6616 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

1Office 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. 

2The Energy Information Administration (EIA), 

Trends in U.S. Residential Natural Gas 

Consumption, http://www.eia.gov/pub/oil_gas/ 

natural_gas/feature_articles/2010/ngtren

dsresidcon/ngtrendsresidcon.pdf (reporting that in 

2009, U.S. residential consumption was 

approximately 74 Mcf per household with natural 

gas service). 

DEPARTMENT OF THE INTERIOR 

Bureau of Land Management 

43 CFR Parts 3100, 3160, and 3170 

[15X.LLWO300000.L13100000.NB0000] 

RIN 1004–AE14 

Waste Prevention, Production Subject 

to Royalties, and Resource 

Conservation 

AGENCY: Bureau of Land Management, 

Interior. 

ACTION: Proposed rule. 

SUMMARY: The Bureau of Land 

Management (BLM) is proposing new 

regulations to reduce waste of natural 

gas from venting, flaring, and leaks 

during oil and natural gas production 

activities on onshore Federal and Indian 

leases. The regulations would also 

clarify when produced gas lost through 

venting, flaring, or leaks is subject to 

royalties, and when oil and gas 

production used on site would be 

royalty-free. These proposed regulations 

would be codified at new 43 CFR 

subparts 3178 and 3179. They would 

replace the existing provisions related to 

venting, flaring, and royalty-free use of 

gas contained in the 1979 Notice to 

Lessees and Operators of Onshore 

Federal and Indian Oil and Gas Leases, 

Royalty or Compensation for Oil and 

Gas Lost (NTL–4A), which are over 3 

decades old. 

DATES: Send your comments on this 

proposed rule to the BLM on or before 

April 8, 2016. The BLM is not obligated 

to consider any comments received after 

this date in making its decision on the 

final rule. 

As explained later, the proposed rule 

would establish new information 

collection requirements that must be 

approved by the Office of Management 

and Budget (OMB). If you wish to 

comment on the information collection 

requirements in this proposed rule, 

please note that the OMB is required to 

make a decision concerning the 

collection of information contained in 

this proposed rule between 30 and 60 

days after publication of this document 

in the Federal Register. Therefore, a 

comment to the OMB on the proposed 

information collection requirements is 

best assured of having its full effect if 

the OMB receives it by March 9, 2016. 

ADDRESSES: Mail: U.S. Department of 

the Interior, Director (630), Bureau of 

Land Management, Mail Stop 2134 LM, 

1849 C St. NW., Washington, DC 20240, 

Attention: 1004–AE14. Personal or 

messenger delivery: 20 M Street SE., 

Room 2134LM, Washington, DC 20003. 

Federal eRulemaking Portal: http://

www.regulations.gov. Follow the 

instructions at this Web site. 

Comments on the information 

collection burdens: Fax: Office of 

Management and Budget (OMB), Office 

of Information and Regulatory Affairs, 

Desk Officer for the Department of the 

Interior, fax 202–395–5806. Electronic 

mail: OIRA_Submission@omb.eop.gov. 

Please indicate ‘‘Attention: OMB 

Control Number 1004–XXXX,’’ 

regardless of the method used to submit 

comments on the information collection 

burdens. If you submit comments on the 

information collection burdens, you 

should provide the BLM with a copy, at 

one of the addresses shown earlier in 

this section, so that we can summarize 

all written comments and address them 

in the final rule preamble. 

FOR FURTHER INFORMATION CONTACT: Eric 

Jones at the BLM Moab Field Office, 82 

East Dogwood Ave., Moab, UT 84532, or 

by telephone at 435–259–2117; or 

Timothy Spisak at the BLM Washington 

Office, 20 M Street SE., Room 2134LM, 

Washington, DC 20003, or by telephone 

at 202–912–7311. For questions relating 

to regulatory process issues, contact 

Faith Bremner at 202–912–7441. 

Persons who use a 

telecommunications device for the deaf 

(TDD) may call the Federal Information 

Relay Service (FIRS) at 1–800–877–8339 

to contact these individuals during 

normal business hours. FIRS is available 

24 hours a day, 7 days a week to leave 

a message or question with these 

individuals. You will receive a reply 

during normal business hours. 

SUPPLEMENTARY INFORMATION: 

I. Executive Summary 

A. Background 

This proposed regulation aims to 

reduce the waste of natural gas from 

mineral leases administered by the 

BLM. This gas is lost during oil and gas 

production activities through flaring or 

venting of the gas, and equipment leaks. 

While oil and gas production 

technology has advanced dramatically 

in recent years, the BLM’s requirements 

to minimize waste of gas have not been 

updated in over 30 years. The Mineral 

Leasing Act of 1920 (MLA) requires the 

BLM to ensure that lessees ‘‘use all 

reasonable precautions to prevent waste 

of oil or gas developed in the 

land . . . .’’ 30 U.S.C. 225. The BLM 

believes there are economical, costeffective, 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

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6617 

3See 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. 

4Mineral 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. 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. 

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. 

13Further 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. 

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. 

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

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

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. 

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 nongovernmental 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. 

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6618 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

14EPA, 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. 

15Colorado 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-CCR1001-9_0.pdf. 

16Wyoming, Nonattainment Area Regulations Ch. 

8 (June 2015), available at http://soswy.state.wy.us/ 

Rules/RULES/9868.pdf. 

17North Dakota Industrial Commission Order 

24665 Policy Guidance Version 102215, available at 

https://www.dmr.nd.gov/oilgas/GuidancePolicy

NorthDakotaIndustrialCommissionorder24665.pdf. 

18Pennsylvania 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. 

19EPA Natural Gas STAR Accomplishments, 

available at http://www3.epa.gov/gasstar/

accomplishments/index.html. 

20EPA Natural Gas Star Methane Challenge, 

Program Proposal, available at http:// 

www3.epa.gov/gasstar/methanechallenge/ 

index.html. 

21Maria 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/sixmajor-oil-gas-firms-agree-cut-potent-methaneemissions-ahead-un-climate-change-summit1693517; http://www.gastechnology.org/CH4/ 

Documents/Fiji-George-CH4-presentationSep2014.pdf; One Future: Our Nation’s Energy, 1, 

6 (Sept. 2014), http://www.gastechnology.org/CH4/ 

Documents/Fiji-George-CH4-presentationSep2014.pdf. 

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. 

In addition, several States with BLMadministered 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

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

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 BLMadministered leases. Second, as a 

practical matter, neither the EPA nor 

State regulations adequately address the 

issue of waste of gas from BLMadministered 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6619 

22BLM, 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. 

23RIA at 119–120. 

24RIA 119. 

25RIA at 111 (Appendix A–2). 

26See footnote 2 (assuming 2009 usage levels). 

27RIA at 33. 

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

29See proposed 43 CFR 3179.105. 

30 Ibid. 

31Wyoming 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.). 

and cost savings using a 3 percent 

discount rate).22

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 highbleed 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

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). 

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 microturbines to generate power for use onsite 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 BLMadministered 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6620 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

32RIA 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. 

33RIA at 60. 34RIA at 3. 35Colorado 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. 

36Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission and 

Distribution, 60 CFR subpart OOOO; 80 CFR 56593, 

56660–56698. 

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. 

The BLM proposes to phase in the 

flaring limit over the first 2 years after 

the rule becomes effective, in 

recognition of the fact that some wells 

are flaring at rates considerably higher 

than 1,800 Mcf/month, not all wells will 

be able to use on-site capture 

technologies, and connecting to gas 

pipeline infrastructure may take some 

time. We propose that in the first year 

after the effective date of the rule, the 

flaring limit per well, averaged across 

all of the producing wells on a lease, 

would be 7,200 Mcf/month. In the 

second year, it would be 3,600 Mcf/ 

month. The 1,800 Mcf/month limit 

would apply beginning in the third year 

of the rule. 

The BLM is also proposing that prior 

to drilling a new development oil well, 

an operator would have to evaluate the 

opportunities and prepare a plan to 

minimize waste of associated gas from 

that well, and the operator would need 

to submit this plan along with the 

Application for Permit to Drill or 

Reenter (APD). The BLM proposes to 

require submission of a plan with 

specific content, to ensure that operators 

have carefully considered and planned 

for gas capture prior to drilling. 

In addition to these requirements to 

reduce flaring, the BLM proposes to 

update existing royalty provisions by 

more specifically defining when a loss 

of gas would be considered 

‘‘unavoidable’’ and royalty-free, and 

when it would be considered 

‘‘avoidable’’ and subject to royalties. A 

loss of gas would be deemed 

unavoidable when an operator has 

complied with all applicable 

requirements and taken prudent and 

reasonable steps to avoid waste, and the 

gas is lost from any of the following 

specified operations or sources, subject 

to limits specified in the proposed 

regulations: Emergencies; well drilling, 

well completion and related operations; 

initial production tests and subsequent 

well tests; exploratory coalbed methane 

well dewatering; leaks; venting from 

pneumatic devices in the normal course 

of operation; evaporation from storage 

vessels; and downhole well 

maintenance and liquids unloading. A 

loss of gas would also be deemed 

unavoidable when gas is flared (or, in 

limited circumstances, vented) from a 

well that is not connected to gas capture 

infrastructure, provided the BLM has 

not otherwise determined that the loss 

of gas is avoidable, pursuant to the 

provisions of the 1,800 Mcf/month limit 

in § 3179.6. All losses of gas not 

specifically found to be unavoidable 

would be considered avoidable and 

subject to royalties. Thus, royalties 

would apply to associated gas flared 

from a development well that is already 

connected to capture infrastructure. 

Under these circumstances, operators 

have made an economic choice to flare, 

and that flaring should not be 

considered an unavoidable consequence 

of oil production. 

Currently, there is a backlog of 

requests for approval to flare royaltyfree 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

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

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

The BLM believes that LDAR 

programs are a cost-effective means of 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6621 

37The 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.’’ 

38RIA at 109. 

39RIA at 108–109. 

40RIA at 3. 

41RIA 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). 

43 40 CFR 60.5390. 

44Colorado 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. 

45Wyoming, Nonattainment Area Regulations Ch. 

8, Section 6(e) (June 2015), available at http:// 

soswy.state.wy.us/Rules/RULES/9868.pdf. 

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

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

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 BLMadministered 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

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6622 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

46Regulatory Impact Analysis (RIA) at 78. 

47RIA at 82. 

48RIA at 81. 

49RIA at 3. 

50RIA at 19. 

51Colorado 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. 

52 40 CFR 60.5395; Colorado Air Quality Control 

Commission Regulations, Regulation 7, 5 CCR 

1001–9, Section XVII.C. 

53Wyoming, Nonattainment Area Regulations Ch. 

8, Section 6(c)(i)(a) (June 2015), available at http:// 

soswy.state.wy.us/Rules/RULES/9868.pdf. 

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

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

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

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

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

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) 

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, 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6623 

54RIA at 95. 

55RIA at 3. 

56RIA at 87. 

57RIA at 3. 

58RIA at 18 (Table 6). 

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 BLMadministered 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. 

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

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

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 BLMadministered 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

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 BLMadministered 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6624 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

59RIA at 74. 

60RIA at 74. 

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). 64Note that the proposed rule would renumber 

current 43 CFR 3103.3–1 (a)(2) and (3) but would 

not otherwise change the content of those 

provisions. Further, the proposed rule would not 

alter 43 CFR 3103.3–1(b), (c), or (d). Those five 

provisions are reprinted in this proposed rule solely 

to clarify the proposed numbering of the revised 

§ 3103.3–1, and for ease of reference. The BLM does 

not intend to revise those provisions, nor to invite 

comment on their content. 

65RIA at 127. 

66Some 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. 

67RIA at 127. 

68RIA 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. 

69RIA at 130. 

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

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

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. 

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). 

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

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

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– 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6625 

70RIA at 133–135. 

71RIA at 130. 

72RIA at 133–135. 

73RIA at 7. 

74RIA at 140. 

75RIA at 140. 

76RIA at 143. 

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

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

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

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

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

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). 

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6626 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

77ONRR, 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. 

78Based on an estimate of 74 Mcf of gas used per 

household per year. See footnote 2. 

79RIA at 3. 

80RIA at 111 (Appendix A–2). 

1. Data Sources on Lost Gas 

2. Additional Information on Loss 

Estimates 

I. Examples of and Gaps in Existing WasteReduction 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

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

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6627 

81RIA at 3. 

82The 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). 

83U.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). 

84See 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. 

85The President’s Climate Action Plan, https:// 

www.whitehouse.gov/sites/default/files/image/ 

president27sclimateactionplan.pdf. at 10–11 (June 

2013) 

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. 

related to venting, flaring, and royaltyfree 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

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

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

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. 

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, 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6628 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

87See the BLM oil and gas program’s outreachevents page: http://www.blm.gov/wo/st/en/prog/

energy/public_events_on_oil. 

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

89 Ibid. 

90 Ibid. 

91 Ibid. 

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

93 Ibid. 

94 Ibid. 

95 Ibid. 

96 Ibid. 

97 Ibid. 

98 Ibid. 

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. 

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 NaturalGas Waste 

Venting, flaring, and royalty-free uses 

of oil and natural gas on BLMadministered 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: 

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

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

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

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 lowpressure vessels are considered to be 

unavoidably lost, and not subject to 

royalties, unless the Supervisor 

determines that their recovery is 

warranted.98

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. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6629 

99 Ibid. 

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

101 30 U.S.C. 1756. 

102See footnote 4. 

103See, 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. 

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). 

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

115See 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). 

116 44 FR 76600. 

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

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

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 surfacedisturbing 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

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

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 BLMmanaged 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. 

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 royaltyfree treatment of various uses of lease 

production, and would identify the 

situations in which prior written BLM 

approval would be required for royaltyfree 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6630 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

117 Ibid. 

118 Ibid. at 76,601. 

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. 

120 GAO–11–34, Oct. 2010, 2. 

121 Ibid. at 34. 

122 Ibid. at 27. 

123 Ibid. at 34. 

124 Ibid. at 34. 

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

126 ICF, Onshore Petroleum and Natural Gas 

Operations on Federal and Tribal Lands in the 

United States (June 2015) (SHORT FORM—ICF 

2015). 

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. 

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

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

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. 

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6631 

127 GAO–11–34, Oct. 2010. 

128Using U.S. Census Bureau Total Households 

as of 2013 (latest data available). 

129Based on updated EIA production crossed 

against ONRR Federal production data. 

130For additional detail on these calculations, see 

RIA App. 7. 

131RIA at 19. 

132That is, 22 Bcf vented or leaked (per EPA GHG 

Inventory data), and 76 Bcf flared (per ONRR data). 

133RIA at 3. 

134Based on an estimate of 74 Mcf of gas used 

per household per year. See footnote 2. 

135RIA at 201. 

136 Ibid. 

137BLM data extracted from AFMSS in response 

to media inquiry, October 2014. 

138 ICF 2014 Study. 

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. 

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

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. 

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 BLMadministered leases through venting and 

leaks in 2013. 

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

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. 

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. 

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6632 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

139A. 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 Pe ́tron et al., A new look at methane 

and nonmethane hydrocarbon emissions from oil 

and natural gas operations in the Colorado DenverJulesburg Basin, Journal of Geophysical Research: 

Atmospheres, 6836 (June 3, 2014), http://

onlinelibrary.wiley.com/doi/10.1002/

2013JD021272/pdf. 

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. 146Austin 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. 147Birmur Guven et. al., Analyzing Methane 

Emissions from Upstream Oil and Gas Production 

Operations, (Nov. 2014). 148 Ibid. 149Howard, Touche ́, University of Texas study 

underestimates national methane emissions at 

natural gas production sites due to instrument 

sensor failure, Energy Science & Engineering (Aug. 

4, 2015). 

sources that already exist at the time of 

the final rule. 

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

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6633 

150NASA news release, Oct. 9, 2014 available at 

http://www.nasa.gov/press/2014/october/satellitedata-shows-us-methane-hot-spot-bigger-thanexpected/#.VLbQ0PnF9sE. 

151 Ibid. 

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. 

153Zavala-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. 

156Alaska Administrative Code Title 20—Chapter 

25 235, Gas Disposition, available at http://

doa.alaska.gov/ogc/Regulations/RegIndex.html. 

157 Ibid. 

158Telephone call with BLM staff and State of 

Alaska, Oil and Gas Conservation Commission 

(April 30, 2015). 

159 Ibid. 

160Colorado 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). 

161For further information about EPA’s NSPS 

standards for this source category, see Section IV.I.3 

of this preamble below. 

162Colorado Air Quality Control Commission 

Regulations, Regulation 7, 5 CCR 1001–9, Sections 

XII, XVIII. 

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. 

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

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. 

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

The BLM expects that additional 

studies will use bottom-up and topdown 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

(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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6634 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

168The MOUs are available at http://

cogcc.state.co.us/gov.html#/federal. 

169Administrative 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). 

174North 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/GuidancePolicyNorthDakota

IndustrialCommissionorder24665.pdf. 

175 Ibid. 

176 Ibid. 

177 Ibid. 

178 Ibid. 

179 Ibid. 

180 Ibid. 

181 Ibid. 

182 Ibid. 

183 Ibid. 

184Pennsylvania 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. 

185State 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). 

186Wyoming, 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). 

191See, 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. 

Commission regarding permitting, 

inspection, and enforcement relating to 

oil and gas activities on BLM lands.168

(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

(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

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

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. 

(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

(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

(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

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. 

Many of these efforts have been 

initiated by companies participating in 

Natural Gas STAR, a voluntary EPAindustry 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6635 

192EPA Natural Gas STAR, Accomplishments, 

http://www3.epa.gov/gasstar/accomplishments/

index.html. 

193EPA Natural Gas Star Methane Challenge, 

Program Proposal, http://www3.epa.gov/gasstar/

methanechallenge/index.html. 

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-majoroil-gas-firms-agree-cut-potent-methane-emissionsahead-un-climate-change-summit-1693517; http://

www.gastechnology.org/CH4/Documents/FijiGeorge-CH4-presentation-Sep2014.pdf. 

195Our Nation’s Energy (ONE) Future Coalition, 

http://www.gastechnology.org/CH4/Documents/fijiGeorge-CH4-presentation-Sep2014.pdf. 

196U.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. 

198U.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. 

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. 

205 80 FR 56593, Sept. 18, 2015. 

206 Ibid. 

207 Ibid. 

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

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

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

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 wellcompletion 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. 

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

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

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6636 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

208RIA at 3. 209Based on an estimate of 74 Mcf of gas used 

per household per year. See footnote 2. 210RIA at 203. 211 Ibid. 212 Ibid. 213Pipeline and Gas Journal, Billions Needed to 

Meet Long-Term Natural Gas Infrastructure Supply, 

Demands (April 2009) http://

pipelineandgasjournal.com/billions-needed-meetlong-term-natural-gas-infrastructure-supplydemands?page=4. 

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 BLMregulated activities, such as well 

maintenance and liquids unloading. 

Similarly, of the States with extensive 

oil and gas operations on BLMadministered 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 BLMadministered 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

According to ONRR data, 91 percent 

of flared oil-well gas from BLMadministered leases occurred in three 

States: North Dakota, South Dakota, and 

New Mexico. In 2013, the volumes of 

flared oil-well gas from BLMadministered 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

(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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6637 

214See Carbon Limits (providing detailed 

evaluation of new and emerging gas utilization 

technologies). 

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. 

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 microturbines 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

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 costeffective 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 onsite 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, 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6638 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

215Phone conversation with BLM, Planning and 

Environmental Coordinator, Miles City, MT, 

September 2014. 

216Letter from North Dakota Oil and Gas Division 

to Operators, Re: Gas Capture Plans Required on All 

APD’s (May 8, 2014). 

217 GAO–11–34 (Oct. 2010) at 24. 

218 Ibid. 219 44 FR 76600 (Dec. 27, 1979). 

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 BLMadministered 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

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

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

(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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6639 

220RIA at 33–35. 

221 Data supplied by ONNR. 

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 

§ 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 

§ 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

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. 

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; 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6640 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

222Wyoming 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.). 223NTL–4A, IV.B. 

• 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 

§ 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. 

(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 § 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. 

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 onsite 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6641 

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

225Hereinafter ‘‘Carbon Limits.’’ The study is 

available at http://www.catf.us/resources/

publications/files/Flaring_Report.pdf. 

226 Ibid. at 34. 

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. 

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, acrossthe-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 straightline 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.) 

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 

§ 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6642 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

227Letter 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). 

228Telephone Communication from North Dakota 

Industrial Commission, Department of Mineral 

Resources, Oil and Gas Division to BLM Staff, (May 

13, 2015). 229RIA at 69. 

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

(iv) Estimating or Measuring Quantities 

of Flared or Vented Gas 

Under proposed § 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

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 costeffective; 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6643 

230RIA at 60. 

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

(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 § 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 § 3179.6. In some cases, 

the effectiveness and affordability of onsite 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 § 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 § 3179.101 that gas 

produced during normal well drilling 

operations and then flared would be 

deemed unavoidably lost. Similarly, 

under proposed § 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 § 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6644 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

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 royaltyfree during initial production testing. 

Under proposed § 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 § 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 § 3179.4(b), all losses 

of gas not specifically found to be 

unavoidable would be considered 

avoidable. Proposed § 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 onsite 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6645 

231RIA at 19. 

232Based on an estimate of 74 Mcf of gas used 

per household per year. See footnote 2. 

233Carbon Limits, 16. 

234Carbon Limits, 16. 

235Colorado Air Quality Control Commission 

Regulations, Regulation 7, 5 CCR 1001–9, Section 

XVII.F. 

236Wyoming Operational Rules, Drilling Rules 

Section Ch. 8, Section 6(g), available at http://

soswy.state.wy.us/Rules/RULES/9868.pdf. 

237API, 2014. 

238API, 2014. 

239 40 CFR part 60, App. A–7. 

240 GAO–11–34 (Oct. 2010) at 34. 

241 80 FR 56593, 56634. 

242 Ibid. 

243 Ibid. 

244 Ibid. 

245API, 2014. 

246Carbon Limits, 14, 32. 

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

(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. 

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

(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. 

(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

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. 

(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

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. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6646 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

247See footnote 2. 

248Carbon 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. 

250Briefing from Dr. Bryan Wilson, Program 

Director, Advanced Research Projects Agency— 

Energy on O&G emission projects the agency is 

funding, August 3, 2015. 

251ARPA–E, http://arpa-e.energy.gov/?q=arpa-eprograms/monitor. 

252Briefing from Dr. Bryan Wilson, Program 

Director, Advanced Research Projects Agency— 

Energy on O&G emission projects the agency is 

funding, August 3, 2015. 

253API, June 13, 2014. Re: EPA VOC/Methane 

White Paper on Oil and Natural Gas Sector Leaks. 

Pages 7–9. 

254Phone conversation with Conoco Phillips on 

San Juan Basin operation, February 2015. 

255Phone conversation with Conoco Phillips on 

San Juan Basin operation, February 2015. 

256Phone conversations with Conoco Phillips and 

WPX energy on San Juan Basin operations, 

February 2015. 

257 Ibid. 

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. 

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

(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. 

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 methanesensing 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

(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

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 solarpowered 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

(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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6647 

258 80 FR 56593, 56611–56614. 259Colorado 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). 

260The BLM could provide notice to all operators 

that it had found that a specified new technology 

would satisfy these requirements. 

proposing under §§ 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. 

(i) LDAR Options in the Proposed Rule 

The BLM proposes under § 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. 

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 

§ 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 

§ 3179.303(a). 

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 § 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 

§ 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6648 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

261Colorado Air Quality Control Commission 

Regulations, Regulation 7, 5 CCR 1001–9 at Section 

XVIII.F.3. 

262 Ibid. 

263Wyoming, Nonattainment Area Regulations 

Ch. 8 (June 2015), Section 6(g), available at 

http://soswy.state.wy.us/Rules/RULES/9868.pdf. 

264See 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. 

266Carbon Limits. 

267Note 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). 

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

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

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 semiannual surveys. We request data and 

comment on the data, methodology, and 

analysis used in this study. 

Thus, the BLM is proposing under 

§ 3179.303 to require all operators to 

conduct semi-annual surveys of their 

sites—defined in proposed § 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 twiceyearly inspections. On the other hand, 

if the operator is inspecting semiannually 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 semiannual inspections. 

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 § 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 § 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. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6649 

268U.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. 

269See 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). 

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 thirdparty 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 § 3179.302(a)(3).) 

Another approach would be to limit 

authorization for an alternative leak 

detection program under proposed 

§ 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 oilequivalent 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 oilequivalent 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 lowproducing 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

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. 

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-oilequivalent 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6650 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

270 80 FR 56593, 56635. 

271RIA at 113. 272RIA at 109. 273RIA at 108–109. 

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. 

(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 semiannual 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

In addition, the BLM requests 

comment on simply requiring semiannual 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. 

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6651 

274RIA at 18. 

275 40 CFR 60.5390. 

276 80 FR 56593, 56610. 

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). 

278Colorado 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. 

280Email 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). 

281Wyoming, Nonattainment Area Regulations 

Ch. 8 (June 2015), Section 6(f), available at http:// 

soswy.state.wy.us/Rules/RULES/9868.pdf. 

282U.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. 

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 BLMadministered leases. That volume 

includes releases from chemical 

injection pumps, diaphragm pumps, 

and gas-assist glycol dehydrator pumps. 

(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 § 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

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

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

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

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

A third option for reducing gas losses 

from pneumatic controllers and 

pneumatic pumps is to add a lowpressure collection system that would 

capture the natural gas emitted from 

pneumatic controllers and pneumatic 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6652 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

283Wyoming, Nonattainment Area Regulations 

Ch. 8 (June 2015), Section 6(e), available at http:// 

soswy.state.wy.us/Rules/RULES/9868.pdf. 

284Phone conversation with Conoco Phillips on 

San Juan Basin operation, February 2015. 

285RIA at 78. 

286Wyoming, Nonattainment Area Regulations 

Ch. 8, Section 6(e) (June 2015), available at http:// 

soswy.state.wy.us/Rules/RULES/9868.pdf. 

pumps and either combust it or repressure 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

(c) Proposals To Reduce Waste From 

Pneumatic Controllers and Pneumatic 

Pumps 

The BLM believes that replacing highbleed pneumatic controllers with lowor 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. 

Under proposed § 3179.201, the BLM 

would require operators to replace all 

pneumatic controllers that have bleed 

rates greater than 6 scf/hour with lowbleed 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 § 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 

§ 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

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 

§ 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 § 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 zeroemission 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


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6653 

287RIA at 82. 

288RIA at 81. 

289 40 CFR 60.5395. 

290 Ibid. 

291 Ibid. 

292 40 CFR 60.5395, 60.5415–5416. 

293Colorado Air Quality Control Commission 

Regulations, Regulation 7, 5 CCR 1001–9, Section 

XVII.C. 

294 Ibid. 

295 Ibid. 

296Wyoming Operational Rules, Drilling Rules 

Section Ch. 8, Section 6(d). 

297RIA at 18. 

298 40 CFR part 60 subpart OOOO. 

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

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

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 backpressure—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

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

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

(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. 

(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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6654 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

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

300 Ibid. 

301 40 CFR 60.5395. 

302Colorado Air Quality Control Commission 

Regulations, Regulation 7, 5 CCR 1001–9, Section 

XVII.C. 

303Wyoming Operational Rules, Drilling Rules 

Section Ch. 8, Section 6(d). 

304RIA at 95. 

305 Ibid. 

306RIA at 128–129. 307EPA PowerPoint presentation found at 

http://www3.epa.gov/gasstar/documents/

workshops/fortworth-2006/gremillion.pdf. 308 Ibid. 

includes both flares and combustors) is 

$8,900 per year, assuming that a flare 

device is already in place at the 

facility.299

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 

rule300), 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. 

(c) Proposals To Minimize Vapor Losses 

From Storage Vessels 

Under proposed § 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 

§ 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 

§ 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

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. 

The BLM estimates that the proposed 

requirements would affect about 300 

existing storage vessels on BLMadministered 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

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. 

(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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6655 

309EPA, Natural Gas STAR Program, 2011, 

http://www3.epa.gov/gasstar/documents/ll_

options.pdf. 

310 Ibid. 

311EPA (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. 

313EPA, Natural Gas STAR Program (2011). 

http://www3.epa.gov/gasstar/documents/ll_

options.pdf. 

314 Ibid. 

315Colorado Air Quality Control Commission 

Regulations, Regulation 7, 5 CCR 1001–9, Sections 

XVII. 

316 Ibid. 

317 80 FR 56593, 56614. 

maintain the well even when operators 

are not present. 

Advanced reservoir-energy 

management and optimized liquidsunloading 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

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. 

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

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

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

(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 § 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 

§ 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 

§§ 3179.204(d) and (e) to require that 

operators maintain certain records to 

document liquids unloading events. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6656 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

318RIA at 216. 

319According 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. 

320RIA at 217. Source is Shires & Lev-on analysis 

of API/ANGA survey data. 

321RIA at 85. 

322EPA Natural Gas STAR, Lessons Learned from 

Natural Gas STAR Partners, available at http://

www3.epa.gov/gasstar/documents/ll_

plungerlift.pdf. 

323RIA at 87. 

324RIA at 205. 

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. 

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. 

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. 

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

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

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

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6657 

325 80 FR 56593. 

326RIA at 74. 

327 Ibid. 

328 40 CFR 60.5380–5385. 329 40 CFR 60.5380. 330 40 CFR 60.5385. 

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 BLMadministered 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. 

Proposed § 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 § 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

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

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 costeffective 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. 

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6658 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

331Colorado Air Quality Control Commission 

Regulations, Regulation 7, 5 CCR 1001–9, Sections 

XII.C.1.e, XVII.B.2.d. 

332 40 CFR part 60, subpart OOOO. 

333Colorado 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). 

334See, 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). 

335See Plains Exploration & Production Co., 178 

IBLA 327, 335–336, 341–343 (2010). 

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). 

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. 

well drilling, § 3179.101, and 

completions, § 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

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

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 royaltyfree 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 onsite 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 § 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 royaltyfree 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

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. 

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6659 

340 GAO–08–691 at 6. 

341Agalliu, 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. 

342A ‘‘progressive’’ royalty rate refers to a rate 

that increases with the quantity of the resource 

being sold. 

343PFC 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. 

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. 

346 80 FR 22148 (April 21, 2015). 

347 80 FR at 22151–52 (April 21, 2015). 

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. 

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, profitinvestment 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. 

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. 

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

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

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. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6660 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

348See footnote 64. 349 80 FR at 22151–52 (April 21, 2015). 

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-bysection 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: 

1. Amend § 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. 

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 

§ 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 

§ 3179.101), well completions (proposed 

§ 3179.102), initial production testing 

(proposed § 3179.103), and subsequent 

well testing (proposed § 3179.104). With 

respect to venting and flaring during 

emergencies (proposed § 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6661 

350Colorado Air Quality Control Commission 

Regulations, Regulation 7, 5 CCR 1001–9 at Section 

XVII.H.1.c. and XVII.F.8 for proposed §§ 3179.204 

and 3179.305 respectively. 

351See, e.g., Secretarial Order Nos. 3289 (Sept. 14, 

2009) (updated by Amendment No. 1, Feb. 22, 

2010) and 3226 (Jan. 19, 2001). 

352Letter 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). 

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 § 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 § 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

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 § 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 §§ 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. 

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6662 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

353Letter 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). 

355WELC Jan. 27 Letter, p. 23. 

356WELC 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). 

357WELC Jan. 27 Letter, p. 24. 

358WELC May 30 Letter, pp. 11–12. 

359WELC 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 fieldspecific conditions). 

360WELC Jan. 27 Letter, p. 20. 

361 GAO–11–34, 34. 

362BLM Public Land Statistics, 2014 Table 3–4, 

column (c), Mineral Leasing Act. 

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

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 fieldlevel scale.’’ 358

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

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

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 BLMadministered 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-ofway 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. 

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 BLMmanaged 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 BLMadministered 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 BLMadministered 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6663 

363BLM analysis of EPA GHG Inventory data 

applied against the estimated number of 

compressors located on BLM-managed ROW 

authorizations. 364See footnote 64. 

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. 

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 § 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. § 3103.3–1 Royalty on Production 

The proposed revisions to § 3103.3– 

1(a)(1) and (2) do four things: (1) 

Remove two provisions of the existing 

regulations that are no longer necessary 

(§ 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

2. § 3160.0–5 Definitions 

This proposed amendment to 

§ 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 

§ 3179.4 delineates when the loss of oil 

or gas is avoidable or unavoidable. 

3. § 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) § 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) § 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) § 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 § 3178.5 would qualify the 

general provisions of proposed § 3178.3 

by listing specific operations for which 

prior written BLM approval would be 

required for royalty-free use. 

(d) § 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6664 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

365Plains Exploration & Production Co., 178 

IBLA 327, 341 n.16 (2010). 

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) § 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 § 3178.3, but is 

not specifically identified in proposed 

§ 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) § 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 royaltyfree 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

(g) § 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6665 

366 30 CFR 1202.150(b) (emphasis added). 367 80 FR 40767 (July 13, 2015). 

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 offlease 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 royaltyfree 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. 

(h) § 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 royaltyfree 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

For both oil and gas, the operator 

would have to report the volumes 

measured or estimated, as applicable, 

under ONRR requirements. 

(i) § 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 § 3178.5 or proposed 

§ 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) § 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) § 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) § 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) § 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) § 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6666 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

368Estimation 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. 

369For 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. 

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

comply with the limits of proposed 

§ 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) § 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 royaltyfree. 

(f) § 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 

§ 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) § 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 § 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 

§ 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) § 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 royaltyfree.368

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

This proposed section would also 

require operators to report all volumes 

vented or flared under applicable ONRR 

reporting requirements. 

(i) § 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) § 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 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. 

(k) § 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, nonIndian 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 nonFederal 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 nonIndian mineral interests. 

6. Flaring and Venting Gas During 

Drilling and Production Operations 

(a) § 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 § 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) § 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 refracturing. It would apply the same 

requirements and exceptions for use, 

sale, or disposal as proposed for well 

drilling operations under proposed 

§ 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 § 3179.106 of this 

subpart. 

(c) § 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 

§ 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 timeintensive 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 § 3179.8 

of this subpart. 

(d) § 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 § 3179.8 

of this subpart. 

(e) § 3179.105 Emergencies 

This proposed section would provide 

that an operator may flare or vent 

royalty-free during a temporary, shortterm, 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 § 3179.8 

of this subpart. 

7. Gas Flared or Vented From 

Equipment or During Well Maintenance 

Operations 

(a) § 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6668 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

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 highbleed 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) § 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) § 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) § 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) § 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. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6669 

371The actual number is expected to be slightly 

lower due to duplicate entries. 

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) § 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) § 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) § 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 followup 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 

§ 3179.303. 

(e) § 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) § 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6670 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

372Calendar 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. 

373U.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. 

374U.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. 

375RIA at 81–90. 

376RIA at 127. 

377Some 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. 

378RIA at 127. 

379RIA at 85–90. 

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. 

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. 

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. 

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

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

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 gascapture 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). 

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

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6671 

380RIA at 130. 

381RIA at 133–135. 

382RIA at 130. 

383RIA at 133–135. 

384RIA at 67. 

385RIA at 92–93. 

386RIA at 140. 

387RIA at 140. 

388RIA at 94–95. 

389The BLM conducted an Initial Regulatory 

Flexibility Analysis, RIA at 154–166. 

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

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

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

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

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

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

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

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


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6672 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

390The profit margin was calculated by dividing 

the net income by the total revenue as reported in 

the companies’ 10–K filings. 

391RIA at 148. 

392Executive Order 13563, Improving Regulation 

and Regulatory Review (Jan. 18, 2011). 

393RIA at 148–150. 

394RIA at 148. 

395 Ibid. 

396 Ibid. 

397RIA at 150. 

398RIA at 149. 

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 smallsized entities that currently hold BLMmanaged 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 perentity cost increase figures of $31,400 

and $37,600 which roughly represent 

the middle of the range of potential perentity 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. 

For these 26 small companies, a perentity 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

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. 

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

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

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

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

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

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6673 

399RIA at 167. 

400RIA at 167–168. 

401 5 U.S.C. 601–612. The exception is found in 

5 U.S.C. 605(b). 

402See RIA, section 9. 

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

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

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. 

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. 

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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6674 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

403More info can be found at: http://

www.blm.gov/wo/st/en/prog/energy/public_events_

on_oil.html 

404 44 U.S.C. 3501–3521. 

405 44 U.S.C. 3502(3); 5 CFR 1320.3(c). 

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 BLMadministered 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-togovernment 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. 

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

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 tspisak@

blm.gov 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. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 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 § 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 § 3178.3 

that is not identified in proposed 

§ 3178.4. 

Under proposed § 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 § 3178.9, the 

following information would be 

required in a request for prior approval 

of royalty-free use under § 3178.5, or for 

prior approval of off-lease royalty-free 

use under § 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 § 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 

§ 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: 

Æ The name, number, and location of 

each well, and the number of the lease, 

unit, or CA with which it is associated; 

Æ The depths and names of producing 

formations; 

Æ The gas production level of each of 

the operator’s wells for the most recent 

production month for which 

information is available; and 

Æ The volumes of gas being vented 

and flared from each of the operator’s 

wells; 

• Map(s) showing: 

Æ 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; 

Æ 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; 

Æ 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 

Æ 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 § 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 § 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 straightline 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 § 3179.6. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6676 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

(e) Well Completion and Related 

Operations (43 CFR 3179.102(b)) 

• Proposed § 3179.102(a) would 

require gas that reaches the surface 

during well completion and related 

operations to be: 

Æ Captured and sold; 

Æ 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 § 3179.103(a)(3); 

Æ Used in operations on the lease, 

unit, or CA; or 

Æ 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 § 3179.103 would allow 

gas to be flared royalty-free during a 

well’s initial production testing until: 

Æ The operator determines that it has 

obtained adequate reservoir information 

for the well; 

Æ 30 days have passed since the 

beginning of the production test; 

Æ The operator has flared 20 million 

MMcf of gas; or 

Æ 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 § 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 § 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 § 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 § 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 § 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 § 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 § 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 § 3179.204 would pertain to 

downhole well maintenance and liquids 

unloading operations. Paragraph (e) 

would require an operator to notify the 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 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 §§ 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 § 3179.301(e) would 

allow an operator to satisfy the 

requirements of proposed §§ 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 § 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 § 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

Type of response Number of 

responses 

Hours per 

response 

Total Hours 

(column B × 

column C) 

A. B. C. D. 

Plan to Minimize Waste of Natural Gas, 43 CFR 3162.3–1, Form 3160–3 ............................... 2,000 2 4,000 

Request for Prior Approval for Royalty-Free Uses On-Lease or Off-Lease, 43 CFR 3178.5, 

3178.7, and 3178.9, Form 3160–5 .......................................................................................... 50 8 400 

Request for Approval of Alternative Volume Limits, 43 CFR 3179.7(b), Form 3160–5 ............. 185 16 2,960 

Certification in Support of Exemption from Volume Limits, 43 CFR 3179.7(d), Form 3160–5 .. 15 16 240 

Well Completion and Related Operations, 43 CFR 3179.102(b), Form 3160–5 ........................ 5 2 10 

Initial Production Testing Request for Extension, 43 CFR 3179.103, Form 3160–5 ................. 5 2 10 

Subsequent Well Tests Request for Extension, 43 CFR 3179.104, Form 3160–5 .................... 5 2 10 

Reporting of Emergency Venting and Flaring Beyond Specified Timeframes, 43 CFR 

3179.105, Form 3160–5 ........................................................................................................... 25 2 50 

Pneumatic Controller Report, 43 CFR 3179.201(b) and (c), Form 3160–5 ............................... 200 2 400 

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), Form 3160–5 ................... 100 8 800 

Downhole Well Maintenance and Liquids Unloading—Documentation and Reporting, 43 CFR 

3179.204(a) and (d), Form 3160–5 ......................................................................................... 5,000 1 5,000 

Downhole Well Maintenance and Liquids Unloading—Notification of Excessive Duration or 

Volume, 43 CFR 3179.204(e) ..................................................................................................

Form 3160–5 ............................................................................................................................... 120 1 120 

Leak Detection—Compliance with EPA Regulations, 43 CFR 3179.301(e), Form 3160–5 ....... 500 8 4,000 

Leak Detection—Request to Use and Alternative Device, Program, or Method, 43 CFR 

3179.303(b), Form 3160–5 ...................................................................................................... 200 40 8,000 

Leak Detection—Notification of Delay in Repairing Leaks, 43 CFR 3179.304(a), Form 3160–5 100 1 100 

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

Type of response Number of 

responses 

Hours per 

response 

Total Hours 

(column B × 

column C) 

A. B. C. D. 

Downhole Well Maintenance and Liquids Unloading—Recordkeeping, 43 CFR 3179.204(c) ... 5,000 0.25 1,250 

Leak Detection—Inspection Recordkeeping, 43 CFR 3179.305 ................................................ 52,000 .25 13,000 

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’’ 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6678 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

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

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. 

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 

■ 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. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6679 

1732(b), 1733, and 1740; and the Energy 

Policy Act of 2005 (Pub. L. 109–58). 

■ 2. Revise § 3103.3–1 to read as 

follows: 

§ 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) 121⁄2 percent on all noncompetitive 

leases; and 

(ii) A base rate of not less than 121⁄2

percent on all competitive leases, 

exchange and renewal leases, and leases 

issued in lieu of unpatented oil placer 

mining claims under § 3108.2–4; 

(3) 16 2⁄3 percent on noncompetitive 

leases reinstated under § 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 121⁄2 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 

■ 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. 

§ 3160.0–5 [Amended] 

■ 4. Amend § 3160.0–5 by removing the 

definition of ‘‘Avoidably lost.’’ 

■ 5. Amend § 3162.3–1 by adding 

paragraph (j) to read as follows: 

§ 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 

■ 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. 

■ 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. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6680 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

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 royaltyfree 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. 

§ 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. 

§ 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. 

§ 3178.3 Production on which royalty is 

not due. 

(a) To the extent specified in 

§§ 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 § 3178.5, 

the operator must obtain prior written 

BLM approval for the volumes used for 

operational and production purposes to 

be royalty free. 

§ 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 § 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. 

§ 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 § 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 § 3178.3 that is not 

identified in § 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 § 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 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. 

§ 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 § 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. 

§ 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 § 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 offlease royalty-free use) if the use meets 

one or more of the criteria listed in 

§ 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 § 3178.9. 

(d) Approval of measurement or 

commingling off the lease, unit, or CA 

under other regulations does not 

constitute approval of off-lease royaltyfree 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. 

§ 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. 

§ 3178.9 Requesting approval of royaltyfree treatment when approval is required. 

To request written approval of 

royalty-free use when required under 

§ 3178.5, or of off-lease royalty-free use 

under § 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). 

§ 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 

§ 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. 

§ 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6682 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

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. 

§ 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 §§ 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 gasto-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). 

§ 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 § 3179.103; 

(iv) Subsequent well tests, subject to 

the limitations in § 3179.104; 

(v) Exploratory coalbed methane well 

dewatering; 

(vi) Emergencies, subject to the 

limitations in § 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 § 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. 

§ 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. 

§ 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 

§ 3179.105; 

(3) When § 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 § 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. 

§ 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 § 3179.6, if the 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6683 

operator demonstrates, and the BLM 

agrees, that the applicable limit under 

§ 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 § 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 § 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. 

§ 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. 

§ 3179.9 Determinations regarding royaltyfree 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 

§ 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]. 

§ 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. 

§ 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 

§ 3179.101 Well drilling. 

(a) Except as provided in § 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6684 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

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. 

§ 3179.102 Well completion and related 

operations. 

(a) Except as provided in § 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 

§ 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. 

§ 3179.103 Initial production testing. 

(a) Gas flared during a well’s initial 

production test is royalty-free under 

§§ 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 

§ 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. 

§ 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 §§ 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. 

§ 3179.105 Emergencies. 

(a) An operator may flare or, if flaring 

is not feasible given the emergency, vent 

gas royalty-free under § 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 

§ 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 

§ 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. 

§ 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, 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 6685 

based on the information identified in 

§ 3179.7(b), that installation of a zeroemissions 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. 

§ 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 § 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. 

§ 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 

§ 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) 

§ 3179.301 Operator responsibility. 

(a) The requirements of §§ 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 §§ 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 §§ 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 §§ 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. 

§ 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 

§ 3179.303(b) of this subpart; 

(3) A comprehensive program, 

approved by the BLM under 

§ 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. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
6686 Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules 

§ 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 § 3179.301(b) 

of this subpart. For purposes of 

§§ 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. 

If the operator inspects And in two consecutive inspections the operator The operator 

(1) Semi-annually ........................ Detects no more than 2 leaks at the site inspected ...................... Must inspect at least annually. 

(2) Annually ................................. Detects 3 or more leaks at the site inspected ............................... Must inspect at least semi-annually. 

(3) Semi-annually ........................ Detects 3 or more leaks at the site inspected ............................... Must inspect at least quarterly. 

(4) Quarterly ................................ Detects no more than 2 leaks at the site inspected ...................... Must inspect at least semi-annually. 

(b) The BLM may approve an 

alternative leak detection device, 

program, or method under 

§ 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 §§ 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. 

§ 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 

§ 3179.303. 

§ 3179.305 Leak detection inspection 

recordkeeping. 

The operator must maintain the 

following records for the period 

required under § 3162.4–1 of this title 

and make them available to the BLM 

upon request: 

(a) For each inspection required under 

§ 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 followup inspection(s) required under 

§ 3179.304 paragraph (c) or (d) of this 

subpart. 

State or Tribal Variances 

§ 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 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS