on which the equipment is located.
    NTL-4A does not include a provision that specifically addresses 
approving off-lease royalty-free use. Such approval is required, 
however, under ONRR regulations, which provide, ``All gas (except gas 
unavoidably lost or used on, or for the benefit of, the lease, 
including that gas used off-lease for the benefit of the lease when 
such off-lease use is permitted by the BOEMRE or BLM, as appropriate) 
produced from a Federal lease to which this subpart applies is subject 
to royalty.'' \366\ The proposed section would add clarity and 
consistency in implementation.
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    \366\ 30 CFR 1202.150(b) (emphasis added).
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(h) Sec.  3178.8 Measurement or Estimation of Royalty-Free Volumes
    This proposed section specifies that an operator must measure or 
estimate the volume of royalty-free gas used in operations upstream of 
the FMP. In general, the operator would be free to choose whether to 
measure or estimate, with the exception that the operator must in all 
cases measure under the applicable oil or gas measurement regulations: 
(1) The volume of royalty-free oil used in operations on the lease, 
unit, or CA; and (2) The volume of royalty-free gas removed from the 
product downstream of the FMP and used in operations on the lease, 
unit, or CA. If oil is used on the lease, unit or CA, it is most likely 
to be removed from a storage tank on the lease, unit or CA. Thus, this 
proposed section would also require the operator to document the 
removal of the oil from the tank.\367\
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    \367\ 80 FR 40767 (July 13, 2015).
---------------------------------------------------------------------------

    For both oil and gas, the operator would have to report the volumes 
measured or estimated, as applicable, under ONRR requirements.
(i) Sec.  3178.9 Requesting Approval of Royalty-Free Treatment When 
Approval Is Required
    This proposed section describes how to request BLM approval of 
royalty-free use when prior-approval is required under proposed Sec.  
3178.5 or proposed Sec.  3178.7. NTL-4A is silent with respect to 
application procedures. This proposed section would require the 
operator to submit a Sundry Notice containing specified information, 
which is necessary for the BLM to determine if approval is appropriate. 
The information would include a description of the operation to be 
conducted, the measurement or estimation method, the volume expected to 
be used, the basis for an estimate (if applicable), and the proposed 
disposition of the oil or gas used.
(j) Sec.  3178.10 Facility and Equipment Ownership
    This proposed section clarifies that although the operator would 
not be required to own the equipment in which production is used 
royalty-free, the operator is responsible for all authorizations, 
production measurements, production reporting, and other applicable 
requirements.
5. Subpart 3179--Waste Prevention and Resource Conservation
(a) Sec.  3179.1 Purpose
    This proposed section states that the purpose of subpart 3179 would 
be to implement the statutes relating to prevention of waste from 
Federal and Indian (other than Osage Tribe) leases, conservation of 
surface resources, and management of the public lands for multiple use 
and sustained yield. The proposed section also provides that subpart 
3179 would supersede those parts of NTL-4A that pertain to flaring and 
venting of produced gas, unavoidably and avoidably lost gas, and waste 
prevention.
(b) Sec.  3179.2 Scope of This Subpart
    This proposed section specifies which leases, agreements, tracts, 
facilities, and gas lines are covered by this subpart. The proposed 
section also states that the term ``lease'' in this subpart includes 
IMDA agreements as consistent with those agreements and with principles 
of Federal Indian law--an edit intended to enhance the clarity and 
brevity of these provisions.
(c) Sec.  3179.3 Definitions and Acronyms
    This proposed section contains definitions for 13 terms that are 
used in subpart 3179: ``Accessible component''; ``capture'' and 
``capture infrastructure''; ``component''; ``development oil well'' and 
``development gas well''; ``gas-to-oil ratio''; ``gas well''; ``liquid 
hydrocarbon''; ``liquids unloading''; ``lost oil or lost gas''; 
``storage vessel''; and ``volatile organic compounds.'' Some defined 
terms have a particular meaning in this proposed rule. Other defined 
terms may be familiar to many readers, but we include their definitions 
in the proposed regulatory text to enhance the clarity of the rule.
(d) Sec.  3179.4 Determining When the Loss of Oil or Gas Is Avoidable 
or Unavoidable
    This proposed section describes the circumstances under which lost 
oil or gas would be classified as ``unavoidably lost.'' ``Avoidably 
lost'' oil or gas would then be defined as oil or gas that is not 
unavoidably lost.
    NTL-4A defined the terms ``avoidably lost'' and ``unavoidably 
lost,'' but the definitions are general and could be applied 
inconsistently. The descriptions in the proposed rule are intended to 
enhance clarity and consistency by listing specific operations and 
sources that produce gas that the BLM would deem ``unavoidably lost,'' 
as long as an operator has not been negligent, has not violated laws, 
regulations, lease terms or orders, and has taken prudent and 
reasonable steps to avoid waste.
    The rule would also define as ``unavoidably lost'' any produced gas 
that is vented or flared from a well that is not connected to gas 
capture infrastructure, if the BLM has not determined that the loss of 
gas through such venting or flaring is otherwise avoidable. To be 
deemed ``unavoidably lost,'' this produced gas would have to

[[Page 6666]]

comply with the limits of proposed Sec.  3179.6.
    Finally, this proposed section would define ``avoidably lost'' oil 
or gas as lost oil or gas that does not meet this section's definition 
of ``unavoidably lost.''
(e) Sec.  3179.5 When Lost Production Is Subject to Royalty
    This proposed section would reemphasize the distinction that is the 
foundation of NTL-4A: Royalties are due on all avoidably lost oil or 
gas, but not on unavoidably lost oil or gas. This section further 
provides that if oil becomes waste oil through operator negligence, the 
operator would owe royalties on the waste oil, but absent negligence, 
waste oil would be royalty-free.
(f) Sec.  3179.6 When Flaring or Venting Is Prohibited
    This proposed section would require operators to flare all gas that 
is not captured, except under certain limited circumstances. Operators 
would be allowed to vent gas if flaring is technically infeasible--for 
example if the volumes of gas are too small to operate a flare, or if 
the gas is not readily combustible. Operators would also be allowed to 
vent gas in an emergency, when the loss of gas is uncontrollable or 
venting is necessary for safety. In addition, this proposed section 
would authorize venting of gas from pneumatic devices, and from storage 
vessels, as long as flaring of that gas is not required under other 
provisions of this proposed subpart.
    This proposed section would impose an overall limit of 1,800 Mcf 
per month per well, averaged over all of the producing wells on a 
lease, on all venting or flaring from development oil wells, unless the 
BLM approves an alternative volume limit under proposed Sec.  3179.7. 
This limit would phase in over the first 3 years that the rule is in 
effect, such that the flaring limit in year 1 would be 7,200 Mcf/well/
month, averaged over all of the producing wells on a lease, the limit 
in year 2 would be 3,600 Mcf/well/month on average, and the limit in 
year 3 and thereafter would be 1,800 Mcf/well/month, again on average.
(g) Sec.  3179.7 Alternative Limits on Venting and Flaring
    This proposed section would apply only to leases issued before the 
effective date of this regulation. It would allow the BLM to approve a 
higher limit on venting and flaring for a well, in place of the 
applicable limit specified in proposed Sec.  3179.6, if the operator 
demonstrates, and the BLM agrees, that the limit would impose such 
costs as to cause the operator to cease production on the lease and 
abandon significant recoverable oil reserves. 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. To 
demonstrate the need for an alternative limit, the operator would have 
to submit through a Sundry Notice: (1) Information regarding the 
operator's wells under the lease that produce Federal or Indian gas, 
including identifying information, and levels of gas production, 
venting and flaring for each well; (2) Maps showing the lease area, 
well and pipeline locations, capture, flaring and venting status of 
wells, and distances to pipelines; (3) Information on pipeline capacity 
and the operator's cost projections for gas capture infrastructure and 
alternative methods of transportation that do not require pipelines; 
and (4) The operator's projections of oil and gas prices, oil and gas 
production volumes, costs, revenues and royalty payments from the 
operator's oil and gas operations on the lease over the lesser of 15 
years or the remaining period in which the operator will produce from 
the Federal or Indian lease, unit, or CA. As provided in paragraph (c) 
of this proposed section, the BLM would aim to set the lowest 
alternative flaring limit that would not cause the operator to cease 
production and abandon significant recoverable oil reserves under the 
lease.
    In addition, this proposed section would exempt wells on a lease 
from the applicable flaring limit for a renewable 2-year period if the 
operator certifies that the following conditions apply: (1) The lease, 
unit, or CA is not connected to a gas pipeline; (2) The lease is more 
than 50 straight-line miles from the nearest gas processing plant; and 
(3) The rate gas flaring from the lease is 50 percent or more greater 
than the applicable flaring limit in proposed Sec.  3179.6. An operator 
would have to submit a Sundry Notice to the BLM, certifying in an 
affidavit that it meets the conditions for the exemption.
(h) Sec.  3179.8 Measuring and Reporting Volumes of Gas Vented and 
Flared From Wells
    This proposed section would require operators to estimate (using 
estimation protocols) or measure (using a metering device) all flared 
and vented gas, whether royalty-bearing or royalty-free.\368\
---------------------------------------------------------------------------

    \368\ Estimation in this instance involves the use of known well 
or reservoir information such as periodic well tests or a well's gas 
to oil ratio to estimate a well's gas production rate. For example, 
if a production flow test is conducted monthly on a well, one might 
presume the well continued producing gas at the tested rate for the 
entire month. Similarly, if a well has a gas to oil ratio that is 
uniform over time, the operator could estimate the rate of gas 
production based on the measured rate of oil production and the gas 
to oil ratio. Gas volume estimation using these protocols is 
suitable for reporting flared gas volumes in many cases.
---------------------------------------------------------------------------

    This proposed section further provides that operators must measure 
rather than estimate the flared and vented volumes when the operator is 
flaring 50 Mcf or more of gas per day from a flare stack or manifold, 
based on estimated volumes.
    This proposed section would not specify how to measure gas when 
measurement is required. Onshore Oil and Gas Orders Nos. 4 and 5, which 
are currently undergoing revision, contain standards for measuring 
royalty-bearing oil and gas, respectively.\369\
---------------------------------------------------------------------------

    \369\ For oil: Onshore Oil and Gas Order No. 4, III(C), III(D), 
and III(E); for gas: Onshore Oil and Gas Order No. 5, III(C) and 
III(D). More information can be found at http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/onshore_oil_and_gas.html.
---------------------------------------------------------------------------

    This proposed section would also require operators to report all 
volumes vented or flared under applicable ONRR reporting requirements.
(i) Sec.  3179.9 Determinations Regarding Royalty-Free Venting or 
Flaring
    This proposed section would provide for a transition for operators 
that are operating under existing approvals for royalty-free flaring or 
venting, as of the effective date of the rule. Those operators could 
continue to flare or vent royalty-free, and/or to flare or vent above 
the applicable flaring limit, for 90 days after the effective date of 
the rule. After 90 days, those operators would become subject to all 
the provisions of the final rule, including both the royalty provisions 
and the flaring limit.
    Further, this proposed section would clarify that nothing in this 
subpart alters the royalty-bearing status of flaring that occurred 
prior to [EFFECTIVE DATE OF FINAL RULE], nor the BLM's authority to 
determine that status and collect appropriate back-royalties.
(j) Sec.  3179.10 Other Waste Prevention Measures
    This proposed section would clarify that nothing in this subpart 
alters the BLM's existing authority under the MLA to limit the volume 
of production from a lease, or to delay action on an APD to minimize 
the loss of associated gas.\370\ Specifically, if production from a new 
well would force an existing producing well already connected to the 
pipeline to go offline, then notwithstanding the

[[Page 6667]]

requirements in 3179.6 and 3179.7, the BLM could limit the volume of 
production from the new well for a period of time, while gas pressures 
from the new well stabilize. In addition, the BLM could delay action on 
an APD or approve it with conditions related to gas capture and 
production levels. The BLM could suspend the lease under 43 CFR 3103.4-
4 if the lease associated with the APD is not in producing status.
---------------------------------------------------------------------------

    \370\ 30 U.S.C. 187; 30 U.S.C. 225.
---------------------------------------------------------------------------

(k) Sec.  3179.11 Coordination With State Regulatory Authority
    This proposed section addresses certain ``mixed ownership'' 
situations, in which a single well may produce oil and gas from Federal 
and/or Indian mineral interests, and non-Federal, non-Indian mineral 
interests. This proposed section would provide that to the extent that 
any BLM action to enforce a prohibition, limitation, or order under 
this subpart adversely affects production of oil or gas from non-
Federal and non-Indian mineral interests, the BLM would coordinate on a 
case-by-case basis with the State regulatory authority with 
jurisdiction over that non-Federal and non-Indian production. This is 
consistent with current practice, in which the BLM and State regulators 
coordinate closely in regulating and enforcing requirements that apply 
to operators producing from Federal or Indian and non-Federal non-
Indian mineral interests.
6. Flaring and Venting Gas During Drilling and Production Operations
(a) Sec.  3179.101 Well Drilling
    This proposed section would require gas that reaches the surface as 
a normal part of drilling operations to be used or disposed of in one 
of four specified ways: (1) Captured and sold; (2) Flared at a flare 
pit or stack with an automatic igniter; (3) Used in the lease 
operations; or (4) Injected. Under the proposal, gas may not be vented 
except under the narrow circumstances specified in proposed Sec.  
3179.6(a).
    The proposed section also addresses gas that is lost as a result of 
loss of well control. If there is a loss of well control, the BLM would 
determine whether it was due to operator negligence, and if so, the BLM 
will notify the operator in writing. Gas lost as a result of a loss of 
well control would be classified as unavoidably lost and royalty-free, 
unless the loss of well control was due to operator negligence, in 
which case it would be avoidably lost and subject to royalties.
(b) Sec.  3179.102 Well Completion and Related Operations
    This proposed section would address gas that reaches the surface 
during well completion and post-completion recovery of drilling, 
fracturing, or re-fracturing. It would apply the same requirements and 
exceptions for use, sale, or disposal as proposed for well drilling 
operations under proposed Sec.  3179.101. In lieu of compliance with 
the requirements of this proposed section, an operator may demonstrate 
to the BLM that it is in compliance with the requirements for control 
of gas from well completions established under 40 CFR part 60 subpart 
OOOOa.
    Volumes flared under this proposed section would be reported to 
ONRR as directed in proposed Sec.  3179.106 of this subpart.
(c) Sec.  3179.103 Initial Production Testing
    This proposed section would clarify when gas may be flared, 
royalty-free or otherwise, during a well's initial production test. It 
provides that gas may be flared royalty-free during initial production 
testing for up to 30 days or 20 MMcf of flared gas, whichever occurs 
first. Volumes flared under proposed Sec.  3179.102(a)(2) during well 
completion would count towards the 20 MMcf limit. Under this section, 
royalty-free flaring would end when production begins.
    Paragraph (b) of this proposed section would allow the BLM to 
approve royalty-free flaring during a longer testing period of up to 60 
days, if there are well or equipment problems or a need for additional 
testing to develop adequate reservoir information. Paragraph (c) would 
allow a 90- rather than 30-day period for royalty-free flaring, during 
the variable and time-intensive dewatering and initial evaluation of 
exploratory coalbed methane well. In addition, the BLM could approve up 
to two extensions of 90 days each to allow for more time to dewater a 
coalbed methane well. The operator would have to transmit a request for 
a longer test period under paragraph (b) or (c) of this proposed 
section through a Sundry Notice. Under any of these circumstances, 
notwithstanding an extension of the test period, the well would be 
still subject to the 20 MMcf limit on flared gas.
    Volumes vented or flared under this proposed section would be 
reported to ONRR as directed in proposed Sec.  3179.8 of this subpart.
(d) Sec.  3179.104 Subsequent Well Tests
    The proposed requirement in this section is essentially the same as 
NTL-4A's requirement regarding subsequent well tests. It would limit 
royalty-free flaring during production tests after the initial 
production test to 24 hours, unless the BLM approves or requires a 
longer test period. The operator must transmit its request for a longer 
test period through a Sundry Notice.
    Volumes vented or flared under this proposed section would be 
reported to ONRR as directed in proposed Sec.  3179.8 of this subpart.
(e) Sec.  3179.105 Emergencies
    This proposed section would provide that an operator may flare or 
vent royalty-free during a temporary, short-term, infrequent, and 
unavoidable emergency.
    Paragraph (b) would limit royalty-free emergency flaring or venting 
to a maximum of 24 hours per incident, for a maximum of three incidents 
per lease, unit, or CA per 30-day period. Together, these limits 
restrict monthly flaring or venting to a maximum of 72 hours.
    The proposed rule would further clarify that more than three 
failures of the same equipment within any 365-day period, and failures 
that result from improperly sized, installed, or maintained equipment, 
would not constitute an emergency. Similarly, the proposed rule would 
also exclude from the definition of ``emergency'' any equipment failure 
caused by operator negligence.
    In addition, this proposed section would clarify that scheduled 
maintenance does not constitute an emergency, even when it is outside 
of the operator's control. For example, the fact that a downstream gas 
processing plant goes down for maintenance would not constitute an 
emergency that allows an operator to flare royalty-free.
    Volumes vented or flared under this proposed section would be 
reported to ONRR as directed in proposed Sec.  3179.8 of this subpart.
7. Gas Flared or Vented From Equipment or During Well Maintenance 
Operations
(a) Sec.  3179.201 Equipment Requirements for Pneumatic Controllers
    This proposed section would address gas losses from pneumatic 
controllers. Paragraph (a) identifies the pneumatic controllers that 
would be subject to the requirements of this section: Pneumatic 
controllers that use natural gas produced from a Federal or Indian 
lease, or from a unit or CA that includes a Federal or Indian lease, if 
the controllers have a continuous bleed rate greater than 6 scf/hour 
(``high-bleed'' controllers) and are not covered by EPA

[[Page 6668]]

regulations that prohibit the new use of high-bleed pneumatic 
controllers (40 CFR 60.5360 through 60.5390).
    Paragraph (b) of the proposed section would require pneumatic 
controllers subject to the requirement to be replaced with controllers 
having a bleed rate of no more than 6 scf/hour. Under paragraph (c), 
operators would be required to replace the controllers within 1 year 
from the effective date of the final rule, or within 3 years from the 
effective date of the rule, if the well or facility served by the 
controller has an estimated remaining productive life of 3 years or 
less. Under paragraph (d), operators would also be required to ensure 
that pneumatic controllers are functioning within the manufacturers' 
specifications.
    This proposed section also provides several exceptions to the 
replacement requirement. An operator would not be required to replace a 
controller if a high-bleed controller is necessary to perform the 
needed function. For example, replacement might not be required if a 
low-bleed controller would not provide a timely response, which would 
lead to greater waste or create a safety hazard. Likewise, replacement 
would not be required if the controller is routed to a flare, or if the 
operator demonstrates, and the BLM concurs, that replacing the 
pneumatic controllers on the lease would impose such costs as to cause 
the operator to cease production and abandon significant recoverable 
oil reserves under the lease.
(b) Sec.  3179.202 Requirements for Pneumatic Chemical Injection Pumps 
or Pneumatic Diaphragm Pumps
    This proposed section would establish requirements for operators 
with pneumatic chemical injection pumps or pneumatic diaphragm pumps 
that use natural gas produced from a Federal or Indian lease, or from a 
unit or CA that includes a Federal or Indian lease, except those 
pneumatic pumps covered under EPA regulations at 40 CFR part 60, 
subpart OOOO. The proposed section would require operators to replace 
pneumatic pumps covered by this proposed section with a zero-emissions 
pump or route the pneumatic pump to a flare, no later than 1 year after 
these rules are effective.
    The proposed section also provides for exceptions to the 
replacement requirement. An operator would not be required to replace a 
pneumatic pump if a zero-emissions pump would be insufficient to 
perform the pneumatic pump's function, and an operator would not be 
required to route a pneumatic pump to a flare if no flare device were 
available on site. Replacement or routing to a flare is also not 
required if the operator demonstrates, and the BLM concurs, that the 
cost of replacing the pneumatic pumps on the lease or routing them to a 
flare would impose such costs as to cause the operator to cease 
production and abandon significant recoverable oil reserves under the 
lease.
    In addition, as proposed for pneumatic controllers and based on the 
same rationale, this proposed section would provide that if the 
estimated remaining productive life of the well or facility is 3 years 
or less, the operator would be allowed to replace the pneumatic 
controller no later than 3 years from the effective date of the 
regulation, rather than within 1 year.
    The proposed section would also require that pneumatic pumps 
function within manufacturers' specifications.
(c) Sec.  3179.203 Crude Oil and Condensate Storage Vessels
    This proposed section addresses gas vented from an oil or 
condensate storage vessel (or a battery of storage vessels) that 
contains production from a Federal or Indian lease, or from a unit or 
CA that includes a Federal or Indian lease. The proposed section would 
require operators to route all gas vapor from covered storage vessels 
or batteries to a combustion device or continuous flare, or to a sales 
line. Operators would be required to meet this requirement no later 
than 6 months after the rule becomes effective.
    A storage vessel would be subject to this proposed section if the 
vessel is not covered under EPA regulations at 40 CFR part 60 subpart 
OOOO, and if it has a rate of total VOC emissions equal to or greater 
than 6 tpy. Operators would be required to determine the rate of 
emissions from the storage vessel within 60 days after this rule is 
effective, and within 30 days after adding a new source of production 
to a storage vessel.
    This proposed section would not apply if the total VOC emissions 
rate from the storage vessel declines to 4 tpy in the absence of 
controls for 12 consecutive months, or if the operator demonstrates, 
and the BLM concurs, that the cost of replacing the pneumatic pumps on 
the lease or routing them to a flare would impose such costs as to 
cause the operator to cease production and abandon significant 
recoverable oil reserves under the lease.
(d) Sec.  3179.204 Downhole Well Maintenance and Liquids Unloading
    This proposed section would establish requirements for venting and 
flaring during downhole well maintenance and liquids unloading. It 
would require the operator to use practices for such operations that 
maximize the recovery of gas for sale, and to flare gas that is not 
recoverable, unless the practices or flaring are technically infeasible 
or unduly costly. The proposed rule would also prohibit liquids 
unloading by well purging (as defined in the section) for wells drilled 
after the effective date of this rule, except when the operator is 
returning the well to production following a well workover or following 
a shut-in of more than 30 days.
    For existing wells, before the operator purges a well for the first 
time after the effective date of this section, the BLM is proposing 
that the operator must document that purging is the only technically or 
economically feasible method of unloading liquids from the well. In 
addition, during any liquids unloading by well purging, an operator 
would be required to be present on site to ensure that any venting to 
the atmosphere is limited to what is necessary, unless the operator 
uses an automated control system that limits the venting event to the 
minimum necessary. This proposed section would require the operator to 
maintain records of the date and duration of each venting event and to 
make those records available to the BLM upon request.
    Under this proposal, the operator would be required to notify the 
BLM by Sundry Notice within 10 days after the first liquids unloading 
by well purging after the effective date of the rule. Operators would 
also be required to notify the BLM by Sundry Notice if the cumulative 
duration of well purging events for a well exceeds 24 hours during any 
production month, or if the estimated volume of gas vented in the 
process exceeds 75 Mcf during any production month.
    Paragraph (g) would require operators to report volumes vented 
during downhole maintenance and liquids unloading to ONRR.
8. Leak Detection and Repair
(a) Sec.  3179.301 Operator Responsibility
    This proposed section would apply to all oil or gas wells that 
produce gas from a Federal or Indian lease, or from a unit or CA that 
includes a Federal or Indian lease. The section would obligate 
operators to inspect all equipment, equipment components, facilities 
(such as separators, heater/treaters, and liquids unloading equipment), 
and compressors located on the lease, unit, or CA for leaks. Operators 
would be required to conduct the inspections during production 
operations, and to fix any leaks found.

[[Page 6669]]

    The proposed requirement would not apply to centralized 
compressors, owned by a pipeline company, which the operator of the 
Federal or Indian lease, unit, or CA does not lease or operate, and for 
which the operator has no direct control over maintenance and 
operation. In addition, operators would have the option to demonstrate 
to the BLM in a Sundry Notice that, in lieu of complying with these 
requirements for LDAR for some or all of their equipment and 
facilities, the operator is complying with LDAR requirements 
established by the EPA under 40 CFR part 60 subpart OOOOa for the same 
equipment and facilities. Under the proposed rule, the BLM's LDAR 
requirements would apply to operators that are covered by 40 CFR part 
60, but do not meet that rule's production thresholds, and are 
therefore exempt from performing LDAR under that rule. The BLM seeks 
comment on whether such operators should also be exempt from this 
rule's LDAR requirements.
(b) Sec.  3179.302 Approved Instruments and Methods
    This proposed section would prescribe the types of instruments and 
monitoring methods that an operator must use to inspect for leaks. 
Specifically, operators could use: (1) An optical gas imaging device 
such as an infrared camera; (2) An alternative, equally advanced 
monitoring device, not listed in the proposed rule, which is approved 
by the BLM for use by any operator; or (3) A comprehensive program, 
approved by the BLM, that includes the use of instrument-based 
monitoring devices or continuous emissions monitoring. Large operators 
that have 500 or more wells within the jurisdiction of a single BLM 
field office would have only these three choices for detecting leaks. 
Smaller operators, however, would have a fourth choice: To use a 
portable analyzer device, operated according to manufacturer 
specifications, and assisted by AVO inspection.
(c) Sec.  3179.303 Leak Detection Inspection Requirements for Natural 
Gas Wellhead Equipment, Facilities, and Compressors
    This proposed section would require operators to conduct initial 
site inspections within specified timeframes after the effective date 
of the rule. The proposed section would define ``site'' as a discrete 
area containing wellhead equipment, facilities, and compressors, which 
is suitable for inspection in a single visit.
    The proposed section would require the operator initially to 
conduct site inspections twice a year. The inspection frequency would 
be subject to change based on whether leaks are detected in two 
consecutive inspections, according to the following provisions:
     Case one: If the operator detects no more than two leaks 
at the site inspected, in each of two consecutive semi-annual 
inspections, the operator could shift to conducting less frequent, 
annual inspections.
     Case two: If the operator detects three or more leaks at 
the site inspected, in each of two consecutive semi-annual inspections, 
the operator would have to shift to more frequent, quarterly 
inspections.
    The proposed section also specifies that the inspection frequency 
would revert back to semi-annually if: (1) In case one, the operator 
detects three or more leaks in two subsequent, consecutive annual 
inspections; or (2) In case two, the operator detects no more than two 
leaks in two subsequent, consecutive, quarterly inspections.
    Paragraph (b) of this proposed section would authorize the BLM to 
approve an alternative leak detection device, program, or method, if 
the BLM finds that the alternative would meet or exceed the 
effectiveness of the required approach. The operator would have to 
transmit a request for an alternative leak detection device, program, 
or method through a Sundry Notice.
    Under paragraph (c), an operator would not be required to inspect 
components that are not accessible.
(d) Sec.  3179.304 Repairing Leaks
    This proposed section would require operators to repair leaks 
within 15 calendar days of discovery of the leak, unless there is good 
cause for repair to take longer. The proposed rule would require the 
operator to notify the BLM if this occurs and to complete the repair 
within 15 calendar days after the cause of the delay ceases to exist. 
The rule would also require the operator to conduct a follow-up 
inspection to verify the effectiveness of the repair, using the same 
method used to detect the leak, within 15 calendar days after the 
repair and to make additional repairs within 15 calendar days if the 
previous repair was not effective. The repair and follow-up process 
would have to be followed until the repair is effective. The BLM would 
not consider an inspection to verify the effectiveness of a repair to 
be a periodic inspection under proposed Sec.  3179.303.
(e) Sec.  3179.305 Leak Detection Inspection Recordkeeping
    This proposed section would require operators to maintain records 
of LDAR inspections and repairs, including dates, locations, methods, 
where leaks were found, dates of repairs, and dates of follow-up 
inspections. These records would have to be made available to the BLM 
upon request.
9. State or Tribal Variances
(a) Sec.  3179.401 State or Tribal Requests for Variances From the 
Requirements of This Subpart
    This proposed section would create a variance procedure, under 
which the BLM could grant a State or tribe's request to have a State or 
tribal regulation apply in place of a provision or provisions of this 
subpart. The variance request would have to: (1) Identify the specific 
provisions of the BLM requirements for which the variance is requested; 
(2) Identify the specific State or tribal regulation that would 
substitute for the BLM requirements; (3) Explain why the variance is 
needed; and (4) Demonstrate how the State or tribal regulation would 
satisfy the purposes of the relevant BLM provisions. The BLM State 
Director would review a State or tribal variance request. To approve a 
request, the BLM State Director would have to determine that the State 
or tribal regulation meets or exceeds the requirements of the 
provision(s) for which the State or tribe sought the variance, and that 
the State or tribal regulation is consistent with the terms of the 
affected Federal or Indian leases and applicable statutes.
    Paragraph (b) would specify that the decision on a variance request 
is not subject to administrative appeal under 43 CFR part 4. Paragraph 
(c) would clarify that a variance granted under this proposed section 
would not constitute a variance from provisions of regulations, laws, 
or orders other than proposed subpart 3179. Paragraph (d) would reserve 
the BLM's authority to rescind a variance or modify any condition of 
approval in a variance.

VI. Analysis of Impacts

A. Description of the Regulated Entities

1. Potentially Affected Entities
    Entities that would be directly affected by the proposed rule would 
include most, if not all, entities involved in the exploration and 
development of oil and natural gas on Federal and Indian lands. 
According to AFMSS data (as of March 27, 2015), there are up to 1,828 
entities that currently operate Federal and Indian leases.\371\ We 
believe that these 1,828

[[Page 6670]]

entities would be most affected by the proposed rule, in addition to 
entities currently involved with drilling and support activities, and 
any entities that become involved in the future.
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    \371\ The actual number is expected to be slightly lower due to 
duplicate entries.
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    The potentially affected entities are likely to fall within one of 
the following industries, identified by the North American Industry 
Classification System (NAICS) codes:

 NAICS Code 21111 ``Oil and Gas Extraction''
 NAICS Code 213111 ``Drilling Oil and Gas Wells''
 NAICS Code 213112 ``Support Activities''

    Table 35 of the RIA displays 2011 data from the U.S. Census Bureau, 
which reveal a number of characteristics about the entities that 
operate within these industries.\372\ First, the table identifies the 
total number of entities within each industry and the number of 
entities with less than 500 employees and the number of entities with 
500 or more employees. Next, the table identifies the total employment 
within each industry and the combined employment for entities with less 
than 500 employees and the combined employment for entities with 500 or 
more employees. Third, the table shows the total annual payroll for 
each industry and the combined annual payroll for entities with less 
than 500 employees and the combined annual payroll for entities with 
500 or more employees.
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    \372\ Calendar year 2011 is the most recent data available from 
the U.S. Census Bureau that includes detailed employment data. 
Entities primarily involved in the support of mining activities on a 
contract basis were not included in this count.
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    Based on these data, in 2011, there were 6,628 entities directly 
involved in extraction of oil and gas in the United States, 2,041 
entities involved in the drilling of wells, and 8,119 entities 
providing other support functions. Therefore, the approximately 17,000 
entities associated with developing, and producing of domestic oil and 
gas \373\ represent an upper bound estimate of the operators that could 
potentially be affected by this rulemaking.
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    \373\ U.S. Census Bureau data does not readily differentiate 
between the number of firms involved in oil development and 
production activities versus gas development and production.
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2. Affected Small Entities
    The Small Business Administration (SBA) has developed size 
standards to carry out the purposes of the Small Business Act and those 
size standards can be found in 13 CFR 121.201. For mining, including 
the extraction of crude oil and natural gas, the SBA defines a small 
entity as an individual, limited partnership, or small company, at 
``arm's length'' from the control of any parent companies, with fewer 
than 500 employees. For entities drilling oil and gas wells, the 
threshold is also 500 employees. For entities involved in support 
activities, the standard is annual receipts of less than $38.5 million. 
Of the 6,628 domestic firms involved in oil and gas extraction, 99 
percent (or 6,530) had fewer than 500 employees. There are another 
2,041 firms involved in drilling. Of those firms, 98 percent of those 
firms had fewer than 500 employees.
    To estimate a percentage for firms involved in oil and gas support 
activities we reference Table 36 of the RIA, which provides the NAICS 
information for firms involved in oil and gas support activities based 
on the size of receipts. The most recent data available from the U.S. 
Census Bureau for establishment/firm size based on receipts is for 
2007. Of the 5,880 firms in oil and gas support activities in 2007, 97 
percent had annual receipts of less than $35 million.\374\
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    \374\ U.S. Census Bureau does not provide receipt data that 
allow a break at the $38.5 million threshold as defined by SBA. As 
such, the 97 percent figure is a slight underestimate.
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    Based on this national data, the preponderance of entities involved 
in developing oil and gas resources are small entities as defined by 
the SBA. As such, a substantial number of small entities may 
potentially be affected by the proposed rule.

B. Impacts of the Proposed Requirements

1. Overall Costs of the Rule \375\
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    \375\ RIA at 81-90.
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    We analyzed the overall costs of the rule if the EPA finalizes the 
40 CFR part 60 subpart OOOOa rulemaking, and also if the EPA does not 
finalize that rulemaking. As explained above, we expect more 
significant costs and benefits of the rule for the first few years, 
during which some operators would have to add or improve gas-capture 
capability, and some would also have to replace existing equipment. The 
BLM expects this transitional period to last for the first few years, 
after which the compliance requirements of the rule would be 
significantly reduced, as would any benefits associated with increased 
capture and sale of gas that would otherwise have been vented or 
flared.
    Overall, assuming that the EPA finalizes its concurrent 40 CFR part 
60 subpart OOOOa rulemaking, the BLM estimates that this rule will pose 
costs ranging from $125-161 million per year (using a 7 percent 
discount rate) or $117-1 34 million per year (using a 3 percent 
discount rate) over the next 10 years.\376\ These costs include 
engineering compliance costs and the social cost of minor additions of 
carbon dioxide to the atmosphere.\377\ 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).
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    \376\ RIA at 127.
    \377\ Some gas that would have otherwise been vented would now 
be combusted on-site or presumably downstream to generate 
electricity. The estimated value of the carbon additions do not 
exceed $21,000 in any given year.
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    If, for analytical purposes, we assume that EPA does not finalizes 
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.\378\
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    \378\ RIA at 127.
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    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.
2. Overall Benefits of the Rule \379\
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    \379\ RIA at 85-90.
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    The potential benefits of the rule include the additional 
production of resources from Federal and Indian leases; reductions in 
venting, flaring, and GHG emissions; and increased opportunities for 
royalties.
    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 projected environmental benefits of reducing the amount of 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

[[Page 6671]]

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).\380\ 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 (this benefit is not monetized in our 
calculations).\381\
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    \380\ RIA at 130.
    \381\ RIA at 133-135.
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    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).\382\ We 
estimate that the proposed rule would reduce methane emissions by 
176,000-185,000 tpy, which we estimate to be $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 (this benefit is not monetized in our calculations).\383\
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    \382\ RIA at 130.
    \383\ RIA at 133-135.
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    The proposed rule will 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 NOx and particulate matter, which can cause respiratory 
and heart problems.
3. Net Benefits of the Proposed Rule
    Overall, the BLM estimates that the benefits of this rulemaking 
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.\384\
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    \384\ RIA at 67.
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    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 million to $203 million per year (costs and costs savings 
calculated using a 7 percent discount rate) or $139 million to $245 
million per year (costs and costs savings calculated using a 3 percent 
discount rate).
4. Distributional Impacts
    (a) Energy Systems \385\
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    \385\ RIA at 92-93.
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    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 subpart OOOOa were not 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 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.\386\
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    \386\ RIA at 140.
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    If the EPA finalizes subpart OOOOa, we estimate slightly less 
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), 
and the same amount of additional NGL production and reduced crude oil 
production as presented above. 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.\387\
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    \387\ RIA at 140.
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    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.
(b) Royalties \388\
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    \388\ RIA at 94-95.
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    The rule is expected to increase natural gas production from 
Federal and Indian leases, and likewise, is expected to increase annual 
royalties to the Federal Government, tribal governments, States, and 
private landowners. For requirements that would result in incremental 
gas production, we calculate the additional royalties based on that 
production. When considering the deferment of production that could 
result from the rule's flaring limit, we calculate the incremental 
royalty as the difference in the net present value of the royalty 
received 1 year later (using 7 percent and 3 percent discount rates) 
and the value of the royalty received now.
    If subpart OOOOa is not finalized, we estimate that the rule would 
result in additional royalties of $9-11 million per year (discounted at 
7 percent) or $11-17 million per year (discounted at 3 percent). If the 
EPA finalizes subpart OOOOa, we estimate additional royalties of $9-11 
million per year (discounted at 7 percent) or $10-16 million per year 
(discounted at 3 percent).
    Royalty payments are recurring income to Federal or tribal 
governments and costs to the operator or lessee. As such, they are 
private transfer payments that do not affect the total resources 
available to society. An important but sometimes difficult problem in 
cost estimation is to distinguish between real costs and transfer 
payments. While transfers should not be included in the economic 
analysis of the benefits and costs of a regulation, they may be 
important for describing distributional effects.
    (c) Small Businesses \389\
---------------------------------------------------------------------------

    \389\ The BLM conducted an Initial Regulatory Flexibility 
Analysis, RIA at 154-166.

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[[Page 6672]]

    The BLM identified up to 1,828 entities that currently operate 
Federal and Indian leases. The vast majority of these entities are 
small business, as defined by the SBA. We estimated a range of 
potential per-entity costs, based on different discount rates and 
scenarios. Those per-entity compliance costs are presented in RIA.
    Recognizing that the SBA defines a small business for oil and gas 
producers as one with fewer than 500 employees, a definition that 
encompasses many oil and gas producers, the BLM looked at company data 
for 26 different small-sized entities that currently hold BLM-managed 
oil and gas leases. The BLM ascertained the following information from 
the companies' annual reports to the U.S. Securities and Exchange 
Commission (SEC) for 2012 to 2014.
    From data in the companies' 10-K filings to the SEC, the BLM was 
able to calculate the companies' profit margins \390\ for the years 
2012, 2013 and 2014. We then calculated a profit margin figure for each 
company when subject to the average annual cost increase associated 
with this rule. For simplicity, we used the average per-entity cost 
increase figures of $31,400 and $37,600 which roughly represent the 
middle of the range of potential per-entity costs assuming the EPA 
finalizes and does not finalize subpart OOOOa, respectively. Both 
figures include compliance costs and cost savings, calculated using a 7 
percent discount rate.
---------------------------------------------------------------------------

    \390\ The profit margin was calculated by dividing the net 
income by the total revenue as reported in the companies' 10-K 
filings.
---------------------------------------------------------------------------

    For these 26 small companies, a per-entity compliance cost increase 
of $31,400 would result in an average reduction in profit margin of 
0.087 percentage points (based on the 2014 company data) and a per 
entity cost increase of $37,600 would result in an average reduction in 
profit margin of 0.105 percentage points (also based on the 2014 
company data). The full detail of this calculation is available in the 
RIA.
(d) Employment \391\
---------------------------------------------------------------------------

    \391\ RIA at 148.
---------------------------------------------------------------------------

    Executive Order 13563 states, ``Our regulatory system must protect 
public health, welfare, safety, and our environment while promoting 
economic growth, innovation, competitiveness, and job creation.'' \392\ 
An analysis of employment impacts is a standalone analysis and the 
impacts should not be included in the estimation of benefits and costs.
---------------------------------------------------------------------------

    \392\ Executive Order 13563, Improving Regulation and Regulatory 
Review (Jan. 18, 2011).
---------------------------------------------------------------------------

    The proposed rule is not expected to materially impact the 
employment within the oil and gas extraction, drilling, and support 
industries. As noted previously, the anticipated additional gas 
production volumes represent only a small fraction of the U.S. natural 
gas production volumes. Additionally, the annualized compliance costs 
represent only a small fraction of the annual net incomes of companies 
likely to be impacted. Therefore, we believe that the proposed rule 
would not alter the investment or employment decisions of firms or 
significantly adversely impact employment.
    The proposed requirements would require the one-time installation 
or replacement of equipment and the ongoing implementation of an LDAR 
program, both of which would require labor to comply.
(e) Impacts on Tribal Lands \393\
---------------------------------------------------------------------------

    \393\ RIA at 148-150.
---------------------------------------------------------------------------

    This section presents the costs, benefits, net benefits, and 
incremental production associated with operations on Indian leases, as 
well as royalty implications for tribal governments.
    If, as we expect, the EPA finalizes 40 CFR part 60 subpart OOOOa, 
we estimate that the proposed rule would pose costs ranging from $17-
$23 million per year (using a 7 percent discount rate) or $16-18 
million per year (using a 3 percent discount rate).\394\
---------------------------------------------------------------------------

    \394\ RIA at 148.
---------------------------------------------------------------------------

    Projected benefits from the proposed rule's operation on Indian 
lands range from $31-39 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 $31-43 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).\395\
---------------------------------------------------------------------------

    \395\ Ibid.
---------------------------------------------------------------------------

    Net benefits from operation of the rule on leases on Indian lands 
range from $11-20 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 range from $15-27 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).\396\
---------------------------------------------------------------------------

    \396\ Ibid.
---------------------------------------------------------------------------

    For impacts on production from leases on Indian lands, the rule is 
projected to result in additional natural gas production ranging from 
1.1-1.5 Bcf per year; the productive use of an additional 4.5-6.4 Bcf 
of natural gas, which we estimate would be used to generate 5.6-8.0 
million gallons of NGL per year; and a reduction in crude oil 
production ranging from 0.1-0.5 million bbl per year.\397\ We further 
estimate that the proposed rule would reduce methane emissions from 
leases on Indian lands by 20,000 tpy, and would reduce VOC emissions by 
48,000-51,000 tpy.\398\
---------------------------------------------------------------------------

    \397\ RIA at 150.
    \398\ RIA at 149.
---------------------------------------------------------------------------

    We estimate additional royalties from leases on Indian lands of 
$1.1-1.6 million per year (discounted at 7 percent) or $1.1-1.8 million 
per year (discounted at 3 percent). See previous explanation about how 
the royalty estimates were derived.
    If we assume for analytical purposes that the EPA does not finalize 
40 CFR part 60 subpart OOOOa, we estimate that the proposed rule would 
pose costs ranging from $20-25 million per year (using a 7 percent 
discount rate) or from $18-21 million per year (using a 3 percent 
discount rate).
    Projected benefits from the proposed rule's operation on Indian 
lands range from $35-46 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 $35-50 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).
    Net benefits from operation of the rule on leases on Indian lands 
range from $13-24 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 range from $17-31 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).
    With respect to production from leases on Indian lands, the rule is 
projected to result in additional natural gas production ranging from 
1.6-2.1 Bcf per year; the productive use of an

[[Page 6673]]

additional 4.5-6.4 Bcf of natural gas, which we estimate would be used 
to generate 5.6-8.0 million gallons of NGL per year; and a reduction in 
crude oil production ranging from 0.1-0.5 million bbl per year. We 
further estimate that the proposed rule would reduce methane emissions 
from leases on Indian lands by 22,000-23,000 tpy, and would reduce VOC 
emissions by 50,000-53,000 tpy.
    We estimate additional royalties from leases on Indian lands of 
$1.4-1.9 million per year (discounted at 7 percent) or $1.4-2.1 million 
per year (discounted at 3 percent). See previous explanation about how 
the royalty estimates were derived.

VII. Procedural Matters

A. Executive Order 12866, Regulatory Planning and Review \399\
---------------------------------------------------------------------------

    \399\ RIA at 167.
---------------------------------------------------------------------------

    Executive Order 12866 requires agencies to assess the benefits and 
costs of regulatory actions, and, for significant regulatory actions, 
submit a detailed report of their assessment to the OMB for review. A 
rule is deemed significant under Executive Order 12866 if it may:
    (a) Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities;
    (b) Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
    (c) Materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs or the rights and obligations of recipients 
thereof; or
    (d) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    The Office of Management and Budget has determined that this 
proposed rule is a significant regulatory action because it may have an 
annual effect on the economy of $100 million or more and because it may 
raise novel legal or policy issues arising out of legal mandates and 
the President's priorities. This proposed rule would limit flaring of 
associated gas from oil wells, and it would require operators to take 
actions to reduce gas losses through venting and leaks.

B. Regulatory Flexibility Act and Small Business Regulatory Enforcement 
Fairness Act of 1996 \400\
---------------------------------------------------------------------------

    \400\ RIA at 167-168.
---------------------------------------------------------------------------

    The Regulatory Flexibility Act as amended by the Small Business 
Regulatory Enforcement Fairness Act (SBREFA) generally requires an 
agency to prepare a regulatory flexibility analysis of any rule subject 
to notice and comment rulemaking requirements under the Administrative 
Procedure Act, unless the head of the agency certifies that the rule 
would not have a significant economic impact on a substantial number of 
small entities.\401\ Congress enacted the RFA to ensure that government 
regulations do not unnecessarily or disproportionately burden small 
entities. Small entities include small businesses, small governmental 
jurisdictions, and small not-for-profit enterprises.
---------------------------------------------------------------------------

    \401\ 5 U.S.C. 601-612. The exception is found in 5 U.S.C. 
605(b).
---------------------------------------------------------------------------

    The BLM reviewed the Small Business Administration (SBA) size 
standards for small businesses and the number of entities fitting those 
size standards as reported by the U.S. Census Bureau in the Economic 
Census. The BLM concludes that the vast majority of entities operating 
in the relevant sectors are small businesses as defined by the SBA. As 
such, the rule would likely affect a substantial number of small 
entities. The BLM believes, however, that the proposed rule would not 
have a significant economic impact on a substantial number of small 
entities. The screening analysis conducted by BLM estimates the average 
reduction in profit margin for small companies will be just a fraction 
of one percentage point, which is not a large enough impact to be 
considered significant.
    Although it is not required, the BLM nevertheless has chosen to 
prepare an initial regulatory flexibility analysis for this proposed 
rule.\402\ There are several factors driving this decision. First, 
although the projected costs are expected to be quite small, as a 
percentage of a typical firm's annual profits, there is significant 
uncertainty associated with these costs. There is a combination of 
factors contributing to the uncertainty associated with the costs of 
this rule. These factors include limited data, a wide range of possible 
variation in commodity prices over time, and a variety of possible 
compliance options, particularly with respect to the flaring 
requirements. In addition, the BLM is taking comment on a wide range of 
alternatives to some of the proposed requirements, and some of these 
alternatives could affect the costs of the rule if the BLM were to 
adopt them in the final rule. This further enhances the uncertainty 
regarding the cost projections for the rule. Second, there is no 
question that if the costs of the rule for affected entities were 
economically significant, the BLM would be required to prepare an IRFA 
for the rule, given that the rule will affect a substantial number of 
small entities.
---------------------------------------------------------------------------

    \402\ See RIA, section 9.
---------------------------------------------------------------------------

    Thus, given the unique circumstances present in this rulemaking, 
the BLM believes it is prudent, and potentially helpful to small 
entities, to prepare an IRFA at this stage in the rulemaking. We do not 
believe this decision should be viewed as a precedent for preparing an 
IRFA in other rulemakings, and we may choose not to prepare a final 
regulatory flexibility analysis for the final rule, if our best 
estimate at that time is that the final rule would not have a 
significant economic effect on a substantial number of small entities.

C. Unfunded Mandates Reform Act of 1995

    Under the Unfunded Mandates Reform Act (UMRA), agencies must 
prepare a written statement about benefits and costs prior to issuing a 
proposed rule that includes any Federal mandate that is likely to 
result in aggregate expenditure by State, local, and tribal 
governments, or by the private sector, of $100 million or more in any 1 
year, and prior to issuing any final rule for which a proposed rule was 
published.
    This proposed rule does not contain a Federal mandate that may 
result in expenditures of $100 million or more by State, local, and 
tribal governments, in the aggregate, or by the private sector in any 1 
year. Thus, the proposed rule is also not subject to the requirements 
of Section 205 of UMRA.
    This proposed rule is also not subject to the requirements of 
Section 203 of UMRA because it contains no regulatory requirements that 
might significantly or uniquely affect small governments. It contains 
no requirements that apply to such governments, nor does it impose 
obligations upon them.

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

    Under Executive Order 12630, the proposed rule would not have 
significant takings implications. A takings implication assessment is 
not required. The proposed rule would establish a limited set of 
standards

[[Page 6674]]

under which gas can be flared or vented, and under which an operator 
can use oil and gas on a lease, unit, or communitized area for 
operations and production purposes, without paying royalty.
    Oil and gas operators on BLM-administered leases are subject to 
lease terms that expressly require that subsequent lease activities be 
conducted in compliance with applicable Federal laws and regulations. 
The proposed rule is consistent with the terms of those Federal leases 
and is authorized by applicable statutes. Thus, the proposed rule is 
not a governmental action capable of interfering with constitutionally 
protected property rights, it would not cause a taking of private 
property, and it does not require further discussion of takings 
implications under this Executive Order.

E. Executive Order 13132, Federalism

    The proposed rule would not have a substantial direct effect on the 
States, the relationship between the national government and the 
States, or the distribution of power and responsibilities among the 
levels of government. It would not apply to States or local governments 
or State or local government entities. Therefore, in accordance with 
Executive Order 13132, the BLM has determined that this proposed rule 
does not have sufficient Federalism implications to warrant preparation 
of a Federalism Assessment.

F. Executive Order 12988, Civil Justice Reform

    This proposed rule would comply with the requirements of Executive 
Order 12988. Specifically, this rulemaking: (a) Meets the criteria of 
section 3(a) requiring that all regulations be reviewed to eliminate 
errors and ambiguity and be written to minimize litigation; and (b) 
Meets the criteria of section 3(b)(2) requiring that all regulations be 
written in clear language and contain clear legal standards.

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

    In accordance with Executive Order 13175, the BLM has evaluated 
this rulemaking and determined that it would not have substantial 
direct effects on federally recognized Indian tribes. Nevertheless, on 
a government-to-government basis we initiated consultation with tribal 
governments that the proposed rule may affect.
    In 2014, the BLM conducted a series of forums to consult with 
tribal governments to inform the development of this proposal. We held 
tribal outreach sessions in Denver, Colorado (March 19, 2014), 
Albuquerque, New Mexico (May 7, 2014), Dickinson, North Dakota (May 9, 
2014), and Washington, DC (May 14, 2014).\403\ At the Denver and 
Washington, DC sessions, the tribal meetings were live-streamed to 
allow for the greatest possible participation by tribes and others. The 
tribal outreach sessions served as initial consultation with Indian 
tribes to comply with Executive Order 13175. We look forward to 
continuing close interaction with tribal regulators as we proceed 
through this rulemaking process.
---------------------------------------------------------------------------

    \403\ More info can be found at: http://www.blm.gov/wo/st/en/prog/energy/public_events_on_oil.html
---------------------------------------------------------------------------

H. Paperwork Reduction Act

1. Overview
    The Paperwork Reduction Act (PRA) \404\ provides that an agency may 
not conduct or sponsor, and a person is not required to respond to, a 
``collection of information,'' unless it displays a currently valid 
control number. Collections of information include any request or 
requirement that persons obtain, maintain, retain, or report 
information to an agency, or disclose information to a third party or 
to the public.\405\
---------------------------------------------------------------------------

    \404\ 44 U.S.C. 3501-3521.
    \405\ 44 U.S.C. 3502(3); 5 CFR 1320.3(c).
---------------------------------------------------------------------------

    This proposed rule contains information collection requirements 
that are subject to review by OMB under the PRA. In accordance with the 
PRA, the BLM is inviting public comment on proposed new information 
collection requirements for which the BLM is requesting a new OMB 
control number.
    As discussed below, some provisions of the proposed rule would 
involve some of the information collection activities that OMB has 
approved under Control Number 1004-0137, Onshore Oil and Gas Operations 
(43 CFR part 3160) (expiration date January 31, 2018).
    The information collection activities in this proposed rule are 
described below along with estimates of the annual burdens. Included in 
the burden estimates are the time for reviewing instructions, searching 
existing data sources, gathering and maintaining the data needed, and 
completing and reviewing each component of the proposed information 
collection requirements.
    The information collection request for this proposed rule has been 
submitted to OMB for review in accordance with the PRA. A copy of the 
request may be obtained from the BLM by electronic mail request to Tim 
Spisak at [email protected] or by telephone request to 202-912-7311. You 
may also review the information collection request online at: http://www.reginfo.gov/public/do/PRAMain.
    The BLM requests comments on the following subjects:
     Whether the collection of information is necessary for the 
proper functioning of the BLM, including whether the information will 
have practical utility;
     The accuracy of the BLM's estimate of the burden of 
collecting the information, including the validity of the methodology 
and assumptions used;
     The quality, utility, and clarity of the information to be 
collected; and
     How to minimize the information collection burden on those 
who are to respond, including the use of appropriate automated, 
electronic, mechanical, or other forms of information technology.
    If you want to comment on the information collection requirements 
of this proposed rule, please send your comments directly to OMB, with 
a copy to the BLM, as directed in the ADDRESSES section of this 
preamble. Please identify your comments with ``OMB Control Number 1004-
XXXX.'' OMB is required to make a decision concerning the collection of 
information contained in this proposed rule between 30 to 60 days after 
publication of this document in the Federal Register. Therefore, a 
comment to OMB is best assured of having its full effect if OMB 
receives it by March 9, 2016.
2. Summary of Proposed Information Collection Requirements
     Title: Waste Prevention, Production Subject to Royalties, 
and Resource Conservation (43 CFR parts 3160 and 3170).
     Forms: Form 3160-5, Sundry Notices and Reports on Wells.
     OMB Control Number: This is a new collection of 
information.
     Description of Respondents: Holders of Federal and Indian 
(except Osage Tribe) oil and gas leases, those who belong to federally 
approved units and CAs, and are parties to IMDA oil and gas agreements.
     Respondents' Obligation: Required to obtain or retain a 
benefit.
     Frequency of Collection: On occasion and monthly.
     Abstract: This proposed rule would update standards to 
reduce wasteful venting, flaring, and leaks of natural gas from onshore 
wells located on Federal and Indian oil and gas leases, units and CAs.
     Estimated Total Annual Burden Hours: 42,350 hours.

[[Page 6675]]

     Estimated Total Non-Hour Cost: None.
3. Proposals Involving APDs and Sundry Notices
(a) Plan to Minimize Waste of Natural Gas (Form 3160-3) (43 CFR 3162.3-
1(j))
    This proposed rule would add a new paragraph (j) to 43 CFR 3162.3-1 
that would require a plan to minimize waste of natural gas when 
submitting an APD for a development oil well. This information would be 
in addition to the APD information that the BLM already collects under 
OMB Control Number 1004-0137. The required elements of the waste 
minimization plan are listed at paragraphs (j)(1) through (j)(7).
(b) Request for Prior Approval for Royalty-Free Uses On-Lease or Off-
Lease (43 CFR 3178.5, 3178.7, and 3178.9)
    Under proposed Sec.  3178.5, submission of a Sundry Notice (Form 
3160-5) would be required to request prior written BLM approval for 
royalty-free treatment of volumes used for the following uses:
     Using oil as a circulating medium in drilling operations;
     Injecting gas that an operator produces from a lease, unit 
participating area (PA), or communitized area (CA) into the same lease, 
unit PA, or CA for the purpose of increasing the recovery of oil or gas 
(including gas that is cycled in a contained gas-lift production 
system), subject to an approval under 43 CFR 3162.3-2 to conduct the 
gas injection;
     Using oil or gas that an operator removes from the 
pipeline at a location downstream of the facility measurement point 
(FMP), if removal and use both occur on the lease, unit, or CA;
     Using gas initially removed from a lease, unit PA, or CA 
for treatment or processing because of particular physical 
characteristics of the gas, where the gas is returned to the lease, 
unit, or CA for lease operations; and
     Any other type of use of produced oil or gas for 
operations and production purposes pursuant to proposed Sec.  3178.3 
that is not identified in proposed Sec.  3178.4.
    Under proposed Sec.  3178.7, submission of a Sundry Notice (Form 
3160-5) would be required to request prior written BLM approval for 
off-lease royalty-free uses in the following circumstances:
     The equipment or facility in which the operation is 
conducted is located off the lease, unit, or CA for engineering, 
economic, resource-protection, or physical-accessibility reasons; and
     The operations are conducted upstream of the FMP.
    Under proposed Sec.  3178.9, the following information would be 
required in a request for prior approval of royalty-free use under 
Sec.  3178.5, or for prior approval of off-lease royalty-free use under 
Sec.  3178.7:
     A complete description of the operation to be conducted, 
including the location of all facilities and equipment involved in the 
operation and the location of the FMP;
     The method of measuring the volume of oil, or measuring or 
estimating the volume of gas, that the operator expects will be used in 
the operation, and the volume expected to be used;
     If the volume expected to be used will be estimated, the 
basis for the estimate (e.g., equipment manufacturer's published 
consumption or usage rates); and
     The proposed disposition of the oil or gas used (e.g., 
whether gas used would be consumed as fuel, vented through use of a 
gas-activated pneumatic controller, returned to the reservoir, or some 
other disposition).
(c) Request for Approval of Alternative Volume Limits (43 CFR 3179.7)
    Proposed Sec.  3179.7 would apply only to leases issued before the 
effective date of the final rule. It would provide that an operator may 
seek BLM approval of venting and flaring in excess of the applicable 
limit under proposed Sec.  3179.6. Using a Sundry Notice, the operator 
would be required to show that the applicable limit would impose such 
costs as to cause the operator to cease production and abandon 
significant recoverable oil reserves under the lease. To support this 
showing, the operator would be required to submit the following 
information:
     Information regarding the operator's wells under the lease 
that produce Federal or Indian gas, including:
    [cir] The name, number, and location of each well, and the number 
of the lease, unit, or CA with which it is associated;
    [cir] The depths and names of producing formations;
    [cir] The gas production level of each of the operator's wells for 
the most recent production month for which information is available; 
and
    [cir] The volumes of gas being vented and flared from each of the 
operator's wells;
     Map(s) showing:
    [cir] The entire lease, unit, or CA and the surrounding lands to a 
distance and on a scale that shows the field in which the well is or 
will be located (if applicable), and all pipelines that could transport 
the gas from the well;
    [cir] All of the operator's producing oil and gas wells, which are 
producing from Federal or Indian leases, (both on Federal or Indian 
leases and on other properties) within the map area;
    [cir] Identification of all of the operator's wells within the 
lease from which gas is flared or vented, and the location and distance 
of the nearest gas pipeline(s) to each such well, with an 
identification of those pipelines that are or could be available for 
connection and use; and
    [cir] Identification of all of the operator's wells within the 
lease from which gas is captured;
     Data that show pipeline capacity and the operator's 
projections of the cost associated with installation and operation of 
gas capture infrastructure and alternative methods of transportation 
that do not require pipelines;
     The operator's projections of gas prices, gas production 
volumes, gas quality (i.e., heating value and H2S content), 
revenues derived from gas production, and royalty payments on gas 
production over the next 15 years or the life of each of the operator's 
leases, units, or CAs, whichever is less; and
     The operator's projections of oil prices, oil production 
volumes, costs, revenues, and royalty payments from the operator's oil 
and gas operations within the lease over the lesser of the next 15 
years or the anticipated remaining period in which the operator will 
produce from the Federal or Indian lease, unit, or CA.
(d) Certification in Support of Exemption From Volume Limits (43 CFR 
3179.7(d))
    Proposed Sec.  3179.7(d) would apply only to leases issued before 
the effective date of the final rule. It would authorize an operator to 
provide a certification in support of a renewable, 2-year exemption 
from volume limits (instead of an alternative limit requested under 
proposed Sec.  3179.7(b)). The certification would consist of a Sundry 
Notice with an affidavit verifying that all of the following terms and 
conditions are met:
     The lease, unit, or CA is not connected to a gas pipeline;
     The closest point on the lease, unit, or CA is located 
more than 50 straight-line miles from the nearest gas processing plant; 
and
     In the most recent production month, the lease, unit or CA 
flared or vented at an average rate that exceeds by at least 50 percent 
the applicable flaring limit specified in Sec.  3179.6.

[[Page 6676]]

(e) Well Completion and Related Operations (43 CFR 3179.102(b))
     Proposed Sec.  3179.102(a) would require gas that reaches 
the surface during well completion and related operations to be:
    [cir] Captured and sold;
    [cir] Directed to a flare pit or flare stack equipped with an 
automatic igniter to combust any flammable gasses, subject to the 
volumetric limitations in proposed Sec.  3179.103(a)(3);
    [cir] Used in operations on the lease, unit, or CA; or
    [cir] Injected.
     Paragraph (b) would authorize an operator to demonstrate 
to the BLM on a Sundry Notice that it is in compliance with 
requirements for control of gas from well completions established under 
40 CFR part 60, in lieu of compliance with the requirements of 
paragraph (a).
(f) Initial Production Testing Request for Extension (43 CFR 3179.103)
     Proposed Sec.  3179.103 would allow gas to be flared 
royalty-free during a well's initial production testing until:
    [cir] The operator determines that it has obtained adequate 
reservoir information for the well;
    [cir] 30 days have passed since the beginning of the production 
test;
    [cir] The operator has flared 20 million MMcf of gas; or
    [cir] Production begins.
    The BLM may extend the period for royalty-free testing, but only if 
the operator requests such an extension by submitting a Sundry Notice.
(g) Subsequent Well Tests Request for Extension (43 CFR 3179.104)
    Proposed Sec.  3179.104 would limit royalty-free flaring during 
production tests after the initial production test to 24 hours, unless 
the BLM approves or requires a longer test period. The operator would 
be allowed to request for longer test period by submitting a Sundry 
Notice.
    Reporting of Emergency Venting and Flaring Beyond Specified 
Timeframes (43 CFR 3179.105)
(h) Reporting of Emergency Venting or Flaring Beyond Specified 
Timeframes (43 CFR 3179.105)
    Proposed Sec.  3179.105 would allow an operator to flare or vent 
gas royalty-free during a temporary, short-term, infrequent, and 
unavoidable emergency for up to 24 hours per incident, and for no more 
than 3 emergencies within any 30-day period. The operator would be 
required to report on a Sundry Notice any volumes of gas flared or 
vented beyond those specified timeframes.
(i) Pneumatic Controller Report (43 CFR 3179.201(b) and (c))
    Proposed Sec.  3179.201 addresses gas losses from pneumatic 
controllers that are not covered by EPA regulations at 40 CFR 60.5360 
through 60.5390. The proposed section would require operators to 
replace pneumatic controllers that have continuous bleed rates that are 
greater than 6 scf/hour with lower-bleed models within 1 year after the 
effective date of the final rule. Paragraph (b) would provide an 
exception to this requirement if the operator submits a Sundry Notice 
to the BLM showing that:
     A pneumatic controller with a bleed rate greater than 6 
scf/hour is required based on functional needs;
     The pneumatic controller exhaust is routed to a flare 
device; or
     The replacement of a pneumatic controller would impose 
such costs as to cause the operator to cease production and abandon 
significant recoverable oil reserves under the lease.
    Paragraph (c) would provide an exception to the replacement 
requirement if the operator submits a Sundry Notice showing that a 
pneumatic controller with a bleed rate greater than 6 scf/hour serves a 
well or facility has an estimated remaining productive life of 3 years 
or less. The operator would also be required to replace the device no 
later than 3 years from the effective date of the rule, absent a 
showing that replacement would impose costs as to cause the operator to 
cease production and abandon significant recoverable oil reserves under 
the lease.
(j) Pneumatic Pump Report (43 CFR 3179.202)
    Proposed Sec.  3179.202 would require operators to replace 
pneumatic pumps not covered under EPA regulations with zero-emissions 
pumps or route the pump exhaust to a flare device within 1 year after 
the effective date of the final rule. Paragraph (c) would provide an 
exception to this requirement if the operator makes a showing on a 
Sundry Notice, and the BLM agrees, that:
     A pneumatic pump is required based on functional needs, 
described in the Sundry Notice, and there is no existing flare device 
on site or routing to such a device is technically infeasible; or
     The installation of a zero-emissions pump would impose 
such costs as to cause the operator to cease production and abandon 
significant recoverable oil reserves under the lease and there is no 
existing flare device on site or routing to such a device is 
technically infeasible.
    Paragraph (d) would provide an exception to the replacement 
requirement if the operator submits a Sundry Notice showing that a 
pneumatic pump serves a well or facility that has an estimated 
remaining productive life of 3 years or less. The operator would also 
be required to replace the device no later than 3 years from the 
effective date of the rule, absent a showing that replacement would 
impose costs as to cause the operator to cease production and abandon 
significant recoverable oil reserves under the lease.
(k) Crude Oil and Condensate Storage Vessels (43 CFR 3179.203(c))
    Proposed Sec.  3179.203 would require operators to route all tank 
vapor gas from storage vessels and batteries to a combustion device or 
continuous flare, or to a sales line, unless the operator submits an 
economic analysis in a Sundry Notice and the BLM agrees with that 
economic analysis. Paragraph (c) would require that the operator 
demonstrate in the Sundry Notice that compliance would impose such 
costs as to cause the operator to cease production and abandon 
significant recoverable oil reserves. Operators would be required to 
submit this information no later than 6 months after the rule becomes 
effective.
(l) Downhole Well Maintenance and Liquids Unloading--Documentation and 
Reporting (43 CFR 3179.204(a) and (d))
    Proposed Sec.  3179.204 would pertain to downhole well maintenance 
and liquids unloading operations. Paragraph (a) would require operators 
to use practices that maximize the recovery of gas for sale and to 
flare gas that is not recovered. It would also require operators to 
document, before purging a well for the first time, a discovery that 
compliance with these requirements would be technically infeasible or 
unduly costly. Paragraph (d) would require that documentation to be 
included as part of a Sundry Notice submitted to the BLM within 10 
calendar days after the first liquids unloading event by well purging 
conducted after the effective date of proposed Sec.  3179.204.
4. Other Proposed Information Collection Activities
(a) Downhole Well Maintenance and Liquids Unloading--Notice of 
Excessive Duration or Volume (43 CFR 3179.204(e)
    Proposed Sec.  3179.204 would pertain to downhole well maintenance 
and liquids unloading operations. Paragraph (e) would require an 
operator to notify the

[[Page 6677]]

BLM in a Sundry Notice within 14 days if the cumulative duration of 
well purging events for a well exceeds 24 hours during any production 
month, or if the estimated gas volume vented in liquids unloading by 
well purging operations for a well exceed 75 Mcf during any production 
month.
(b) Leak Detection Inspection and Repair
    Proposed Sec. Sec.  3179.301 through 3179.305 would include 
information collection activities pertaining to the detection and 
repair of gas leaks during production operations. The following 
activities would require operators to submit a Sundry Notice:
     Proposed Sec.  3179.301(e) would allow an operator to 
satisfy the requirements of proposed Sec. Sec.  3179.301 through 
3179.305 for some or all of the equipment or facilities on a given 
lease by demonstrating to the BLM on a Sundry Notice that the operator 
is complying with EPA requirements established pursuant to 40 CFR part 
60 with respect to such equipment or facilities.
     Proposed Sec.  3179.303(b) would allow an operator to 
submit a Sundry Notice requesting authorization to detect gas leaks 
using an alternative device, program, or method.
     Proposed Sec.  3179.304(a) would require an operator to 
repair any leak not associated with normal equipment operation no later 
than 15 calendar days after discovery. In the event of a delay beyond 
15 calendar days, paragraph (b) of this section would require the 
operator to submit a Sundry Notice showing good cause.
5. Burden Estimates
    The following table details the estimated annual burdens of 
activities that would involve APDs and Sundry Notices, the use of which 
has been authorized under Control Number 1004-0137.

                       Proposals Involving APDs and Sundry Notices Estimated Hour Burdens
----------------------------------------------------------------------------------------------------------------
                                                                                                    Total Hours
                        Type of response                             Number of       Hours per      (column B x
                                                                     responses       response        column C)
A.                                                                            B.              C.              D.
----------------------------------------------------------------------------------------------------------------
Plan to Minimize Waste of Natural Gas, 43 CFR 3162.3-1, Form               2,000               2           4,000
 3160-3.........................................................
Request for Prior Approval for Royalty-Free Uses On-Lease or Off-             50               8             400
 Lease, 43 CFR 3178.5, 3178.7, and 3178.9, Form 3160-5..........
Request for Approval of Alternative Volume Limits, 43 CFR                    185              16           2,960
 3179.7(b), Form 3160-5.........................................
Certification in Support of Exemption from Volume Limits, 43 CFR              15              16             240
 3179.7(d), Form 3160-5.........................................
Well Completion and Related Operations, 43 CFR 3179.102(b), Form               5               2              10
 3160-5.........................................................
Initial Production Testing Request for Extension, 43 CFR                       5               2              10
 3179.103, Form 3160-5..........................................
Subsequent Well Tests Request for Extension, 43 CFR 3179.104,                  5               2              10
 Form 3160-5....................................................
Reporting of Emergency Venting and Flaring Beyond Specified                   25               2              50
 Timeframes, 43 CFR 3179.105, Form 3160-5.......................
Pneumatic Controller Report, 43 CFR 3179.201(b) and (c), Form                200               2             400
 3160-5.........................................................
Pneumatic Pump Report, 43 CFR 3179.202, Form 3160-5.............             250               8           2,000
Crude Oil and Condensate Storage Vessels, 43 CFR 3179.203(c),                100               8             800
 Form 3160-5....................................................
Downhole Well Maintenance and Liquids Unloading--Documentation             5,000               1           5,000
 and Reporting, 43 CFR 3179.204(a) and (d), Form 3160-5.........
Downhole Well Maintenance and Liquids Unloading--Notification of             120               1             120
 Excessive Duration or Volume, 43 CFR 3179.204(e)...............
Form 3160-5.....................................................
Leak Detection--Compliance with EPA Regulations, 43 CFR                      500               8           4,000
 3179.301(e), Form 3160-5.......................................
Leak Detection--Request to Use and Alternative Device, Program,              200              40           8,000
 or Method, 43 CFR 3179.303(b), Form 3160-5.....................
Leak Detection--Notification of Delay in Repairing Leaks, 43 CFR             100               1             100
 3179.304(a), Form 3160-5.......................................
rrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrr
    Totals......................................................           8,760  ..............          28,100
----------------------------------------------------------------------------------------------------------------

    The following table details the annual estimated hour burdens for 
the rest of the proposed information collection activities in this 
rule.

                              Estimated Annual Hour Burdens for Other IC Activities
----------------------------------------------------------------------------------------------------------------
                                                                                                    Total Hours
                        Type of response                             Number of       Hours per      (column B x
                                                                     responses       response        column C)
A.                                                                            B.              C.              D.
----------------------------------------------------------------------------------------------------------------
Downhole Well Maintenance and Liquids Unloading--Recordkeeping,            5,000            0.25           1,250
 43 CFR 3179.204(c).............................................
Leak Detection--Inspection Recordkeeping, 43 CFR 3179.305.......          52,000             .25          13,000
rrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrr
    Totals......................................................          57,000  ..............          14,250
----------------------------------------------------------------------------------------------------------------

I. National Environmental Policy Act

    The BLM has prepared a draft environmental assessment (EA) to 
determine whether issuance of this proposed regulation pertaining to 
oil and gas waste prevention and royalty clarification would constitute 
a ``major Federal action significantly affecting the quality of the 
human environment''

[[Page 6678]]

under section 102(2)(C) of the National Environmental Policy Act 
(NEPA).\406\ The BLM believes that, for the most part, the proposed 
rule would benefit the environment by reducing emissions of methane (a 
potent GHG), VOCs (which contribute to smog), and hazardous air 
pollutants such as benzene (a known carcinogen). In addition, the 
proposed rule would reduce light pollution and other impacts from 
flaring. The rule may also have indirect and minor to negligible 
adverse environmental impacts, primarily due to land disturbance from 
increased or accelerated construction of gas pipelines and compressors 
and/or increased truck traffic on existing disturbed surfaces from the 
increased use of mobile capture technology. In the aggregate, the 
beneficial impacts of the proposed rule are expected to dwarf its 
adverse impacts. Further, the BLM anticipates that any new gathering 
lines would be subject to additional environmental review based on 
submission of a Sundry Notice or a FLPMA Title V right-of-way 
application prior to construction.
---------------------------------------------------------------------------

    \406\ 42 U.S.C. 4332(2)(C).
---------------------------------------------------------------------------

    During the public comment period for the proposed rule, we will 
consider any new information we receive that may inform our analysis of 
the potential environmental impacts of the rule. A copy of the draft EA 
can be viewed at www.regulations.gov (use the search term 1004-AE14, 
open the Docket Folder, and look under Supporting Documents) and at the 
address specified in the ADDRESSES section.

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

    Under Executive Order 13211, agencies are required to prepare and 
submit to OMB a Statement of Energy Effects for significant energy 
actions. This statement is to include a detailed statement of ``any 
adverse effects on energy supply, distribution, or use (including a 
shortfall in supply, price increases, and increase use of foreign 
supplies)'' for the action and reasonable alternatives and their 
effects.
    Section 4(b) of Executive Order 13211 defines a ``significant 
energy action'' as ``any action by an agency (normally published in the 
Federal Register) that promulgates or is expected to lead to the 
promulgation of a final rule or regulation, including notices of 
inquiry, advance notices of proposed rulemaking, and notices of 
proposed rulemaking: (1)(i) that is a significant regulatory action 
under Executive Order 12866 or any successor order, and (ii) is likely 
to have a significant adverse effect on the supply, distribution, or 
use of energy; or (2) that is designated by the Administrator of (OIRA) 
as a significant energy action.''
    Since the compliance costs for this rule would represent such a 
small fraction of company net incomes, we believe that the rule is 
unlikely to impact the investment decisions of firms. Also, any 
incremental production of gas estimated to result from the rule's 
enactment would constitute a small fraction of total U.S. production, 
and any potential and temporary deferred production of oil would 
likewise constitute a small fraction of total U.S. production. For 
these reasons, we do not expect that the proposed rule would 
significantly impact the supply, distribution, or use of energy. As 
such, the rulemaking is not a ``significant energy action'' as defined 
in Executive Order 13211.

K. Clarity of the Regulations

    Executive Order 12866 requires each agency to write regulations 
that are simple and easy to understand. We invite your comments on how 
to make these proposed regulations easier to understand, including 
answers to questions such as the following:
     Are the requirements in the proposed regulations clearly 
stated?
     Do the proposed regulations contain technical language or 
jargon that interferes with their clarity?
     Does the format of the proposed regulations (grouping and 
order of sections, use of headings, paragraphing, etc.) aid or reduce 
their clarity?
     Would the regulations be easier to understand if they were 
divided into more (but shorter) sections?
     Is the description of the proposed regulations in the 
SUPPLEMENTARY INFORMATION section of this preamble helpful in 
understanding the proposed regulations? How could this description be 
more helpful in making the proposed regulations easier to understand?
    Please send any comments you have on the clarity of the regulations 
to the address specified in the ADDRESSES section.

L. Executive Order 13563, Improving Regulation and Regulatory Review

    Executive Order 13563 reaffirms the principles of E.O. 12866 while 
calling for improvements in the nation's regulatory system to promote 
predictability, to reduce uncertainty, and to use the best, most 
innovative, and least burdensome tools for achieving regulatory ends. 
The executive order directs agencies to consider regulatory approaches 
that reduce burdens and maintain flexibility and freedom of choice for 
the public where these approaches are relevant, feasible, and 
consistent with regulatory objectives. E.O. 13563 emphasizes further 
that regulations must be based on the best available science and that 
the rulemaking process must allow for public participation and an open 
exchange of ideas. We have developed this proposed rule in a manner 
consistent with these requirements.

VIII. Authors

    The principal authors of this rule are: Timothy Spisak and James 
Tichenor of the BLM Washington Office; Eric Jones of the BLM Moab, Utah 
Field Office; and David Mankiewicz of the BLM Farmington, New Mexico 
Field Office; assisted by Faith Bremner of the staff of the BLM's 
Regulatory Affairs Division.

List of Subjects

43 CFR Part 3100

    Government contracts, Mineral royalties, Oil and gas reserves, 
Public lands-mineral resources, Reporting and recordkeeping 
requirements, Surety bonds.

43 CFR Part 3160

    Administrative practice and procedure, Government contracts, 
Indians-lands, Mineral royalties, Oil and gas exploration, Penalties, 
Public lands--mineral resources, Reporting and recordkeeping 
requirements.

43 CFR Part 3170

    Administrative practice and procedure, Flaring, Government 
contracts, Incorporation by reference, Indians-lands, Mineral 
royalties, Immediate assessments, Oil and gas exploration, Oil and gas 
measurement, Public lands--mineral resources, Reporting and 
recordkeeping requirements, Royalty-free use, Venting.

    Dated: January 21, 2016.
Janice M. Schneider,
Assistant Secretary, Land and Minerals Management.

    For the reasons set out in the preamble, the Bureau of Land 
Management proposes to amend 43 CFR parts 3100 and 3160 and add new 
subparts 3178 and 3179 to new 43 CFR part 3170 as follows:

PART 3100--ONSHORE OIL AND GAS LEASING

0
1. Revise the authority citation for part 3100 to read as follows:

    Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359 and 
1751; 43 U.S.C.

[[Page 6679]]

1732(b), 1733, and 1740; and the Energy Policy Act of 2005 (Pub. L. 
109-58).

0
2. Revise Sec.  3103.3-1 to read as follows:


Sec.  3103.3-1  Royalty on production.

    (a) Royalty on production will be payable only on the mineral 
interest owned by the United States. Royalty must be paid in amount or 
value of the production removed or sold as follows:
    (1) For leases issued on or before [EFFECTIVE DATE OF THE FINAL 
RULE], the rate prescribed in the lease or in applicable regulations at 
the time of lease issuance;
    (2) For leases issued after [EFFECTIVE DATE OF THE FINAL RULE]:
    (i) 12\1/2\ percent on all noncompetitive leases; and
    (ii) A base rate of not less than 12\1/2\ percent on all 
competitive leases, exchange and renewal leases, and leases issued in 
lieu of unpatented oil placer mining claims under Sec.  3108.2-4;
    (3) 16 \2/3\ percent on noncompetitive leases reinstated under 
Sec.  3108.2-3 plus an additional 2 percentage-point increase added for 
each succeeding reinstatement; and
    (4) The rate used for royalty determination that appears in a lease 
that is reinstated or that is in force for competitive leases at the 
time of issuance of the lease that is reinstated, plus 4 percentage 
points, plus an additional 2 percentage points for each succeeding 
reinstatement.
    (b) Leases that qualify under specific provisions of the Act of 
August 8, 1946 (30 U.S.C. 226(c) may apply for a limitation of a 12\1/
2\ percent royalty rate.
    (c) The average production per well per day for oil and gas will be 
determined pursuant to 43 CFR 3162.7-4.
    (d) Payment of a royalty on the helium component of gas will not 
convey the right to extract the helium. Applications for the right to 
extract helium shall be made under 43 CFR part 16.

PART 3160--ONSHORE OIL AND GAS OPERATIONS

0
3. The authority citation for part 3160 continues to read as follows:

    Authority:  25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, 
and 1751; and 43 U.S.C. 1732(b), 1733, and 1740.


Sec.  3160.0-5  [Amended]

0
4. Amend Sec.  3160.0-5 by removing the definition of ``Avoidably 
lost.''
0
5. Amend Sec.  3162.3-1 by adding paragraph (j) to read as follows:


Sec.  3162.3-1  Drilling applications and plans.

* * * * *
    (j) When submitting an Application for Permit to Drill an oil well, 
the operator must also submit a plan to minimize waste of natural gas 
from that well. The waste minimization plan must accompany, but would 
not be part of, the Application for Permit to Drill. The waste 
minimization plan must set forth a strategy for how the operator will 
comply with the requirements of 43 CFR subpart 3179 regarding control 
of waste from venting, flaring and leaks, and must explain how the 
operator plans to capture associated gas upon the start of oil 
production, or as soon thereafter as reasonably possible. Failure to 
submit a complete and adequate waste minimization plan is grounds for 
denying or disapproving an Application for Permit to Drill. The waste 
minimization plan must include the following information:
    (1) The anticipated completion date of the proposed well(s);
    (2) The anticipated gas production rates of the proposed well(s);
    (3) A gas pipeline system location map of sufficient detail, size, 
and scale as to show the field in which the proposed well will be 
located, and all existing gas pipelines within 20 miles of the well. 
The map should also contain:
    (i) The name and location of the gas processing plant(s) closest to 
the proposed well(s), and of the intended destination processing plant, 
if different;
    (ii) The location and name of the operator of each gas pipeline 
within 20 miles of the proposed well;
    (iii) The proposed route and tie-in point that connects or could 
connect the subject well to an existing gas pipeline;
    (4) Information on the gas pipeline to which the operator plans to 
connect, including:
    (i) Maximum current daily capacity of the pipeline;
    (ii) Current throughput of the pipeline;
    (iii) Anticipated daily capacity of the pipeline at the anticipated 
date of first gas sales from the proposed well;
    (iv) Anticipated throughput of the pipeline at the anticipated date 
of first gas sales from the proposed well;
    (v) Certification that the operator has provided one or more 
midstream processing companies with information about the operator's 
production plans, including the anticipated completion dates and gas 
production rates of the proposed well or wells; and
    (vi) Any plans known to the operator for expansion of pipeline 
capacity for the area that includes the proposed well.
    (5) A description of anticipated production, including:
    (i) The anticipated date of first production;
    (ii) The expected oil and gas production rates and duration from 
the proposed well. If the proposed well is on a multi-well pad, the 
plan should include the total expected production for all wells being 
completed;
    (iii) The expected production decline curve of both oil and gas 
from the proposed well; and
    (iv) The expected Btu value for gas production from the proposed 
well.
    (6) The volume and percentage of produced gas the operator is 
currently flaring or venting from wells in the same field and any wells 
within a 20-mile radius of that field; and
    (7) An evaluation of opportunities for alternative on-site capture 
approaches, if pipeline transport is unavailable.

PART 3170--ONSHORE OIL AND GAS PRODUCTION

0
6. The authority citation for part 3170, which was proposed to be added 
on July 13, 2015 (80 FR 40768), continues to read as follows:

    Authority:  25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, 
and 1751; and 43 U.S.C. 1732(b), 1733, and 1740.

0
7. Add subparts 3178 and 3179 to part 3170, which was proposed to be 
added on July 13, 2015 (80 FR 40768), to read as follows:
Subpart 3178--Royalty-Free Use of Lease Production
Sec.
3178.1 Purpose.
3178.2 Scope.
3178.3 Production on which a royalty is not due.
3178.4 Uses of oil or gas on lease, unit, or CA that do not require 
prior written BLM approval for royalty-free treatment of volumes 
used.
3178.5 Uses of oil or gas on a lease, unit, or CA that require prior 
written BLM approval for royalty-free treatment of volumes used.
3178.6 Uses of oil or gas moved off the lease, unit, or CA that do 
not require prior written approval for royalty-free treatment of 
volumes used.
3178.7 Uses of oil or gas moved off the lease, unit, or CA that 
require prior written approval for royalty-free treatment of volumes 
used.
3178.8 Measurement or estimation of royalty-free volumes.
3178.9 Requesting approval of royalty-free treatment when approval 
is required.
3178.10 Facility and equipment ownership.
Subpart 3179--Waste Prevention and Resource Conservation
Sec.
3179.1 Purpose.
3179.2 Scope.
3179.3 Definitions and acronyms.

[[Page 6680]]

3179.4 Determining when the loss of oil or gas is avoidable or 
unavoidable.
3179.5 When lost production is subject to royalty.
3179.6 When flaring or venting is prohibited.
3179.7 Alternative limits on venting and flaring.
3179.8 Measuring and reporting volumes of gas vented and flared from 
wells.
3179.9 Determinations regarding royalty-free venting or flaring.
3179.10 Other waste-prevention measures.
3179.11 Coordination with State regulatory authority.

Flaring and Venting Gas During Drilling and Production Operations

3179.101 Well drilling.
3179.102 Well completion and related operations.
3179.103 Initial production testing.
3179.104 Subsequent well tests.
3179.105 Emergencies.

Gas Flared or Vented From Equipment During Well Maintenance Operations

3179.201 Equipment requirements for pneumatic controllers.
3179.202 Requirements for pneumatic chemical injection pumps or 
pneumatic diaphragm pumps.
3179.203 Crude oil and condensate storage vessels.
3179.204 Downhole well maintenance and liquids unloading.

Leak Detection and Repair (LDAR)

3179.301 Operator responsibility.
3179.302 Approved instruments and methods.
3179.303 Leak detection and inspection requirements for natural gas 
wellhead equipment, facilities, and compressors.
3179.304 Repairing leaks.
3179.305 Leak detection inspection recordkeeping.

State or Tribal Variances

3179.401 State or tribal requests for variances from the 
requirements of this subpart.


Sec.  3178.1  Purpose.

    The purpose of this subpart is to address the circumstances under 
which oil or gas produced from Federal and Indian leases may be used 
royalty-free in operations on the lease, unit, or communitized area 
(CA). This subpart supersedes those portions of Notice to Lessees and 
Operators of Onshore Federal and Indian Oil and Gas Leases (NTL-4A), 44 
FR 76600 (December 27, 1979), pertaining to oil or gas used for 
beneficial purposes.


Sec.  3178.2  Scope.

    (a) This subpart applies to:
    (1) All onshore Federal and Indian (other than Osage Tribe) oil and 
gas leases, units, and CAs, except as otherwise provided in this 
subpart;
    (2) Indian Mineral Development Act (IMDA) oil and gas agreements, 
unless specifically excluded in the agreement or unless the relevant 
provisions of this subpart are inconsistent with the agreement;
    (3) Leases and other business agreements and contracts for the 
development of tribal energy resources under a Tribal Energy Resource 
Agreement entered into with the Secretary, unless specifically excluded 
in the lease, other business agreement, or Tribal Energy Resource 
Agreement;
    (4) Committed State or private tracts in a federally approved unit 
or communitization agreement defined by or established under 43 CFR 
subpart 3105 or 43 CFR part 3180;
    (5) All onshore wells, tanks, compressors, and other facilities 
located on a Federal or Indian lease or a federally approved unit or 
CA; and
    (6) All gas lines located on a Federal or Indian lease or federally 
approved unit or CA that are owned or operated by the operator of the 
lease, unit, or communitization agreement.
    (b) For purposes of this subpart, the term ``lease'' also includes 
IMDA agreements.


Sec.  3178.3  Production on which royalty is not due.

    (a) To the extent specified in Sec. Sec.  3178.4 and 3178.5, 
royalty is not due on:
    (1) Oil or gas that is produced from a lease or CA and used for 
operations and production purposes (including placing oil or gas in 
marketable condition) on the same lease or CA without being removed 
from the lease or CA; or
    (2) Oil or gas that is produced from a unit PA and used for 
operations and production purposes (including placing oil or gas in 
marketable condition) on the unit, for the same unit PA, without being 
removed from the unit.
    (a) For the uses described in Sec.  3178.5, the operator must 
obtain prior written BLM approval for the volumes used for operational 
and production purposes to be royalty free.


Sec.  3178.4  Uses of oil or gas on a lease, unit, or CA that do not 
require prior written BLM approval for royalty-free treatment of 
volumes used.

    (a) Uses of produced oil or gas for operations and production 
purposes that do not require prior written BLM approval for the used 
volumes to be treated as royalty free under Sec.  3178.3 are:
    (1) Use of fuel to power artificial lift equipment;
    (2) Use of fuel to power equipment used for enhanced recovery;
    (3) Use of fuel to power drilling rigs;
    (4) Use of gas to actuate pneumatic controllers or operate 
pneumatic pumps at production facilities;
    (5) Use of fuel to heat, separate, or dehydrate production;
    (6) Use of fuel to compress gas to place it in marketable 
condition; and
    (7) Use of oil that an operator produces from a lease, unit, or CA 
and pumps into a well on the same lease, unit, or CA to clean the well 
and improve production, e.g., hot oil treatment. The operator must 
document the removal of the oil from the tank or pipeline under Onshore 
Oil and Gas Order No. 3 (Site Security), or any successor regulation.
    (b) The volume to be treated as royalty free must not exceed the 
amount of fuel reasonably necessary to perform the operational 
function, using equipment of appropriate capacity.


Sec.  3178.5  Uses of oil or gas on a lease, unit, or CA that require 
prior written BLM approval for royalty-free treatment of volumes used.

    (a) Uses that require prior written approval from the BLM before 
the production used may be treated as royalty free under Sec.  3178.3 
include: (1) Using oil as a circulating medium in drilling operations;
    (2) Injecting gas that an operator produces from a lease, unit PA, 
or CA into the same lease, unit PA, or CA for the purpose of increasing 
the recovery of oil or gas (including gas that is cycled in a contained 
gas-lift production system), subject to an approval under 3162.3-2 of 
this title to conduct the gas injection;
    (3) Using oil or gas that an operator removes from the pipeline at 
a location downstream of the Facility Measurement Point (FMP), if 
removal and use both occur on the lease, unit, or CA;
    (4) Using gas initially removed from a lease, unit PA, or CA for 
treatment or processing because of particular physical characteristics 
of the gas, where the gas is returned to the lease, unit, or CA for 
lease operations; and
    (5) Any other type of use of produced oil or gas for operations and 
production purposes pursuant to Sec.  3178.3 that is not identified in 
Sec.  3178.4.
    (b) (1) The operator must obtain BLM approval to conduct activities 
under paragraph (a) of this section by submitting a Form 3160-5, Sundry 
Notices and Reports on Wells (Sundry Notice) containing the information 
required under Sec.  3178.9.
    (2) With respect to uses under paragraph (a)(3) of this section, 
the operator must measure the volume of oil or gas used in accordance 
with Onshore

[[Page 6681]]

Oil and Gas Orders No. 4 (oil) and 5 (gas) as applicable, or other 
successor regulations.
    (3) With respect to uses under paragraph (a)(4) of this section, 
the operator must measure any gas returned to the lease, unit, or CA 
under such an approval in accordance with Onshore Oil and Gas Order No. 
5 or other successor regulations.
    (c) If the BLM disapproves a request for royalty-free treatment for 
volumes used under this section, the operator must pay royalties for 
the gas used beginning on the date the operator was required to request 
approval under paragraph (a) of this section.


Sec.  3178.6  Uses of oil or gas moved off the lease, unit, or CA that 
do not require prior written approval for royalty-free treatment of 
volumes used.

    Oil or gas used after being moved off the lease, unit, or CA may be 
treated as royalty free without prior written BLM approval only if the 
use meets the criteria under Sec.  3178.4 and when:
    (a) Oil or gas is piped along a logical route, based on existing 
access, topography, land ownership or other similar characteristic, 
directly from one area of the lease, unit, or CA to another area of the 
same lease, unit, or CA where it is used without oil or gas being added 
to or removed from the pipeline while crossing lands that are not part 
of the lease, unit, or CA; or
    (b) A well is directionally drilled and the wellhead is not located 
on the producing lease, unit, or CA, and oil or gas is used on the same 
well pad for operations and production purposes for that well.


Sec.  3178.7  Uses of oil or gas moved off the lease, unit, or CA that 
require prior written approval for royalty-free treatment of volumes 
used.

    (a) Except as provided in Sec.  3178.6(b) and paragraph (b) of this 
section, royalty is owed on all oil or gas used in operations conducted 
off the lease, unit, or CA.
    (b) The BLM may grant prior written approval to treat oil or gas 
used in operations conducted off the lease, unit, or CA as royalty free 
(referred to as off-lease royalty-free use) if the use meets one or 
more of the criteria listed in Sec.  3178.5(a) and if:
    (1) The equipment or facility in which the operation is conducted 
is located off the lease, unit, or CA for engineering, economic, 
resource-protection, or physical-accessibility reasons; and
    (2) The operations are conducted upstream of the FMP.
    (c) The operator must obtain BLM approval under paragraph (b) of 
this section by submitting a Sundry Notice containing the information 
required under Sec.  3178.9.
    (d) Approval of measurement or commingling off the lease, unit, or 
CA under other regulations does not constitute approval of off-lease 
royalty-free use. The operator or lessee must expressly request, and 
submit its justification for, approval of off-lease royalty-free use.
    (e) If equipment or a facility located on a particular lease, unit, 
or CA treats oil or gas produced from properties that are not unitized 
or communitized with the property on which the equipment or facility is 
located, in addition to treating oil or gas produced from the lease, 
unit, or CA on which the equipment or facility is located, the operator 
may report as royalty free only that portion of the oil or gas used as 
fuel that is properly allocable to the share of production contributed 
by the lease, unit, or CA on which the equipment is located, unless 
otherwise authorized by the BLM under this section.


Sec.  3178.8  Measurement or estimation of royalty-free volumes.

    (a) The operator must measure or estimate the volumes of royalty-
free gas used in operations upstream of the FMP.
    (b) The operator must measure all gas that is removed from the 
product stream downstream of the FMP and used in operations on the 
lease, unit, or CA (or off the lease, unit, or CA if the BLM approves 
such use), using the measurement procedures in Onshore Oil and Gas 
Order No. 5 or other successor regulation.
    (c) The operator must measure the volume of oil used in operations 
on the lease, unit, or CA (or off the lease, unit, or CA if the BLM 
approves such use) using the measurement procedures in Onshore Oil and 
Gas Order No. 4 or other successor regulation. The operator must also 
document removal of such oil from the tank or pipeline.
    (d) Each of the volumes required to be measured or estimated, as 
applicable, under this subpart, must be reported by the operator 
following applicable ONRR reporting requirements.


Sec.  3178.9  Requesting approval of royalty-free treatment when 
approval is required.

    To request written approval of royalty-free use when required under 
Sec.  3178.5, or of off-lease royalty-free use under Sec.  3178.7, the 
operator must submit a Sundry Notice that includes the following 
information:
    (a) A complete description of the operation to be conducted, 
including the location of all facilities and equipment involved in the 
operation and the location of the FMP;
    (b) The volume of oil or gas that the operator expects will be used 
in the operation, and the method of measuring or estimating that 
volume;
    (c) If the volume of gas expected to be used will be estimated, the 
basis for the estimate (e.g., equipment manufacturer's published 
consumption or usage rates); and
    (d) The proposed disposition of the oil or gas used (e.g., whether 
gas used would be consumed as fuel, vented through use of a gas-
activated pneumatic controller, returned to the reservoir, or some 
other disposition).


Sec.  3178.10  Facility and equipment ownership.

    The operator is not required to own or lease the equipment or 
facility that uses oil or gas royalty free. The operator is responsible 
for obtaining all authorizations, measuring production, reporting 
production, and all other applicable requirements.

Subpart 3179--Waste Prevention and Resource Conservation


Sec.  3179.1  Purpose.

    The purpose of this subpart is to implement and carry out the 
purposes of statutes relating to prevention of waste from Federal and 
Indian (other than Osage Tribe) leases, conservation of surface 
resources, and management of the public lands for multiple use and 
sustained yield. This subpart supersedes those portions of Notice to 
Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases 
(NTL-4A), 44 FR 76600 (December 27, 1979), pertaining to, among other 
things, flaring and venting of produced gas, unavoidably and avoidably 
lost gas, and waste prevention.


Sec.  3179.2  Scope.

    (a) This subpart applies to:
    (1) All onshore Federal and Indian (other than Osage Tribe) oil and 
gas leases, units, and CAs, except as otherwise provided in this 
subpart;
    (2) IMDA oil and gas agreements, unless specifically excluded in 
the agreement or unless the relevant provisions of this subpart are 
inconsistent with the agreement;
    (3) Leases and other business agreements and contracts for the 
development of tribal energy resources under a Tribal Energy Resource 
Agreement entered into with the Secretary, unless specifically excluded 
in the lease, other business agreement, or Tribal Energy Resource 
Agreement;
    (4) Committed State or private tracts in a federally approved unit 
or communitization agreement defined by

[[Page 6682]]

or established under 43 CFR subpart 3105 or 43 CFR part 3180;
    (5) All onshore wells, tanks, compressors, and other facilities 
located on a Federal or Indian lease or a federally approved unit or 
CA; and
    (6) All gas lines located on a Federal or Indian lease or federally 
approved unit or CA that are owned or operated by the operator of the 
lease, unit, or communitization agreement.
    (b) For purposes of this subpart, the term ``lease'' also includes 
IMDA agreements.


Sec.  3179.3  Definitions and acronyms.

    As used in this subpart, the term:
    Accessible component means a component that can be reached, if 
necessary, by safe and proper use of portable ladders or by built-in 
ladders and walkways. Accessible components also include components 
that can be reached by the safe use of an extension on a monitoring 
probe.
    Capture means the physical containment of natural gas for 
transportation to market or productive use of natural gas, and includes 
reinjection and royalty-free on-site uses pursuant to subpart 3178.
    Capture infrastructure means any pipelines, facilities, or other 
equipment (including temporary or mobile equipment) used to capture, 
transport, or process gas. Capture infrastructure includes, but is not 
limited to, equipment that compresses or liquefies natural gas, removes 
natural gas liquids, or generates electricity from gas.
    Component means any piece of equipment that has the potential to 
leak gas and can be tested in the manner described in Sec. Sec.  
3179.301 through 3179.305 of this subpart.
    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 are being produced at a profit or 
expected profit. For purposes of this subpart, the BLM will determine 
when a well is a development oil well or development gas well in the 
event of a disagreement between the BLM and the operator.
    Gas-to-oil ratio (GOR) means the ratio of gas to oil in the 
production stream expressed in standard cubic feet of gas per barrel of 
oil.
    Gas well means a well for which the energy equivalent of the gas 
produced, including its entrained liquefiable hydrocarbons, exceeds the 
energy equivalent of the oil produced. Unless more specific British 
thermal unit (Btu) values are available, a well with a gas-to-oil ratio 
greater than 6 thousand cubic feet (Mcf) of gas per barrel of oil is a 
gas well. Except where gas has been re-injected into the reservoir, a 
mature oil well would not be reclassified as a gas well even after 
normal production decline has caused the GOR to increase beyond 6 Mcf 
of gas per barrel of oil.
    Liquid hydrocarbon means chemical compounds of hydrogen and carbon 
atoms that exist as a liquid under the temperature and pressure at 
which they are measured. The term is used to refer to oil, condensate, 
liquefied petroleum gas (LPG), liquefied natural gas (LNG), and natural 
gas liquids (NGL).
    Liquids unloading means the removal of an accumulation of liquid 
hydrocarbons or water in the wellbore of a completed gas well.
    Lost oil or lost gas means produced oil or gas that escapes 
containment, either intentionally or unintentionally, or is flared 
before being removed from the lease, unit, or CA, and cannot be 
recovered.
    Storage vessel means a crude oil or condensate storage tank or 
battery of tanks that vents, or is designed to vent, to the atmosphere 
during normal operations.
    Volatile organic compounds (VOC) has the same meaning as defined in 
40 CFR 51.100(s).


Sec.  3179.4  Determining when the loss of oil or gas is avoidable or 
unavoidable.

    For purposes of this subpart:
    (a) ``Unavoidably lost'' oil or gas means lost oil or gas where the 
operator has not been negligent, and has complied fully with applicable 
laws, lease terms, regulations, provisions of a previously approved 
operating plan, or other written orders of the BLM, including:
    (1) Produced oil or gas that is lost from the following operations 
or sources and cannot be recovered in the normal course of operations, 
where the operator has taken prudent and reasonable steps to avoid 
waste:
    (i) Well drilling;
    (ii) Well completion and related operations;
    (iii) Initial production tests, subject to the limitations in Sec.  
3179.103;
    (iv) Subsequent well tests, subject to the limitations in Sec.  
3179.104;
    (v) Exploratory coalbed methane well dewatering;
    (vi) Emergencies, subject to the limitations in Sec.  3179.105;
    (vii) Evaporation from storage vessels;
    (viii) Downhole well maintenance;
    (ix) Liquids unloading;
    (x) Leaks; and
    (xi) Releases from pneumatic controllers and pumps; or
    (2) Produced gas that is flared or vented from a well that is not 
connected to gas capture infrastructure, absent a BLM determination 
that the loss of gas through such venting or flaring is otherwise 
avoidable, subject to the limitations in Sec.  3179.6.
    (b) ``Avoidably lost'' oil or gas means lost oil or gas that is not 
unavoidably lost as defined in paragraph (a) of this section.


Sec.  3179.5  When lost production is subject to royalty.

    (a) Royalty is due on:
    (1) All avoidably lost oil or gas; and
    (2) Waste oil that became waste through operator negligence.
    (b) Royalty is not due on:
    (1) Unavoidably lost oil or gas; and
    (2) Waste oil that did not become waste through operator 
negligence.


Sec.  3179.6  When flaring or venting is prohibited.

    (a) The operator must flare rather than vent any gas that is not 
captured except:
    (1) When flaring the gas is technically infeasible, such as when 
the gas is not readily combustible or the volumes are too small to 
flare;
    (2) Under emergency conditions when the loss of gas is 
uncontrollable or venting is necessary for safety, subject to Sec.  
3179.105;
    (3) When Sec.  3179.203 does not require the combustion or flaring 
of gas vapors from storage vessels; or
    (4) When the gas is vented through operation of a natural gas-
activated pneumatic controller or pump.
    (b) Except as provided in Sec.  3179.7, an operator must not flare 
or vent gas in excess of the following amounts, representing the total 
volume of gas flared or vented over a production month from all 
development oil wells on a lease, unit, or CA, divided by the number of 
development oil wells contributing production for at least 10 days 
during that month:
    (1) 7,200 Mcf, for each month during the period from [EFFECTIVE 
DATE OF FINAL RULE] until [1 YEAR AFTER EFFECTIVE DATE OF FINAL RULE];
    (2) 3,600 Mcf, for each month during the period from [1 YEAR AFTER 
EFFECTIVE DATE OF FINAL RULE] until [2 YEARS AFTER EFFECTIVE DATE OF 
FINAL RULE]; and
    (3) 1,800 Mcf, for each month thereafter.


Sec.  3179.7  Alternative limits on venting and flaring.

    (a) With respect to leases issued before the effective date of this 
regulation, the BLM may approve an alternative rate-based limit on 
venting and flaring from a lease, unit, or CA that is flaring at a rate 
that exceeds the applicable limit under Sec.  3179.6, if the

[[Page 6683]]

operator demonstrates, and the BLM agrees, that the applicable limit 
under Sec.  3179.6 would impose such costs as to cause the operator to 
cease production and abandon significant recoverable oil reserves under 
the lease.
    (b) To support such a demonstration, the operator must submit a 
Sundry Notice that includes the following information:
    (1) Information regarding the operator's wells under the lease that 
produce Federal or Indian gas, including:
    (i) The name, number, and location of each well, and the number of 
the lease, unit, or CA with which it is associated;
    (ii) The depths and names of producing formations;
    (iii) The gas production level of each of the operator's wells for 
the most recent production month for which information is available; 
and
    (iv) The volumes of gas being vented and flared from each of the 
operator's wells;
    (2) Map(s) showing:
    (i) The entire lease, unit, or CA and the surrounding lands to a 
distance and on a scale that shows the field in which the well or wells 
are or will be located (if applicable), and all pipelines that could 
transport the gas from the well or wells;
    (ii) All of the operator's producing oil and gas wells, which are 
producing from Federal or Indian leases (both on Federal or Indian 
leases and on other properties) within the map area;
    (iii) Identification of all of the operator's wells within the 
lease from which gas is flared or vented, and the location and distance 
of the nearest gas pipeline(s) to each such well, with an 
identification of those pipelines that are or could be available for 
connection and use; and
    (iv) Identification of all of the operator's wells within the lease 
from which gas is captured;
    (3) Data that show pipeline capacity and the operator's projections 
of the cost associated with installation and operation of gas capture 
infrastructure and alternative methods of transportation that do not 
require pipelines;
    (4) The operator's projections of gas prices, gas production 
volumes, gas quality (i.e., heating value and H2S content), 
revenues derived from gas production, and royalty payments on gas 
production over the next 15 years or the life of the operator's lease, 
unit, or CA, whichever is less; and
    (5) The operator's projections of oil prices, oil production 
volumes, costs, revenues, and royalty payments from the operator's oil 
and gas operations within the lease over the lesser of:
    (i) The next 15 years; or
    (ii) The anticipated remaining period in which the operator will 
produce from the Federal or Indian lease, unit, or CA.
    (c) In establishing an alternative volume limit on venting and 
flaring under this section, the BLM will aim to set the limit at the 
lowest level that the BLM determines, considering the information 
identified in paragraph (b) of this section, will not cause the 
operator to cease production and abandon significant recoverable oil 
reserves under the lease.
    (d) Instead of an alternative limit under paragraph (a) of this 
section, a lease issued before the effective date of this regulation 
will receive a renewable, 2-year exemption from the applicable flaring 
limit specified in Sec.  3179.6 if the authorizing officer verifies 
that all of the following terms and conditions are met:
    (i) The lease, unit, or CA is not connected to a gas pipeline;
    (ii) The closest point on the lease, unit, or CA is located more 
than 50 straight-line miles from the nearest gas processing plant;
    (iii) In the most recent production month, the lease, unit or CA 
flared or vented at an average rate that exceeds by at least 50 percent 
the applicable flaring limit specified in Sec.  3179.6; and
    (iv) The operator submits to the BLM a Sundry Notice with an 
affidavit certifying that it meets the conditions in paragraphs (d)(i) 
through (iii) of this section.


Sec.  3179.8  Measuring and reporting volumes of gas vented and flared 
from wells.

    (a) The operator must estimate or measure all volumes of gas vented 
or flared from wells, and report those volumes under applicable ONRR 
reporting requirements, including 30 CFR part 1210.
    (b) The operator may choose whether to estimate or measure such 
volumes, except that measurement is required:
    (1) If the operator estimates that the volume of gas vented or 
flared from a flare stack or manifold equals or exceeds 50 Mcf per day; 
or
    (2) If the BLM determines and informs the operator that the 
additional accuracy offered by measurement is necessary for effective 
implementation of this subpart.


Sec.  3179.9  Determinations regarding royalty-free venting or flaring.

    (a) Approvals to flare or vent royalty free, and/or to flare or 
vent at a level above the 7,200 Mcf per month limit in Sec.  
3179.6(b)(1), which are in effect as of the effective date of this 
rule, will continue in effect until [90 DAYS AFTER EFFECTIVE DATE OF 
THE FINAL RULE].
    (b) The provisions of this subpart do not affect any determination 
made by the BLM before or after [EFFECTIVE DATE OF FINAL RULE], with 
respect to the royalty-bearing status of flaring that occurred prior to 
[EFFECTIVE DATE OF FINAL RULE].


Sec.  3179.10  Other waste prevention measures.

    (a) If production from an oil well newly connected to a gas 
pipeline results or is expected to result in one or more producing 
wells already connected to the pipeline being forced off the line, the 
BLM may exercise existing authority to limit the production level from 
the new well until the pressure of gas production from the new well 
stabilizes at levels that allow transportation of gas from all wells 
connected to the line.
    (b) If gas capture capacity is not yet available on a given lease, 
the BLM may exercise existing authority to delay action on the APD for 
that lease, or approve the APD with conditions for gas capture or 
limitations on production. If the lease for which the APD is submitted 
is not yet producing, the BLM may direct or grant a lease suspension 
under 43 CFR 3103.4-4.


Sec.  3179.11  Coordination with State regulatory authority.

    To the extent that any BLM action to enforce a prohibition, 
limitation, or order under this subpart adversely affects production of 
oil or gas that comes from non-Federal and non-Indian mineral 
interests, the BLM will coordinate, on a case-by-case basis, with the 
State regulatory authority having jurisdiction over the oil and gas 
production from the non-Federal and non-Indian interests.

Flaring and Venting Gas During Drilling and Production Operations


Sec.  3179.101  Well drilling.

    (a) Except as provided in Sec.  3179.6(a) of this subpart, gas that 
reaches the surface as a normal part of drilling operations must be:
    (1) Captured and sold;
    (2) Directed to a flare pit or flare stack equipped with an 
automatic igniter to combust any flammable gasses;
    (3) Used in operations on the lease, unit, or CA; or
    (4) Injected.
    (b) If gas is lost as a result of loss of well control, the BLM 
will make a determination of whether the loss of well control is due to 
operator negligence. Such gas is avoidably lost if the BLM determines 
that the loss of well

[[Page 6684]]

control is due to operator negligence. The BLM will notify the operator 
in writing when it makes a determination that gas was lost due to 
operator negligence.


Sec.  3179.102  Well completion and related operations.

    (a) Except as provided in Sec.  3179.6(a), gas that reaches the 
surface during well completion and post-completion, drilling fluid 
recovery, or fracturing or refracturing fluid recovery operations must 
be:
    (1) Captured and sold;
    (2) Directed to a flare pit or flare stack equipped with an 
automatic igniter to combust any flammable gasses, subject to the 
volumetric limitations in Sec.  3179.103(a)(3);
    (3) Used in operations on the lease, unit, or CA; or
    (4) Injected.
    (b) In lieu of compliance with the requirements of paragraph (a) of 
this section, an operator may demonstrate to the BLM on a Sundry Notice 
that it is in compliance with the requirements for control of gas from 
well completions established under 40 CFR part 60, subpart OOOOa.


Sec.  3179.103  Initial production testing.

    (a) Gas flared during a well's initial production test is royalty-
free under Sec. Sec.  3179.4(a)(1)(iii) and 3179.5(b) of this subpart 
until one of the following occurs:
    (1) The operator determines that it has obtained adequate reservoir 
information for the well;
    (2) 30 days have passed since the beginning of the production test, 
except as provided in paragraph (b) and paragraph (c) of this section;
    (3) The operator has flared 20 million cubic feet (MMcf) of gas, 
when volumes flared under this section are combined with volumes flared 
under Sec.  3179.102(b); or
    (4) Production begins.
    (b) The BLM may extend the period specified in paragraph (a)(2) not 
to exceed an additional 60 days, based on testing delays caused by well 
or equipment problems or if there is a need for further testing to 
develop adequate reservoir information.
    (c) During the dewatering and initial evaluation of an exploratory 
coalbed methane well, the 30-day period specified in paragraph (a)(2) 
of this section is extended to 90 days. The BLM may approve up to two 
extensions of this evaluation period, of up to 90 days each.
    (d) The operator must submit its request for a longer test period 
under paragraph (b) or (c) of this section using a Sundry Notice.


Sec.  3179.104  Subsequent well tests.

    During well tests subsequent to the initial production test, the 
operator may flare gas for no more than 24 hours royalty free under 
Sec. Sec.  3179.4(a)(1)(iv) and 3179.5(b) of this subpart, unless the 
BLM approves or requires a longer period. If the operator requests a 
longer period, it must submit a Sundry Notice.


Sec.  3179.105  Emergencies.

    (a) An operator may flare or, if flaring is not feasible given the 
emergency, vent gas royalty-free under Sec.  3179.6(a) of this subpart 
during a temporary, short-term, infrequent, and unavoidable emergency.
    (b) The operator may flare or vent gas royalty free for up to 24 
hours per incident (unless the BLM extends the period), and for no more 
than three emergencies for a lease, unit, or CA within any 30-day 
period.
    (c) The following do not constitute emergencies under this section:
    (1) More than 3 failures of the same equipment within any 365-day 
period;
    (2) The operator's failure to install appropriate equipment of a 
sufficient capacity to accommodate the volume of gas being produced;
    (3) Failure to limit production when the production rate exceeds 
the capacity of the related equipment, pipeline, or gas plant, or 
exceeds sales contract volumes of oil or gas;
    (4) Scheduled maintenance; or
    (5) Operator negligence.
    (d) The operator must estimate and report to the BLM on a Sundry 
Notice the volumes flared or vented beyond the timeframes specified in 
paragraph (b) of this section.

Gas Flared or Vented From Equipment or During Well Maintenance 
Operations


Sec.  3179.201  Equipment requirements for pneumatic controllers.

    (a) A pneumatic controller that uses natural gas produced from a 
Federal or Indian lease, or from a unit or CA that includes a Federal 
or Indian lease, is subject to this section if the pneumatic 
controller:
    (1) Has a continuous bleed rate greater than 6 standard cubic feet 
(scf) per hour; and
    (2) Is not subject to 40 CFR 60.5360 through 60.5390.
    (b) The operator must replace a pneumatic controller subject to 
this section with a pneumatic controller having a bleed rate of 6 scf 
per hour or less within the timeframes set forth in paragraph (c) of 
this section, unless:
    (1) The operator notifies the BLM through a Sundry Notice that use 
of a pneumatic controller with a bleed rate greater than 6 scf per hour 
is required based on functional needs described in the Sundry Notice, 
that may include, but are not limited to, response time, safety, and 
positive actuation;
    (2) The operator notifies the BLM through a Sundry Notice that the 
pneumatic controller exhaust is routed to a flare device; or
    (3) The operator notifies the BLM through a Sundry Notice and 
demonstrates, and the BLM agrees, based on the information identified 
in Sec.  3179.7(b), that replacement of a pneumatic controller subject 
to paragraph (a)(1)(i) of this section would impose such costs as to 
cause the operator to cease production and abandon significant 
recoverable oil reserves under the lease.
    (c) The operator must replace the pneumatic controller(s) no later 
than 1 year after the effective date of this section as required under 
paragraph (b) of this section, except that if the well or facility that 
the pneumatic controller serves has an estimated remaining productive 
life of 3 years or less from the effective date of this section, the 
operator must notify the BLM through a Sundry Notice and replace the 
pneumatic controller no later than 3 years from the effective date of 
this section.
    (d) The operator must ensure pneumatic controllers are functioning 
within manufacturers' specifications.


Sec.  3179.202  Requirements for pneumatic chemical injection pumps or 
pneumatic diaphragm pumps.

    (a) A pneumatic chemical injection or pneumatic diaphragm pump is 
subject to this section if it:
    (1) Uses natural gas produced from a Federal or Indian lease, or 
from a unit or CA that includes a Federal or Indian lease; and
    (2) Is not subject to 40 CFR part 60, subpart OOOOa.
    (b) The operator must replace a pneumatic pump subject to this 
paragraph with a zero-emissions pump or route the pump to a flare 
device within the timeframes set forth in paragraph (d) of this 
section.
    (c) The requirement in paragraph (b) of this section does not apply 
if:
    (1) The operator notifies the BLM through a Sundry Notice that:
    (i) Use of a pneumatic pump is required based on functional needs, 
described in the Sundry Notice; and
    (ii) There is no existing flare device on site or routing to such a 
device is technically infeasible; or
    (2) The operator submits a Sundry Notice to the BLM that:
    (i) Provides an economic analysis that demonstrates, and the BLM 
agrees,

[[Page 6685]]

based on the information identified in Sec.  3179.7(b), that 
installation of a zero-emissions pump(s) would impose such costs as to 
cause the operator to cease production and abandon significant 
recoverable oil reserves under the lease; and
    (ii) Demonstrates to the BLM that there is no existing flare device 
on site or routing to such a device is technically infeasible.
    (d) The operator must replace the pneumatic pump(s) or connect to a 
flare device no later than 1 year after the effective date of this 
section, except that if the well or facility that the pneumatic pump 
serves has an estimated remaining productive life of 3 years or less 
from the effective date of this section, the operator must notify the 
BLM through a Sundry Notice and replace the pneumatic pump no later 
than 3 years from the effective date of this section.
    (e) The operator must ensure pneumatic pumps are functioning within 
manufacturers' specifications.


Sec.  3179.203  Crude oil and condensate storage vessels.

    (a) A crude oil or condensate storage vessel is subject to this 
section if the vessel:
    (1) Contains production from a Federal or Indian lease, or from a 
unit or CA that includes a Federal or Indian lease;
    (2) Is not subject to 40 CFR part 60, subpart OOOO; and
    (3) Has a rate of total VOC emissions equal to or greater than 6 
tons per year (tpy).
    (b) The operator must determine the rate of emissions from the 
storage vessel within 60 days after the effective date of this section, 
and within 30 days after any new source of production is added to the 
tank.
    (c) No later than 6 months after the effective date of this 
section, the operator must route all tank vapor gas from a storage 
vessel that is subject to this section to a combustion device or 
continuous flare, or to a sales line unless the operator submits an 
economic analysis to the BLM through a Sundry Notice that demonstrates, 
and the BLM agrees, based on the information identified in Sec.  
3179.7(b), that compliance with this requirement would impose such 
costs as to cause the operator to cease production and abandon 
significant recoverable oil reserves under the lease.
    (d) If the rate of total uncontrolled gas release from a storage 
vessel declines to 4 tpy or less for any continuous 12 month period, 
the requirements of this section no longer apply.


Sec.  3179.204  Downhole well maintenance and liquids unloading.

    (a) During downhole well maintenance and liquids unloading 
operations, the operator must use practices that maximize the recovery 
of gas for sale and must flare gas not recovered except where such 
practices or flaring are technically infeasible or unduly costly. 
Before the operator purges a well for the first time after the 
effective date of this section, the operator must document that other 
methods are technically infeasible or unduly costly, and provide that 
information as part of the Sundry Notice required under paragraph (d) 
of this section.
    (b) For wells drilled after the effective date of this section, the 
operator may not conduct liquids unloading by well purging, except 
where the operator is returning a well to production following a well 
workover or following a shut-in for more than 30 days.
    (c) For any liquids unloading by well purging, the operator must:
    (1) Be present on-site throughout the event to ensure that any 
venting to the atmosphere is limited to no more than what is 
practically necessary, unless the operator uses an automatic control 
system that relies on real-time pressure or flow, timers, or other well 
data to minimize venting;
    (2) Record the cause, date, time, duration, and estimated volume of 
each venting event; and
    (3) Maintain the liquids unloading records for the period required 
under Sec.  3162.4-1 of this title and make them available to the BLM, 
upon request.
    (d) The operator must notify the BLM by Sundry Notice within 10 
calendar days after the first liquids unloading event by well purging 
conducted after the effective date of this section. This requirement 
applies to each well the operator operates.
    (e) The operator must notify the BLM by Sundry Notice, within 14 
calendar days, if:
    (1) The cumulative duration of well purging events for a well 
exceeds 24 hours during any production month; or
    (2) The estimated volume of gas vented in liquids unloading by well 
purging operations for a well exceeds 75 Mcf during any production 
month.
    (f) For purposes of this section, ``well purging'' means blowing 
accumulated liquids out of a wellbore by gas pressure where the gas is 
vented to the atmosphere.
    (g) Total estimated volumes vented as a result of downhole well 
maintenance and liquids unloading during the production month must be 
included in volumes reported to ONRR as vented.

Leak Detection and Repair (LDAR)


Sec.  3179.301  Operator responsibility.

    (a) The requirements of Sec. Sec.  3179.301 through 3179.305 of 
this subpart apply to all wells that produce natural gas from a Federal 
or Indian lease, or from a unit or CA that includes a Federal or Indian 
lease, including oil wells that also produce natural gas.
    (b) The operator is responsible, as prescribed in Sec. Sec.  
3179.302 and 3179.303 of this subpart, to inspect for gas leaks on the 
following:
    (1) All equipment and equipment components at the wellhead;
    (2) All facilities that the operator operates; and
    (3) All compressors located on the lease, unit, or CA that the 
operator owns, leases, or operates.
    (c) All leak inspections must occur during production operations.
    (d) The operator must fix the leaks as prescribed in Sec. Sec.  
3179.304 and 3179.305 of this subpart. See 43 CFR 3162.5-1 for 
responsibility to repair oil leaks.
    (e) An operator may satisfy the requirements of Sec. Sec.  3179.301 
through 3179.305 for some or all of the equipment or facilities on a 
given lease by demonstrating to the BLM on a Sundry Notice that the 
operator is complying with LDAR requirements established under 40 CFR 
part 60, subpart OOOOa with respect to such equipment or facilities.


Sec.  3179.302  Approved instruments and methods.

    (a) The operator must use one or more of the following instruments 
or monitoring methods to detect leaks:
    (1) An optical gas imaging device;
    (2) A monitoring device not listed in this section, which is 
approved by the BLM for use by any operator, under Sec.  3179.303(b) of 
this subpart;
    (3) A comprehensive program, approved by the BLM under Sec.  
3179.303(b) of this subpart, that includes the use of instrument-based 
monitoring devices; or
    (4) A portable analyzer device capable of detecting leaks, such as 
catalytic oxidation, flame ionization, infrared absorption or 
photoionization devices, operated according to manufacturer 
specifications, and assisted by audio, visual, and olfactory 
inspection.
    (b) If an operator operates 500 or more wells within the 
jurisdiction of a single BLM field office, the operator may only use 
one or more of the methods identified in paragraph (a)(1), (2), or (3) 
of this section to detect leaks.

[[Page 6686]]

Sec.  3179.303  Leak detection inspection requirements for natural gas 
wellhead equipment, facilities, and compressors.

    (a) Except as provided below or otherwise authorized in paragraph 
(b) of this section, the operator must inspect at least semi-annually 
for leaks the wellhead equipment, facilities, and compressors 
identified in Sec.  3179.301(b) of this subpart. For purposes of 
Sec. Sec.  3179.301 through 3179.305, the term ``site'' means a 
discrete area containing wellhead equipment, facilities, and 
compressors, which is suitable for inspection in a single visit.

----------------------------------------------------------------------------------------------------------------
                                   And in two consecutive
    If the operator inspects          inspections the                           The operator
                                          operator
----------------------------------------------------------------------------------------------------------------
(1) Semi-annually...............  Detects no more than 2   Must inspect at least annually.
                                   leaks at the site
                                   inspected.
(2) Annually....................  Detects 3 or more leaks  Must inspect at least semi-annually.
                                   at the site inspected.
(3) Semi-annually...............  Detects 3 or more leaks  Must inspect at least quarterly.
                                   at the site inspected.
(4) Quarterly...................  Detects no more than 2   Must inspect at least semi-annually.
                                   leaks at the site
                                   inspected.
----------------------------------------------------------------------------------------------------------------

    (b) The BLM may approve an alternative leak detection device, 
program, or method under Sec.  3179.302(a)(2) or 3179.302(a)(3) of this 
subpart, if the BLM finds that the alternative would meet or exceed the 
effectiveness for leak detection of the approach specified in 
Sec. Sec.  3179.302(a)(1) and 3179.303(a) of this subpart. The operator 
must submit its request for an alternative leak detection device, 
program, or method of this section through a Sundry Notice.
    (c) The operator is not required to inspect or monitor a component 
that is not an accessible component.


Sec.  3179.304  Repairing leaks.

    (a) The operator must repair any leak not associated with normal 
equipment operation as soon as practicable, and in no event later than 
15 calendar days after discovery, unless good cause exists for repair 
requiring a longer period.
    (b) If delay in repair beyond 15 calendar days is attributable to 
good cause, the operator must notify the BLM of the cause by Sundry 
Notice and must complete repairs within 15 calendar days after the 
cause of delay ceases to exist.
    (c) Not later than 15 calendar days after completion of a repair, 
the operator must verify the effectiveness of the repair through a 
follow-up inspection using the same method used to detect the leak.
    (d) If the repair is not effective, the operator must complete 
additional repairs within 15 calendar days, and conduct follow-up 
inspections and repairs until the leak is repaired.
    (e) A follow-up inspection to verify the effectiveness of repairs 
does not constitute an inspection for purposes of Sec.  3179.303.


Sec.  3179.305  Leak detection inspection recordkeeping.

    The operator must maintain the following records for the period 
required under Sec.  3162.4-1 of this title and make them available to 
the BLM upon request:
    (a) For each inspection required under Sec.  3179.303 of this 
subpart, documentation of:
    (1) The date of the inspection;
    (2) The site where the inspection was conducted; and
    (3) The equipment or facility inspected;
    (b) The monitoring method(s) used to determine the presence of 
leaks;
    (c) A list of components on which leaks were found and a 
description of each leak;
    (d) The date of first attempt to repair each leak and, if 
necessary, any additional attempt to repair the leak;
    (e) The date each leak was repaired; and
    (f) The date and result of the follow-up inspection(s) required 
under Sec.  3179.304 paragraph (c) or (d) of this subpart.

State or Tribal Variances


Sec.  3179.401  State or tribal requests for variances from the 
requirements of this subpart.

    (a)(1) At the request of a State (for Federal land) or a tribe (for 
Indian lands), the BLM State Director may grant a variance from any 
individual provision of this subpart that would apply to all Federal 
leases, units, or CAs within a State or to all tribal leases, units, or 
CAs within that tribe's lands, or to specific fields or basins within 
the State or that tribe's lands, if the BLM finds that the variance 
would meet the criteria in paragraph (b) of this section.
    (2) A State or tribal variance request must:
    (i) Identify the provision(s) of this subpart from which the State 
or tribe is requesting the variance;
    (ii) Identify the State or tribal regulation(s) or rule(s) that 
would be applied in place of the provision(s) of this subpart;
    (iii) Explain why the variance is needed; and
    (iv) Demonstrate how the State or tribal requirement would satisfy 
the requirement of the particular provision from which the State or 
tribe is requesting the variance.
    (b) The BLM State Director, after considering all relevant factors, 
may approve the request for a variance, or approve it with one or more 
conditions, only if the BLM determines that the State or tribal 
regulation or rule meets or exceeds the requirements of the 
provision(s) from which the State or tribe is requesting the variance, 
and is consistent with the terms of the affected Federal or Indian 
leases and applicable statutes. The decision to grant or deny the 
variance will be in writing and is within the BLM's discretion. The 
decision on a variance request is not subject to administrative appeal 
under 43 CFR part 4.
    (c) A variance from any particular requirement of this rule does 
not constitute a variance from provisions of other regulations, laws, 
or orders.
    (d) The BLM reserves the right to rescind a variance or modify any 
condition of approval.

[FR Doc. 2016-01865 Filed 2-5-16; 8:45 am]
 BILLING CODE 4310-84-P