Waste Prevention Rule

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DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3100, 3160 and 3170
[17X.LLWO310000.L13100000.PP0000]
RIN 1004–AE14

Waste Prevention, Production Subject
to Royalties, and Resource
Conservation
Bureau of Land Management,
Interior.
ACTION: Final rule.
AGENCY:

The Bureau of Land
Management (BLM) is promulgating
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 (other than Osage Tribe)
leases. The regulations also clarify when
produced gas lost through venting,
flaring, or leaks is subject to royalties,
and when oil and gas production may
be used royalty-free on-site. These
regulations 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: The final rule is effective on
January 17, 2017.
FOR FURTHER INFORMATION CONTACT:
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 Relay
Service (FRS) at 1–800–877–8339 to
contact these individuals during normal
business hours. FRS 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. Table of Contents

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SUMMARY:

II. Executive Summary
A. Background
B. Summary of Rule
1. Venting and Flaring
2. Leaks
3. Reducing Venting from Equipment and
Practices
4. Royalty Provisions Governing New
Competitive Leases
5. Unavoidable Versus Avoidable Losses of
Gas

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6. Interaction With EPA and State
Regulations
7. Other Provisions
8. Summary of Costs and Benefits
III. Background
A. Impacts of Waste and Loss of Gas
B. Purpose of the Rule
1. Overview
2. Issues Addressed by Rule
3. Relationship to Other Federal, State, and
Industry Activities
C. Legal Authority
D. Stakeholder Outreach
IV. Summary of Final Rule
V. Major Changes From Proposed Rule
A. Venting Prohibition and Capture Targets
1. Venting Prohibition
2. Capture Targets
B. Leak Detection and Repair
1. Requirements of Final Rule
2. Changes From Proposed Rule
3. Significant Comments
C. Liquids Unloading at New Wells
1. Requirements of Final Rule and Changes
From Proposed Rule
2. Significant Comments
D. Variances Related to State and Tribal
Regulations
1. Requirements of Final Rule
2. Changes From Proposed Rule
3. Significant Comments
VI. Additional Significant Comments and
Responses
A. Interaction With EPA Regulations
B. Authority to Require Flaring of Gas
C. ‘‘Avoidably Lost’’ Oil or Gas
D. Application to Units and Communitized
Areas
E. ROW Permitting
F. Planning
VII. Section by Section
Part 3100
Section 3103.3–1 Royalty on production
Section 3160.0–5 Definitions
Section 3162.3–1 Drilling applications
and plans
Subpart 3178—Royalty-Free Use of Lease
Production
Section 3178.1 Purpose
Section 3178.2 Scope of This Subpart
Section 3178.3 Production on Which
Royalty is not due
Section 3178.4 Uses of Oil or Gas on a
Lease, Unit, or Communitized Area That
do not Require Prior Written BLM
Approval for Royalty-Free Treatment of
Volumes Used
Section 3178.5 Uses of Oil or Gas on a
Lease, Unit, or Communitized Area That
Require Prior Written BLM Approval for
Royalty-Free Treatment of Volumes Used
Section 3178.6 Uses of Oil or Gas Moved
off the Lease, Unit, or Communitized
Area That do not Require Prior Written
Approval for Royalty-Free Treatment of
Volumes Used
Section 3178.7 Uses of Oil or Gas Moved
off the Lease, Unit, or Communitized
Area That Require Prior Written
Approval for Royalty-Free Treatment of
Volumes Used
Section 3178.8 Measurement or
Estimation of Volumes of Oil or Gas That
are Used Royalty-Free
Section 3178.9 Requesting Approval of
Royalty-Free Treatment When Approval
is Required

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Section 3178.10 Facility and Equipment
Ownership
Subpart 3179—Waste Prevention and
Resource Conservation
Section 3179.1 Purpose
Section 3179.2 Scope
Section 3179.3 Definitions and Acronyms
Section 3179.4 Determining When the
Loss of Oil or Gas is Avoidable or
Unavoidable
Section 3179.5 When Lost Production is
Subject to Royalty
Section 3179.6 Venting and Flaring From
Gas Wells and Venting Prohibition
Section 3179.7 Gas Capture Requirement
Section 3179.8 Alternative Capture
Requirement
Section 3179.9 Measuring and Reporting
Volumes of Gas Vented and Flared
Section 3179.10 Determinations
Regarding Royalty-Free Flaring
Section 3179.11 Other Waste Prevention
Measures
Section 3179.12 Coordination With State
Regulatory Authority
Section 3179.101 Well Drilling
Section 3179.102 Well Completion and
Related Operations
Section 3179.103 Initial Production
Testing
Section 3179.104 Subsequent Well Tests
Section 3179.105 Emergencies
Section 3179.201 Equipment
Requirements for Pneumatic Controllers
Section 3179.202 Requirements for
Pneumatic Diaphragm Pumps
Section 3179.203 Storage Vessels
Section 3179.204 Downhole Well
Maintenance and Liquids Unloading
Section 3179.301 Operator Responsibility
Section 3179.302 Approved Instruments
and Methods
Section 3179.303 Leak Detection
Inspection Requirements for Natural Gas
Wellhead Equipment and Other
Equipment
Section 3179.304 Repairing Leaks
Section 3179.305 Leak Detection
Inspection, Recordkeeping and Reporting
Section 3179.401 State or Tribal Requests
for Variances From the Requirements of
This Subpart
VIII. Analysis of Impacts
A. Description of the Regulated Entities
1. Potentially Affected Entities
2. Affected Small Entities
B. Impacts of the Requirements
1. Overall Costs of the Rule
2. Overall Benefits of the Rule
3. Net Benefits of the Rule
4. Distributional Impacts
IX. 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

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G. Executive Order 13175, Consultation
and Coordination with Indian Tribal
Governments
H. Paperwork Reduction Act
I. National Environmental Policy Act
J. Executive Order 13211, Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
K. Executive Order 13563, Improving
Regulation and Regulatory Review
X. Authors

II. Executive Summary

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A. Background
This final 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 venting or flaring of
the gas, and through equipment leaks.
While oil and gas production
technology has advanced dramatically
in recent years, the BLM’s rules 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, and that leases include ‘‘a
provision that such rules . . . for the
prevention of undue waste as may be
prescribed by [the] Secretary shall be
observed,’’ id. at § 187. The BLM
believes there are economical, costeffective, and reasonable measures that
operators can take to minimize gas
waste. These measures will enhance our
nation’s natural gas supplies, boost
royalty receipts for American taxpayers,
tribes, and States, reduce environmental
damage from venting, flaring, and leaks
of gas, and ensure the safe and
responsible development of oil and gas
resources.
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 96,000 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)
2015, operators produced 183.4 million
barrels (bbl) of oil, 2.2 trillion cubic feet
(Tcf) of natural gas, and 3.3 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 $20.9 billion and
generated over $2.3 billion in royalties,
which were shared with tribes, Indian

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allottee owners, and States.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 drilling. Yet the American
public has not benefited from the full
potential of this increased production,
due to venting, flaring, and leaks of
significant quantities of gas during the
production process. Federal and Indian
onshore lessees and operators reported
to the Office of Natural Resources
Revenue (ONRR) that they vented or
flared 462 billion cubic feet (Bcf) of
natural gas between 2009 and 2015—
enough gas to serve about 6.2 million
households for a year, assuming 2009
usage levels.2
Venting, flaring, and leaks waste a
valuable resource that could be put to
productive use, and deprive American
taxpayers, tribes, and States of royalty
revenues. In addition, the wasted gas
may harm local communities and
surrounding areas through visual and
noise impacts from flaring, and
contribute to regional and global air
pollution problems of smog, particulate
matter, and toxics (such as benzene, a
carcinogen). Finally, vented or leaked
gas contributes to climate change,
because the primary constituent of
natural gas is methane, an especially
powerful greenhouse gas (GHG), with
climate impacts roughly 25 times those
of carbon dioxide (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.
Congress has directed the BLM to
oversee Federal and Indian oil and gas
activities under multiple laws,
including the MLA, the Mineral Leasing
Act for Acquired Lands of 1947
(MLAAL), the Federal Oil and Gas
1 Office of Natural Resources Revenue, Statistical
Information, http://statistics.onrr.gov/
ReportTool.aspx using Sales Year—FY 2015—
Federal Onshore—All States Sales Value and
Revenue for Oil, Natural Gas Liquids (NGL), and
Gas products as of September 7, 2016.
2 BLM analysis of ONRR Oil and Gas Operations
Report Part B (OGOR–B) data provided for 2009–
2015; see Energy Information Administration (EIA),
Trends in U.S. Residential Natural Gas
Consumption, http://www.eia.gov/pub/oil_gas/
natural_gas/feature_articles/2010/
ngtrendsresidcon/ngtrendsresidcon.pdf (reporting
that in 2009, U.S. residential consumption was
approximately 74 Mcf per household with natural
gas service).
3 See Intergovernmental Panel on Climate Change,
Climate Change 2013: The Physical Science Basis,
Chapter 8, Anthropogenic and Natural Radiative
Forcing, at 714 (Table 8.7), available at https://
www.ipcc.ch/pdf/assessment-report/ar5/wg1/
WG1AR5_Chapter08_FINAL.pdf.

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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 Leases
issued by BLM must ensure that
operations are conducted with
‘‘reasonable diligence, skill, and care’’
and that lessees comply with rules ‘‘for
the prevention of undue waste.’’ 6
Advancing those mandates, this rule
replaces the BLM’s decades-old NTL–
4A requirements related to venting and
flaring, and to royalty-free use of oil and
gas production; amends the BLM’s oil
and gas regulations at 43 CFR part 3160
to include requirements for a waste
minimization plan; and adds new
subparts 3178 and 3179 to 43 CFR part
3170 that address royalty-free use of
lease production (subpart 3178) and
waste prevention through reduction of
venting, flaring and leaks (subpart
3179). This rule will 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.7
This rule implements
recommendations from several oversight
reviews, including reviews by the Office
of the Inspector General of the
Department of the Interior (OIG) and the
Government Accountability Office
(GAO). These reviews raised concerns
about waste of gas from Federal and
Indian production, found that the BLM’s
existing requirements regarding venting
and flaring are insufficient and
outdated, and expressed concerns about
the ‘‘lack of price flexibility in royalty
4 Mineral Leasing Act, 30 U.S.C. 188–287;
Mineral Leasing Act for Acquired Lands, 30 U.S.C.
351–360; Federal Oil and Gas Royalty Management
Act, 30 U.S.C. 1701–1758; Federal Land Policy and
Management Act of 1976, 43 U.S.C. 1701–1785;
Indian Mineral Leasing Act of 1938, 25 U.S.C.
396a–g; Indian Mineral Development Act of 1982,
25 U.S.C. 2101–2108; Act of March 3, 1909, 25
U.S.C. 396.
5 30 U.S.C. 225.
6 30 U.S.C. 187.
7 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 25 CFR part 226.

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rates’’ 8 and about royalty-free use of
gas. The GAO also noted 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.’’ 9 The OIG and GAO
reports recommended that the BLM
update its regulations to require
operators to augment their waste
prevention efforts, afford the BLM
greater flexibility in rate setting, and
clarify BLM policies regarding royaltyfree, on-site use of oil and gas.
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 to
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.10
The BLM continued to consult with
stakeholders throughout the rule
development process, including holding
numerous meetings and calls with State
and tribal representatives, individual
companies, trade associations, and nongovernmental organizations (NGOs).
The BLM conducted additional outreach
with States and tribes where there is
extensive oil and gas production from
BLM-administered leases. We issued a
proposed rule on January 21, 2016,
which was published on February 8,
2016, and accepted public comments
through April 22, 2016, after extending
the comment period. In addition, we
held public meetings during the
comment period in Farmington, New
Mexico; Oklahoma City, Oklahoma;
Denver, Colorado; and Dickinson, North
Dakota. We also held separate meetings
with tribes at each of these locations,
and held further government-togovernment consultation meetings at the
request of several tribes. The BLM
received approximately 330,000 public
comments on the proposed rule,
including approximately 1,000 unique
comments.
The BLM is not the only regulator
with the responsibility to oversee
aspects of onshore oil and gas
production, and throughout this
8 GAO, Oil and Gas Royalties: The Federal System
for Collecting Oil and Gas Revenues Needs
Comprehensive Reassessment, GAO–08–691,
September 2008, 6.
9 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.
10 Further information can be found at the BLM
oil and gas program’s outreach-events page: http://
www.blm.gov/wo/st/en/prog/energy/public_events_
on_oil.html.

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rulemaking the BLM has focused on
potential interactions of this rule with
other Federal, State, or tribal regulatory
requirements. For example, the U.S.
Environmental Protection Agency (EPA)
issued rules in 2012 and early 2016 to
control emissions of methane and
volatile organic compounds (VOCs)
from new, modified and reconstructed
oil and gas wells and production
equipment, and many States and tribes
regulate aspects of the oil and gas
production process to address safety,
waste, production accountability, and/
or air quality concerns. Regulatory
agencies often have overlapping
authority and may adopt very similar
measures to realize those
complementary goals, such as
improving air quality and reducing
waste. For example, measures in this
rule that aim to avoid the waste of
methane gas through venting or leaks
will also reduce methane pollution.
The BLM recognizes that overlapping
regulatory regimes can create difficulties
for operators, and has therefore very
carefully considered and minimized
potential overlaps with other Federal,
State, or tribal regulations. The BLM
aligned the requirements of this new
rule with similar requirements adopted
by the EPA and States, where
practicable, and exempted equipment
complying with relevant EPA
requirements from overlapping
requirements of this rule. In addition,
this rule includes a provision that
authorizes the BLM to grant variances
from particular BLM requirements if a
State or tribe demonstrates that a State,
local, or tribal regulation imposes
equally effective requirements.
It is critical to note, however, that
neither EPA nor State and tribal
requirements obviate the need for this
rule. First, the BLM has an independent
legal responsibility and a proprietary
interest as a land and resource manager
to oversee and minimize waste from oil
and gas production activities conducted
pursuant to Federal and Indian (other
than Osage Tribe) leases, as well as to
ensure that development activities on
Federal and Indian leases are performed
in a safe, responsible, and
environmentally protective matter. The
BLM’s existing venting and flaring
requirements are over 30 years old and
predate significant technological
developments. Updating and clarifying
those requirements 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 carry out its responsibility,
delegated by Congress, to ensure that
the public’s resources are not wasted

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and are developed in a manner that
provides for long-term productivity and
sustainability.
Second, as a practical matter, neither
EPA nor State and tribal regulations
fully address the issue of waste of gas
from BLM-administered leases. The EPA
regulations are directed at air pollution
reduction, not waste prevention; they
cover only new, modified and
reconstructed sources; and they do not
address wasteful routine flaring of
associated gas from oil wells, among
other things. Similarly, no State or tribe
has established a comprehensive set of
requirements addressing all three
avenues for waste—venting, flaring, and
leaks—and only a few States have
significant requirements in even one of
these areas. The BLM therefore believes
this rule is a necessary step in fulfilling
its statutory mandate to minimize waste
of the public’s and tribes’ natural gas
resources.
B. Summary of Rule
This rule requires operators to take
various actions to reduce waste of gas,
establishes clear criteria for when flared
gas will qualify as waste and therefore
be subject to royalties, and clarifies
which on-site uses of gas are exempt
from royalties. The rule focuses on
several key points or processes in the oil
and gas production process where
waste-prevention actions are most
effective and least costly: Venting and
flaring of associated gas from
development oil wells (routine flaring
occurs at oil wells that dispose of gas as
a waste product), gas leaks from
equipment at the well site or elsewhere
on the lease, operation of high-bleed
pneumatic controllers and certain
pneumatic pumps, gas emissions from
storage vessels, downhole well
maintenance and liquids unloading, and
well drilling and completions. The
following discussion summarizes the
rule’s requirements applicable to each of
these aspects of the production process,
and also outlines the rule’s provisions
with respect to royalties, and the
interaction between the rule and related
EPA and State or tribal regulations.
1. Venting and Flaring
In 2014, operators vented about 30 Bcf
and flared at least 81 Bcf of natural gas
from BLM-administered leases, totaling
4.1 percent of the total production from
those leases in that year, and sufficient
gas to supply nearly 1.5 million
households with gas for a year.11 In
11 RIA at 16; see Energy Information
Administration (EIA), Trends in U.S. Residential
Natural Gas Consumption, http://www.eia.gov/pub/
oil_gas/natural_gas/feature_articles/2010/
ngtrendsresidcon/ngtrendsresidcon.pdf (reporting

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2015 operators flared at least 85 Bcf, a
114 percent increase from 2009 levels.12
Roughly 83 Bcf of this flaring came from
oil wells.13 Analysis of data supplied by
the ONRR suggests that most of the
flaring was routine flaring of associated
gas from development oil wells (as
opposed to flaring during exploration,
well testing, and emergencies). Over 88
percent of this flaring occurred in North
Dakota, South Dakota, and New Mexico.
This rule prohibits venting of natural
gas, except under certain specified
conditions, such as in an emergency or
when flaring is technically infeasible.14
With respect to flaring, the rule requires
operators to reduce wasteful flaring of
gas by capturing for sale or using on the
lease a percentage of their gas
production. The required capture
percentage increases over time, and is
also adjusted to provide for a base level
of ‘‘allowable’’ flaring that ramps down
over time. This capture requirement
builds on the proposed rule’s flaring
limits, and modifies that approach in
response to comments, to make
compliance more feasible and less
costly, while working towards phasing
out routine flaring of associated gas
from oil wells by increasing capture.
Specifically, beginning one year from
the effective date of the final rule,
operators must capture 85 percent of
their adjusted total volume of gas
produced each month. This percentage
increases to 90 percent in 2020, 95
percent in 2023, and 98 percent in 2026.
An operator’s adjusted total volume of
gas produced is calculated based on the
quantity of high pressure gas produced
from the operator’s development oil
wells that are in production, adjusted to
exempt a specified volume of gas per
well, which declines over time.
Beginning one year from the effective
date of the final rule, operators are
allowed to exempt 5,400 Mcf gas per
well per month, and this quantity
declines to 3,600 beginning in 2019,
1,800 in 2020, 1,500 in 2021, 1,200 in
2022, 900 in 2024, and 750 from 2025
on.
The final rule gives operators the
option to meet their capture targets on
a lease-by-lease basis, or an average
basis over all of their Federal or Indian
production from development oil wells
county-by-county or State-by-State.
Giving operators the ability to average
their rates of gas capture over
that in 2009, U.S. residential consumption was
approximately 74 Mcf per household with natural
gas service).
12 BLM analysis of ONRR OGOR–B data provided
for 2009–2015 and EPA GHG Inventory data for
2014.
13 RIA at 49.
14 See 43 CFR 3179.6.

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geographic areas beyond individual
leases enhances flexibility and makes
the targets less costly to meet. Similarly,
the more extended phasing in of the
capture targets eases costs and
compliance burdens, while allowing
appropriate planning and investment by
industry to meet more stringent targets
in out years. At the same time, the BLM
recognizes that it has a statutory
responsibility to ensure that operators
minimize waste of public resources.
Accordingly, the BLM has structured
the capture targets to ensure that
operators will achieve overall
reductions in wasteful flaring that are
comparable to, and eventually slightly
greater than, what the BLM estimated
would have been achieved under the
proposed rule.
The BLM estimates that, once fully
implemented, the capture targets will
reduce flaring by up to 49 percent
relative to 2015 levels. Like the
proposed rule, the final rule also retains
the BLM’s discretion to craft alternative
requirements for certain operators that
cannot meet the baseline flaring
reduction obligations. Specifically, the
final rule allows the BLM to adjust the
capture target for an operator on an
existing lease that demonstrates to the
BLM that meeting the target would
impose such costs as to cause the
operator to cease production and
abandon significant recoverable oil
reserves under the lease. In assessing
the operator’s showing, the BLM will
consider the costs of gas capture, and
the costs and revenues of all oil and gas
production on the lease.
As explained in the proposed rule, the
initial flaring limitations were intended
to motivate operators to increase their
capture of gas associated with oil
development, since a reduction in
flaring is achieved most effectively by
an increase in capture. Consequently,
flaring limitations and capture
requirements are two sides of the same
coin. Increasing capture is the BLM’s
primary goal in imposing these waste
prevention requirements, and we
concluded that it would be a more
direct means of achieving that goal to
require capture rather than merely
encourage it through the imposition of
flaring limits. In modifying the rule in
this way, we have determined that both
approaches are expected to achieve
comparable results, in terms of both
increasing capture and reducing
wasteful flaring.
In addition, this rule finalizes the
proposal to require operators to submit
a Waste Minimization Plan when they
apply for a permit to drill a new
development oil well. Preparation of a
Waste Minimization Plan ensures that

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the operator carefully considers and
plans for how it will capture the gas that
will be produced, before the operator
drills a well. While the provisions of a
plan will not be enforceable against the
operator, plan submission is mandatory,
and the plan must include specific
elements listed in the regulations. As in
the proposed rule, failure to submit a
complete and adequate plan could be
grounds for denial of an application for
permit to drill (APD).
2. Leaks
Based on our estimates, leaks are the
second largest source of vented gas from
Federal and Indian leases, accounting
for about 4 Bcf of the natural gas lost in
2014.15 Our analysis indicates that Leak
Detection and Repair (LDAR) programs
are a cost-effective means of reducing
waste in oil and gas production, and
multiple studies have found that once
leaks are detected, the vast majority can
be repaired with a positive return to the
operator.16
Like the proposed rule, the final rule
requires operators to use an instrumentbased approach to leak detection. The
final rule allows operators to use optical
gas imaging equipment, portable
analyzers deployed according to the
protocol prescribed in EPA’s Method
21,17 or an alternative leak detection
device approved by the BLM. In
response to comments on the proposed
rule, the final rule was revised to be
consistent with the EPA’s final
requirements under 40 CFR part 60
subpart OOOOa, requiring operators to
conduct semi-annual inspections at well
sites and quarterly inspections at
compressor stations. Operators may also
request BLM approval of an alternative
instrument-based leak detection
program; the BLM may approve such a
program if it finds that the program
would reduce leaked volumes by at least
as much as the BLM program. Operators
must repair a leak within 30 days of
discovery, absent good cause, and verify
that the leak is fixed. Operators must
also keep records documenting the dates
and results of leak inspections, repairs,
and follow-up inspections.
3. Reducing Venting From Equipment
and Practices
Like the proposed rule, the final rule
includes requirements to update old,
inefficient equipment and to follow best
practices to minimize waste through
venting. These provisions address gas
losses from pneumatic controllers and
pumps, storage vessels, liquids
15 RIA

at 3.
at 27.
17 See 40 CFR part 60, appendix A–7.
16 RIA

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unloading, and well drilling and
completions.
a. Pneumatic Controllers and Pumps

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We estimate that on BLMadministered leases in 2014, operators
lost about 14.9 Bcf of natural gas from
pneumatic controllers and about 2.3 Bcf
from pneumatic pumps.18 A recent
study by the consulting firm ICF
International (ICF) identified
replacement of high-bleed pneumatic
controllers (those with bleed rates
higher than 6 standard cubic feet (scf)/
hour) with low-bleed pneumatic
controllers (those with bleed rates of 6
scf/hour or less) as one of the most
inexpensive options for reducing
methane losses, estimating that
replacing these devices would actually
save industry $2.65 per Mcf of avoided
methane emissions.19 Like the proposed
rule, the final rule requires operators to
replace high-bleed pneumatic
controllers with low-bleed or no-bleed
pneumatic controllers within one year
of the effective date of the final rule.
This requirement tracks existing
requirements in Colorado and Wyoming
(in part of the State), and it applies only
to pneumatic controllers that are not
covered by EPA regulations.
For pneumatic pumps, the final rule
requires the operator to replace
pneumatic diaphragm pumps that
operate 90 or more days per year with
zero-emissions pumps, or route the
pump exhaust gas to processing
equipment. If use of a pneumatic pump
is required based on the function the
pump must serve, and the operator
determines that routing the exhaust gas
to processing equipment would be
technically infeasible or unduly costly,
the operator must route the pneumatic
diaphragm pump to a combustor or
flare, if one is located on the site.
The BLM modified the requirements
in the proposed rule for pneumatic
pumps in response to comments and to
better align with the EPA’s final subpart
OOOOa requirements. For example, the
BLM eliminated the proposed
requirements for chemical injection
pumps and diaphragm injection pumps
that operate relatively infrequently, as
we believe that these pumps vent
relatively small quantities of gas. Like
the proposed rule, the final rule does
at 4.
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).

not apply to pneumatic pumps that are
subject to EPA regulations.
The final rule provides that an
operator can receive an exemption from
the requirements for pneumatic
controllers or pumps 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 will consider
the costs of capture, and the costs and
revenues of all oil and gas production
on the lease.
b. Storage Vessels
We estimate that 2.94 Bcf of natural
gas was lost in 2014 from storage tank
venting on Federal and Indian lands.20
Of that volume, we estimate that 1.54
Bcf was lost from storage vessels used
in natural gas production and 1.4 Bcf of
gas was lost from storage vessels used in
oil production.21 Tank vapors can be
controlled by installing a vapor recovery
unit (VRU) or by routing them to a flare
or combustor. New, modified and
reconstructed 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 tons
per year (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.22
Like the proposed rule, this final rule
includes requirements to reduce gas
losses from existing storage vessels,
which are not covered by the EPA
standards. Using the same applicability
threshold as EPA and Colorado (6 tpy of
VOCs, which the BLM is using as a
proxy for natural gas losses since the
VOCs in this context are coming from
the natural gas from storage vessels), the
rule requires operators to route storage
vessel vapor gas to a sales line, if the
storage vessel has the potential to emit
at least 6 tpy of VOCs. If an operator
determines that compliance with this
requirement is technically infeasible or
unduly costly, the operator may instead
route the tank vapor gas to a combustor
or flare. Like the proposed rule, this
final rule allows operators to request an
exemption from these requirements if

18 RIA
19 ICF

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20 RIA

at 17.
at 17.
22 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Sections
XII.D–F; XVII.C; Wyoming, Nonattainment Area
Regulations Ch. 8, Section 6(c) (June 2015),
available at http://soswy.state.wy.us/Rules/RULES/
9868.pdf.
21 RIA

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the operator demonstrates, and the BLM
concurs, that complying with the
requirements 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
will consider the costs of compliance,
and the costs and revenues of all oil and
gas production on the lease.
c. Well Maintenance and Liquids
Unloading
We estimate that 3.26 Bcf of natural
gas was lost in 2014 during liquids
unloading operations on Federal and
Indian lands.23 There are a wide variety
of methods for liquids unloading, and
technological developments, such as
automated well controls and plunger lift
systems, now allow liquids to be
unloaded with minimal loss of gas. The
BLM expects prudent operators to use
available technologies and practices to
minimize gas losses, and we believe that
the failure to use such technologies and
practices during liquids unloading
constitutes waste.
The final rule does not adopt the
provision from the proposed rule that
would have prohibited manual well
purging from new wells, due to
concerns about the technical feasibility
of such a ban. Instead, the final rule
requires an operator to: (1) Minimize gas
vented to unload liquids, consistent
with safe operations; (2) optimize the
operation of the plunger lift or
automated well control system, at wells
equipped with such a system, to
minimize gas losses from the system to
the extent possible; (3) consider other
methods for liquids unloading and
determine that they are technically
infeasible or unduly costly, prior to
manually purging a well for the first
time; and (4) comply with specified
procedures and document venting
events when unloading liquids by
manual well purging.
d. Reduction of Waste From Drilling,
Completion, and Related Operations
We estimate that in 2014, 1.12 Bcf of
natural gas was lost during drilling,
completion, and refracturing (sometimes
referred to by the broader term
‘‘workover’’) operations on BLMadministered leases.24 The EPA requires
new hydraulically fractured and
refractured oil or gas wells to capture or
flare gas that otherwise would be
released during drilling and completion
operations. The BLM final rule also
includes provisions to minimize the
waste of gas during these operations by
23 RIA
24 RIA

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requiring operators to capture, use, flare,
or inject the gas. While we do not expect
that these provisions will obligate
operators to take any additional actions
beyond what they must do to comply
with the EPA requirements, we believe
it is appropriate for the BLM to adopt its
own provisions governing operator
conduct, to fulfill its independent
statutory obligation to minimize waste
of oil and gas resources on BLMadministered leases.

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4. Royalty Provisions Governing New
Competitive Leases
The final rule revises 43 CFR 3103.3–
1, which governs royalty rates
applicable to onshore oil and gas leases,
to make the rule text parallel to the
BLM’s statutory authority, which
specifies that competitively-issued
BLM-administered leases ‘‘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.’’ 30 U.S.C. 226(b)(1)(A). The final
version of 43 CFR 3103.3–1 thus makes
clear that for competitive leases issued
after the effective date of this rule, the
BLM has the flexibility to set rates at or
above 12.5 percent. This change
finalizes this provision as it was
proposed, and responds to findings and
recommendations in audits from the
GAO. The final rule does not, however,
set a new rate for competitively-issued
leases.
Like the proposed rule, the final rule
specifies the fixed, statutory rate of 12.5
percent for all noncompetitive leases
issued after the effective date of the rule,
as required by statute.25 In addition, the
final rule makes clear that the royalty
rate on all existing leases remains the
rate prescribed in the lease or in
regulations applicable at the time of
lease issuance.
5. Unavoidable Versus Avoidable Losses
of Gas
Like the proposed rule, the final rule
also updates the pre-existing royalty
provisions in NTL–4A to more clearly
and specifically define when a loss of
gas is considered ‘‘unavoidable’’ and
royalty-free, and when it is considered
‘‘avoidable’’ and subject to royalties. A
loss of gas is 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 one of the
operations or sources specified in this
final regulation, subject to certain
limitations. The specified operations
and sources include emergencies; well
25 30

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

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drilling, completions, and tests; normal
operations of pneumatic devices and
storage vessels; liquids unloading; leaks;
equipment or pipeline maintenance
requiring depressurization; and residual
gas after stripping of natural gas liquids.
A loss of gas is also deemed
unavoidable when gas is flared from a
well that is not connected to a gas
pipeline, provided the BLM has not
otherwise determined that the loss of
gas is avoidable. All other losses of gas,
as well as any gas flared in violation of
the capture requirement (regardless of
whether the well is connected to a
pipeline), are deemed avoidable and
subject to royalties. By establishing
clear-cut categories for unavoidable and
avoidable losses, the final rule will
dramatically reduce the large number of
requests for approval to flare royaltyfree that operators have had to file and
the BLM has had to process each year.
6. Interaction With EPA and State
Regulations
Like the proposed rule, this final rule
seeks to minimize regulatory overlap.
Thus, if EPA and/or States or tribes have
adopted requirements that are at least as
effective as and would potentially
overlap with the provisions of this rule,
the final rule provides a means for
operators to comply with the EPA, State,
local or tribal requirements in lieu of the
BLM requirements. Specifically, in
cases in which EPA rules limit venting
from equipment or require leak
inspections and repairs, those operators
that are in compliance with those EPA
requirements are deemed, under this
rule, to be in compliance with the
comparable BLM requirements. With
respect to State, local, or tribal rules, the
final rule allows a State or tribe to
request a variance from a particular
BLM regulation. If the variance is
granted, the BLM has the authority to
enforce the specific provisions of the
State, local, or tribal rule for which the
variance was granted, in lieu of the
comparable provisions of the BLM rule.
As clarified in the final rule, the BLM
may grant a State or tribal variance
request only if the BLM determines that
the State, local, or tribal rule would
perform at least as well as the BLM
provision to which the variance would
apply, in terms of reducing waste of oil
and gas, reducing environmental
impacts from venting and/or flaring of
gas, and ensuring the safe and
responsible production of oil and gas.
7. Other Provisions
Like the proposed rule, the final rule
includes provisions that update and
clarify pre-existing BLM requirements
regarding when operators may use oil or

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83013

gas from a lease for production activities
without owing royalties on the oil or gas
used. In addition, like the proposed
rule, the final rule includes provisions
specifying when operators must
measure the volumes of gas vented or
flared, and requiring operators to report
to ONRR volumes of gas vented or
flared.
8. Summary of Costs and Benefits
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 $46 million to $199
million per year (annualizing capital
costs using a 7 percent discount rate) or
from $50 million to $204 million per
year (annualizing capital costs using a 3
percent discount rate).26
a. Costs
The BLM estimates that this rule will
pose costs ranging from $114–$279
million per year (using a 7 percent
discount rate to annualize capital costs)
or $110–$275 million per year (using a
3 percent discount rate to annualize
capital costs) over the next 10 years.27
These costs 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 rule.28 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).
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 final 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 Regulatory Impact
Analysis (RIA), we estimate that average
costs for a representative small operator
would increase by about $55,200, which
would result in an average reduction in
26 BLM, Economic Impact and Regulatory
Threshold Analysis for 43 CFR 3178 (Royalty Free
Use of Production) and 43 CFR 3179 (Venting and
Flaring Requirements) (2015) (hereinafter RIA) at 6.
27 RIA at 4.
28 Some gas that would have otherwise been
vented would now be combusted on-site or
presumably downstream to generate electricity. As
described in the RIA, the estimated value of these
carbon additions would not exceed $30,000 in any
given year.

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profit margin of 0.15percentage
points.29
b. 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 BLM
estimates that this rule would result in
monetized benefits of $209–$403
million per year (using model averages
of the social cost of methane with a 3
percent discount rate).30 We estimate
that the final rule would reduce
methane emissions by 175,000–180,000
tpy, roughly a 35% reduction in
methane emissions from the 2014
estimates, and which we estimate to be
worth $189–$247 million per year (this
social benefit is included in the
monetized benefit above).31
Adoption of the final 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
nitrogen oxides (NOx) and particulate
matter, which can cause respiratory and
heart problems.
c. Net Benefits

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Overall, the BLM estimates that the
benefits of this rule outweigh its costs
by a significant margin. The BLM
expects net benefits ranging from $46–
$199 million per year (using a 7 percent
discount rate to annualize capital costs)
or $50–$204 million per year (using a 3
percent discount rate to annualize
capital costs). Specifically, assuming a 7
percent discount rate to annualize
capital costs, we estimate the following
annual net benefits in selected years:
• $99–$115 million in 2018;
• $51–$93 million in 2022; and
• $120–$189 million in 2026.
Assuming a 3 percent discount rate to
annualize capital costs, we estimate the
annual net benefits would be:
• $103–$119 million in 2018;
• $55–$97 million in 2022; and
• $125–$193 million in 2026.32
29 RIA at 129. These estimates rely on 2014
company data, and use a 7 percent discount rate.
30 RIA at 5.
31 RIA at 110. We also estimate that the final rule
would have an incidental benefit of reducing VOC
emissions by 250,000–267,000 tpy (this benefit is
not monetized in our calculations).
32 RIA at 111.

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d. Influence on Production
The final 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.
We estimate the following incremental
changes in production, noting the
representative share of the total U.S.
production in 2015 for context. We
estimate additional natural gas
production, ranging from 9–41 Bcf per
year (representing 0.03–0.15 percent of
the total U.S. production), and a
reduction in crude oil production
ranging from 0.0–3.2 million bbl per
year (representing 0–0.07 percent of the
total U.S. production). We also expect
0.8 Bcf of gas to be combusted on-site
that would have otherwise been vented.
Combined, the rule will reduce venting
by about 35 and reduce flaring by 49%,
depending on the year.33
Since the relative changes in
production are expected to be small, we
do not expect that the final rule will
significantly impact the price, supply,
or distribution of energy.
e. Royalties
We estimate that this final rule will
produce additional royalties of $3–$10
million per year (discounted at 7
percent) or $3–$14 million per year
(discounted at 3 percent).34
III. Background
The BLM’s onshore oil and gas
management program is a major
contributor to the 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 96,000 Federal onshore oil
and gas wells accounts for 11 percent of
the Nation’s natural gas supply and 5
percent of its oil supply. In FY 2015, the
ONRR reported that operators produced
183.4 million bbl of oil, 2.6 Tcf of
natural gas, and 3.3 billion gallons of
NGLs from onshore Federal and Indian
oil and gas leases. The production value
of this oil and gas exceeded $20.9
billion and generated over $2.3 billion
in royalties.35
Over the past decade, the United
States has experienced a dramatic
increase in oil and natural gas
production due to technological
33 RIA

at 5.
34 RIA at 143.
35 Office of Natural Resources Revenue, Statistical
Information, http://statistics.onrr.gov/
ReportTool.aspx using Sales Year–FY 2015–Federal
Onshore–All States Sales Value and Revenue for
Oil, NGL, and Gas products as of September 21,
2016.

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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 in
certain regions of the country, 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 the increase in oil production has
been accompanied by significant and
growing quantities of wasted natural
gas. Between 2009 and 2015, operators
on BLM-administered leases wasted
enough natural gas to serve over 6.2
million homes for 1 year, according to
data reported to ONRR.36
A. Impacts of Waste and Loss of Gas
As explained in the proposed rule
preamble section IV.B, natural gas is a
limited and valuable public resource,
which is critical to U.S. energy security
and national security. Natural gas also
provides significant economic benefits
as an energy source for electricity
generation and industrial and
residential use, and as a feedstock for
manufacturing. Royalty payments on
natural gas sales provide Federal, State,
and tribal governments with over $3
billion in revenues each year.
Venting, flaring, and leaks of natural
gas from production on BLMadministered sites waste this limited
natural resource and deprive the
American public and tribes of the
security and economic benefits that this
resource, which belongs to the public
and tribes, would otherwise provide. In
addition to the economic and security
losses, the waste of natural gas also
imposes public health and
environmental costs, in the form of air
pollution, such as smog and regional
haze; emissions of hazardous air
pollutants, some of which are
carcinogenic; and emissions of methane,
a powerful contributor to global
warming and a primary target for
reduction under the President’s Climate
Action Plan.37 Absent stronger
provisions to reduce natural gas waste
on Federal lands, the avoidable loss of
gas will continue to threaten climate
36 Office of Natural Resources Revenue, Statistical
Information, http://statistics.onrr.gov/
ReportTool.aspx using Sales Year–FY 2015–Federal
Onshore—All States Sales Value and Revenue for
Oil, NGL, and Gas products as of September 7,
2016.
37 The President’s Climate Action Plan (June
2013) (https://www.whitehouse.gov/sites/default/
files/image/president27sclimateactionplan.pdf).

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stability and undermine respiratory and
cardiovascular health.
B. Purpose of the Rule
1. Overview
The purpose of this rule is to reduce
waste of natural gas owned by the
American public and tribes, which
occurs during the oil and gas production
process. While the BLM already
regulates venting and flaring of natural
gas during oil and gas production on
Federal and Indian (other than Osage
Tribe) leases, the current requirements
are over 30 years old and do not reflect
modern technologies, practices, and
understanding of the harms caused by
venting, flaring, and leaks of gas.
Oversight reviews have also suggested
that the current requirements are
insufficiently clear in their directives,
which complicates implementation for
BLM staff and creates uncertainty for oil
and gas operators. Today’s rule updates
the existing provisions to direct
operators to take reasonable and
common-sense measures to prohibit
routine venting, minimize the quantities
of natural gas routinely flared, reduce
natural gas losses through leaks, and
deploy up-to-date technology to reduce
routine losses from production
equipment.
2. Issues Addressed by Rule

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a. Large Quantities of Natural Gas Are
Wasted on Federal and Indian Leases
As explained in the proposed rule
preamble section IV.H.1, while there is
some uncertainty regarding the total
volume of natural gas lost during
production on public and tribal lands,
the volume is unacceptably high.
There is no single definitive source
for the total volume of natural gas losses
from oil and gas production on Federal
Lands. BLM efforts to estimate the total
volume are informed by the Oil and Gas
Operations Report Part B (OGOR–B)
filed with the ONRR, the EPA
Greenhouse Gas Inventory,38 data from
the EPA Greenhouse Gas Reporting
Program,39 and numerous studies
discussed in the preamble to the
proposed rule and provided by
commenters. Each data set, however,
has limitations. The ONRR data rely on
self-reporting, and there is substantial
variation in the types of losses that
different operators report (and certain
38 U.S. EPA, (U.S. Greenhouse Gas Inventory
Report: 1990–2014), available at https://
www.epa.gov/sites/production/files/2016-04/
documents/us-ghg-inventory-2016-main-text.pdf
(‘‘2016 GHG Inventory’’).
39 U.S. EPA, Greenhouse Gas Reporting Program;
Petroleum and Natural Gas Systems. Available at
https://www.epa.gov/ghgreporting/ghgrppetroleum-and-natural-gas-systems.

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types of losses, such as most leaks, are
not reported at all). The EPA data are
based on emissions factors that are
representative rather than actual.40 Even
though data in these programs have
recently been updated, they are still
incomplete, and recent studies suggest
actual emissions may be somewhat, or
even substantially, higher than the
emissions factors suggest.41 Thus, we
believe that the estimates of losses used
to support today’s rule, while
substantial, are conservative. For
purposes of this final rule, ONRR
provided the BLM with data evidencing
7 years of vented and flared volumes
reported on the OGOR-Bs. The data
analyzed included gas flared and vented
from both oil and gas wells from 2009
through 2015. During this period,
operators reported that they vented or
flared a total of 462 Bcf of natural gas,
or about 2.7 percent of the 16.8 Tcf of
natural gas that was produced from
BLM-administered leases from 2009
through 2015.42 This is enough natural
gas to supply over 6.2 million
households—or every household in the
States of Colorado, Montana, New
Mexico, North Dakota, South Dakota,
Utah, and Wyoming—for 1 year.43
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 percent came from wells
extracting only Federal minerals; 8.8
percent came from wells extracting only
Indian minerals, and 76.2 percent from
wells extracting minerals with mixed
ownership (some combination of
Federal, Indian, fee (private) and State
minerals).
Finally, the BLM notes that available
data suggest the problem of natural gas
loss on BLM-administered leases is
growing. The total amounts of annual
reported flaring from Federal and Indian
leases increased by over 1000 percent
from 2009 through 2015.44 During this
period, reported volumes of flared oilwell gas increased by 318 percent, while
reported volumes of flared gas-well gas
40 EPA, 2016 GHG Inventory Report: 1990–2014.
Available at https://www3.epa.gov/climatechange/
Downloads/ghgemissions/US-GHG-Inventory-2016Main-Text.pdf.
41 Envt’l Def. Fund, New EPA Stats Confirm: Oil
& Gas Methane Emissions Far Exceed Prior
Estimates (Apr. 15, 2016), https://www.edf.org/
media/new-epa-stats-confirm-oilgas-methaneemissions-far-exceed-prior-estimates.
42 BLM analysis of ONRR OGOR–B data provided
for 2009–2015.
43 Using U.S. Energy Information Administration
Natural Gas Consumption by End Use for 2015
found at http://www.eia.gov/dnav/ng/ng_cons_
sum_a_EPG0_vrs_mmcf_a.htm.
44 BLM analysis of ONRR OGOR–B data provided
for 2009–2015.

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decreased by 86 percent.45 The
reduction in flaring at gas wells
coincides with the adoption of EPA 40
CFR part 60 subpart OOOO (‘‘subpart
OOOO’’) air pollution requirements,
which limit emissions from gas wells
hydraulically fractured after August 23,
2011.46
Another indicator of the increase of
flaring on Federal and Indian lands is
the increased number of applications to
vent or flare royalty-free that the BLM
has received from operators. 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 of
associated gas from oil wells in New
Mexico, Montana, the Dakotas, and, to
a lesser extent, Wyoming.
b. Recent Studies of Venting and Leaks
The proposed rule preamble section
IV.H.2 discussed recent efforts to
improve our understanding of the
quantities of natural gas lost through
venting and leaks during the production
process, and it highlighted a number of
recent studies. These include both
‘‘bottom up’’ studies, which attempt to
improve the accuracy and
understanding of current estimates by
conducting site-specific intensive
measurements of losses during the
production process, and ‘‘top down’’
studies, which use aircraft and tracers to
quantify atmospheric methane levels
and attribute them to oil and gas
production activities. Several of these
recent studies by government, industry,
and environmental organizations
suggest that emission levels are higher
than those estimated using the DOI and
EPA data, and in particular, some
studies highlighted emissions levels two
to three times higher than those based
on EPA data. They also provided
information on the distribution of gas
leaks, which are heavily concentrated at
‘‘super-emitter’’ facilities, and
highlighted the challenges in predicting
which sites will experience superemitter conditions. Commenters on the
proposed rule pointed to additional
studies, some issued after the proposal,
that further demonstrate significant gas
loss, the potential to reduce such waste
through various technologies and
practices, and the need for widespread
leak detection and repair.
45 BLM query of AFMSS database for the number
of Flaring Sundry Notices filed on Federal and
Indian lands between 2009 and 2015 on November
4, 2011.
46 79 FR 49490 (Aug.16, 2012).

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Commenters pointed to both bottom
up and top down studies that suggest
BLM’s estimate of natural gas waste is
conservative. For example, EPA’s 2016
GHG Inventory was released in April
2016 (after BLM issued its proposed
rule), and provides estimates of methane
loss from the oil and gas sector that are
significantly greater than previous
estimates.47 EPA updated its method for
estimating emissions using the latest
peer-reviewed science published over
the last several years. The data also
revealed that emissions had grown by
more than 10 percent between 2010 and
2014.
Commenters also referenced a 2013
top-down study led by the National
Oceanic and Atmospheric
Administration (NOAA) that estimated
emissions from an oil and natural gas
production field in Uintah County,
Utah, using atmospheric measurements
in a mass balance approach. The
measurements, published in
Geophysical Research Letters, suggested
an emission rate between 6.2 and 11.7
percent of production, allowing for
uncertainties in gas composition and gas
production.48 This is significantly
higher than estimates from bottom up
inventories, such as the 1.4 percent of
production assumed in the 2012 EPA
Greenhouse Gas Inventory, and further
suggests that natural gas waste is likely
underestimated in commonly cited
inventories.
In meetings pursuant to E.O. 12866,
stakeholders referenced a new study
published in Nature on October 5, 2016,
entitled ‘‘Upward revision of global
fossil fuel methane emissions based on
isotope database.’’ 49 The research was
47 EPA, U.S. Greenhouse Gas Inventory Report:
1990–2014 at 3–69, Table 3–46 (2016), available at
https://www.epa.gov/sites/production/files/201604/documents/us-ghg-inventory-2016-main-text.pdf
(‘‘2016 GHG Inventory’’); EPA,U.S. Greenhouse Gas
Inventory Report: 1990–2013 at 3–70, Table 3-44
(2016), available at https://www.epa.gov/sites/
production/files/2016-03/documents/us-ghginventory-2015-main-text.pdf (‘‘2015 GHG
Inventory’’). See also Envt’l Def. Fund, New EPA
Stats Confirm: Oil & Gas Methane Emissions Far
Exceed Prior Estimates (Apr. 15, 2016), https://
www.edf.org/media/new-epa-stats-confirm-oilgasmethane-emissions-far-exceed-prior-estimates; A.R.
Brandt et al., Methane Leaks from North American
Natural Gas Systems, 343 Science 733 (2014),
available at http://www.novim.org/images/pdf/
ScienceMethane.02.14.14.pdf; Gina McCarthy,
Remarks on Climate Action at CERA in Houston,
Texas (Feb. 24, 2016), available at https://yosemite.
epa.gov/opa/admpress.nsf/8d49f7ad4bbcf4ef85257
3590040b7f6/5c432a7068e191e985257f630054fea8
!OpenDocument.
48 Anna Karion et al., Methane Emissions
Estimate from Airborne Measurements Over a
Western United States Natural Gas Field, 40,
Geophysical Research Letters 4393, 4393 (2013)
(http://onlinelibrary.wiley.com/doi/10.1002/
grl.50811/full).
49 Schwietzke, Stefan et al. ‘‘Upward Revision of
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conducted by scientists from NOAA and
the Cooperative Institute for Research in
Environmental Sciences at the
University of Colorado, Boulder. The
study relied on the largest isotopic
methane source signature database ever
assembled to estimate total global
methane emissions and identify the
sources of emissions. It finds that
methane emissions from fossil fuel
production are 20% to 60% greater than
previous estimates, and that they
represent 20% to 25% of global methane
emissions. The study also highlights
that methane emissions by microbial
sources (e.g., cows, agriculture,
landfills, and wetlands) are responsible
for 58% to 67% of total methane
emissions each year, and that these
sources drove most of the global
increase in methane emissions observed
between 2007 and 2013. Thus, the study
affirms the potential for methane
mitigation from fossil fuel production,
while indicating that significant further
reductions may be available from
expanding mitigation efforts to other
sectors as well.
There have also been recent and
ongoing studies of so-called ‘‘superemitters,’’ which account for a
disproportionate quantity of the losses.
One of these is a study by Zavala et al.,
published on July 7, 2015, in
Environmental Science and Technology.
The study used data collected from gas
wells in the Barnett Shale region in
Texas to identify unusually high
emitters—that is, emissions outliers—by
focusing on a site’s absolute methane
emissions divided by production rate.
The study referred to this metric as the
proportional loss rate, and demonstrated
that sites with ‘‘high proportional loss
rates have excess emissions resulting
from abnormal or otherwise avoidable
operating conditions such as improperly
functioning equipment.’’ The study then
concluded that these sources’
‘‘reduction potential’’—that is, their
ability to reduce their losses—is likely
greater than that suggested by emissionfactor based estimates. The study also
found that the losses and abnormal
operating conditions that characterize
these super-emitters are not specific to
a given set or type of sources, but can
and do occur at different sources over
time.50
Isotope Database.’’ Nature, 88 Vol. 538. (Oct. 5,
2016) (http://www.nature.com/nature/journal/v538/
n7623/full/nature19797.html); U.S. Department of
Commerce, National Oceanic and Atmospheric
Administration. Study Finds Fossil Fuel Methane
Emissions Greater Than Previously Expected (2016)
(http://www.noaa.gov/media-release/study-findsfossil-fuel-methane-emissions-greater-thanpreviously-estimated).
50 Zavala-Araiza, et al., (2015) ‘‘Toward a
Function Definition of Methane Super-Emitters:

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In 2015, a team of scientists at
Colorado State University published
studies based on direct measurements of
emissions from 114 gathering facilities
at sixteen different processing plants.
The study found that 30 percent of
facilities were responsible for
approximately 80 percent of the venting.
Substantial venting occurred at liquid
storage tanks at approximately 20
percent of the facilities where emission
rates were four times the average rate.
Moreover, the high emitting facilities
were generally capable of immediate
emission reductions through operating
adjustments, such as adjusting the
operating pressure of the separation
equipment.51
In 2012, the City of Fort Worth, Texas,
sponsored a study of 375 oil and gas
production facilities. It found that thief
hatches were the largest source, and
pneumatic controllers were the most
frequent source, of fugitive emissions at
well pads and compressor stations.
These leaks were often due to operator
error or inadequate maintenance.52
Commenters also pointed to the
largely random nature of significant
leaks. A recent study, authored by Lyon
et al., used optical gas imaging to survey
8,220 oil and gas well pads through
aerial surveys. The study found only a
small correlation between the
probability of detection of a leak and
site characteristics, such as well count,
well age, gas production, oil production,
and water production. The stochastic
and diverse nature of the sites with
leaks, along with the level of waste
observed, provides further support for
broadly applicable leak detection and
repair programs.53
Both the Zavala and Lyon studies
observed that leak rates are not strongly
correlated with well production rates—
that is, higher and lower producing
wells can both have significant levels of
natural gas waste. Specifically, the
Zavala study found small producing
sites (10–100 Mcf/day) were twice as
likely as those sites an order of
magnitude larger (100–1,000 Mcf/day)
to be among the 5% of sites with the
Application to Natural Gas Production Sites,’’
Environ. Sci. Technol., 49, at 8167–8174 (‘‘ZavalaAraiza (2015)’’), available at http://pubs.acs.org/
doi/abs/10.1021/acs.est.5b00133.
51 Mitchell, A.L., et al, (2015) ‘‘Measurements of
Methane Emissions from Natural Gas Gathering
Facilities and Processing Plants,’’ Environ. Sci.
Technol, 2015, 49 (5), pp 3219–3227, available at
http://pubs.acs.org/doi/abs/10.1021/es5052809.
52 Eastern Research Group and Sage
Environmental Consulting, City of Fort Worth
Natural Gas Air Quality Study (Final Report) 3–99
(2011), available at http://fortworthtexas.gov/up
loadedFiles/Gas_Wells/AirQualityStudy_final.pdf.
53 David R. Lyon et. al, Aerial Surveys of Elevated
Hydrocarbon Emissions from Oil and Gas
Production Sites, 1 Envtl. Sci. Tech. (2016)

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highest emissions. The Lyon study
found that well pad characteristics, such
as oil production levels, could only
collectively explain about 14% of the
variation in observed emissions. While
a statistically significant correlation
between size and leaks is observed, both
studies note that it is a weak linear
correlation and that leak occurrence is
largely stochastic. The Lyon study
found that over 15 percent of the highemitting sites detected in its survey
were low production sites, producing 15
barrel of oil equivalent (BOE) per day or
less.54
Another recent study by the Colorado
Air Pollution Control Division surveyed
oil and gas wells over two years using
optical gas imaging. The research
revealed a significant number of leaks,
but also highlighted that it is possible to
achieve immediate reduction or
minimization of waste from production
facilities with timely identification and
repair of leaks. The survey spanned
from July 2013 through June of 2015 and
covered over 4,400 facilities. The optical
gas imaging technology identified gas
lost through leaks or vents at more than
25 percent of the facilities, with the
majority of these leaks or vents
occurring at storage tanks.55

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c. Existing BLM Regulations Need To Be
Updated
As discussed in detail in the proposed
rule preamble at section IV.E, venting,
flaring, and royalty-free uses of oil and
natural gas on BLM-administered leases
are currently governed by NTL–4A. This
‘‘Notice to Lessees’’ 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
places limitations on venting or flaring
of gas-well or oil-well gas, unless
approved in writing by BLM. NTL–4A
also specifies the circumstances under
which an operator owes royalties on oil
or gas that is lost from a lease.
In the past 37 years since NTL–4A
was issued, oil and gas production
technologies and practices have
advanced considerably, particularly
with the development of modern
hydraulic fracturing techniques and
54 David R. Lyon et. al, Aerial Surveys of Elevated
Hydrocarbon Emissions from Oil and Gas
Production Sites, 1 Envtl. Sci. Tech. (2016)
available at http://pubs.acs.org/doi/abs/10.1021/
acs.est.6b00705. See supporting information ‘‘Sitelevel parameter data for well pads in the surveyed
areas and basins’’ file columns M and N in the
‘‘Surveyed Well Pads’’ worksheet.
55 Colorado Department of Public Health and
Environment Air Pollution Control Division
Colorado Optical Gas Imaging Infrared Camera Pilot
Project: Final Assessment July 11, 2016 Author:
Tim Taylor

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directional drilling. 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 the production
process have also advanced. Not
surprisingly, NTL–4A neither reflects
today’s best practices and advanced
technologies, nor is particularly
effective in minimizing waste of public
minerals, as the previously described
data and studies show. In addition, as
discussed in the preamble to the
proposed rule, ambiguities have arisen
regarding how NTL–4A is interpreted
and implemented by various BLM
offices and industry entities. There is a
compelling need to update these
requirements to make them clearer,
more effective, and reflective of modern
technologies and practices.
d. Concerns Identified Through
Oversight
External oversight reviews strongly
support the BLM’s conclusion that the
current NTL–4A requirements need to
be updated, and many of the changes
made in this rule implement
recommendations from relevant
oversight reviews. As discussed in the
proposed rule, key oversight reviews
that influenced the development of this
rule include: (1) A December 2007
Royalty Policy Committee (RPC) report,
Mineral Revenue Collection from
Federal and Indian Lands and the Outer
Continental Shelf, which recommended
that the BLM update its rules and
identified many specific actions to
improve production accountability; (2) a
March 2010 report by the OIG, BLM and
MMS Beneficial Use Deductions, which
recommended that the BLM clarify its
requirements for royalty-free use of
natural gas; and (3) an October 2010
GAO report, Federal Oil and Gas
Leases—Opportunities Exist to Capture
Vented and Flared Gas, Which Would
Increase Royalty Payments and Reduce
Greenhouse Gases, which recommended
that the BLM update its regulations to
take advantage of opportunities to
capture economically recoverable
natural gas using available technologies.
In July 2016, the GAO issued another
report relevant to this rule. The 2016
report entitled, ‘‘OIL AND GAS—
Interior Could Do More to Account for
and Manage Natural Gas Emissions,’’
reviewed the DOI’s provisions to
account for and manage natural gas
emissions. The GAO found that DOI
agencies, including the BLM and ONRR,
have historically focused on
determining the volume of natural gas
production and accounting for the
percent of that volume that is royalty-

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bearing, but have not focused enough on
providing operators clear guidance on
how to determine, account for, and
report the volumes of natural gas that
are not royalty bearing. The GAO
suggested that lack of specific guidance
in these areas has resulted in substantial
variation in how operators obtain and
report the data, and may result in
inaccuracy in the DOI’s data on natural
gas emissions. The GAO recommended
that the BLM provide operators with
specific instructions regarding how to
estimate natural gas emissions, which
the GAO suggests would improve
emissions data and better ensure that,
when appropriate, royalties are
collected on these lost quantities of
natural gas. The GAO also addressed
recommendations to the ONRR that are
closely related to provisions of this rule.
For example, the GAO recommended
that the ONRR provide additional
guidance on how to report royalty-free
and royalty-bearing flaring, and how to
report unreported or underreported
emissions from sources such as tanks.
Some of the changes made in today’s
rule will help clarify the regulatory
requirements that relate to some of these
reporting concerns.
3. Relationship to Other Federal, State,
and Industry Activities
Understanding that other Federal,
State and tribal rules also apply to
aspects of onshore oil and gas
production, the BLM has aimed to
ensure that this rule will complement
other regulatory requirements. As noted
earlier, for example, the EPA issued
rules in 2012 and May of 2016 to control
emissions of methane and VOCs from
new, modified and reconstructed oil
and gas wells and production
equipment, and many States and tribes
also regulate aspects of the production
process to address safety, waste,
production accountability, and/or air
quality concerns.
In updating the BLM regulations, the
BLM carefully considered and
accounted for these potentially
overlapping regimes. Thus, to the
maximum extent possible, today’s rule
aligns its requirements with similar
requirements adopted by the EPA or the
States, exempts equipment and
processes covered by EPA requirements,
and authorizes the BLM to grant
variances from particular rule
provisions if a petitioner State or tribe
can show that a State, local, or tribal
requirement is at least as effective as the
corresponding provision of this rule.
The BLM is also committed to working
with the EPA to ensure that any future
EPA regulations align to the extent
possible with the BLM requirements. To

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the extent that additional State or tribal
regulations are adopted in the future,
the State and tribal variance provisions
in section 3179.401 provide a
mechanism for the BLM to approve
compliance with those regulations in
lieu of the BLM regulations, where the
State or tribal regulations meet the
criteria for a variance.
As noted earlier, even though EPA,
State, and tribal requirements address
some gas waste, there is still a clear
need for this rule. For one thing, the
BLM has independent legal and
proprietary responsibilities to prevent
waste in the production of Federal and
tribal minerals, as well as to ensure the
safe, responsible, and environmentally
protective use of BLM-managed lands
and resources. This rule will update the
BLM’s decades-old venting and flaring
requirements, and represents an
important element of BLM’s larger effort
to ensure that its oil and gas regulations
are effective, transparent, and easy to
understand and administer, and that the
provisions of those regulations
adequately account for significant recent
technological advances in the industry.
The BLM also notes that this
regulation covers a range of sources and
activities that are not adequately
addressed by existing BLM, State, or
tribal regulations. Further, EPA
regulations cover only new, modified,
and reconstructed sources, not the many
existing and unmodified sources on
BLM-administered leases. EPA
regulations also do not address flaring
or activities such as liquids unloading.
Finally, State and tribal regulations are
effective only within the jurisdiction of
the relevant State or tribe, and State and
tribal regulations do not consistently
address all the sources of waste BLM
seeks to prevent via this rule. Indeed, no
State or tribe has requirements covering
all the sources of waste addressed by
this rule.
In the proposed rule preamble section
IV.I.2., the BLM also discussed the
commendable efforts that some oil and
gas operators have made to reduce waste
of gas through venting, flaring, and
leaks. While steps in the right direction,
these voluntary efforts are insufficient
by themselves, given the large and
growing volumes of waste. Moreover,
for the one specific activity area for
which industry has identified a
reduction in gas losses over the past few
years—well completions at
hydraulically fractured gas wells—the
decreases appear to be largely driven by
the adoption of the EPA subpart OOOO
requirements for green completions at
those wells.
The following sections provide a brief
overview of EPA and State regulations

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that are particularly relevant to this
rulemaking.
a. EPA Regulations
The EPA regulates air pollution from
oil and gas production, and since
measures to reduce emissions tend to
limit releases of natural gas, the EPA’s
air pollution regulations to reduce
emissions from the oil and gas sector
have the co-benefit of reducing waste of
natural gas and increasing gas capture.
BLM very carefully coordinated the
waste prevention requirements under
today’s rule with EPA requirements
applicable to some of the same sources,
to minimize compliance burdens for
operators and to avoid unnecessary
duplication.
As explained in section IV.I.3 of the
proposed rule preamble, the EPA
adopted new source performance
standards (NSPS) in 2012 (subpart
OOOO) that require new, modified, or
reconstructed sources to limit the
release of VOCs by requiring that
operators use ‘‘green completions’’ at
hydraulically fractured natural gas
wells.56 The EPA’s NSPS also imposed
requirements at gas processing plants
and boosting stations.57
On September 18, 2015, EPA
proposed NSPS standards that would
update the 2012 standards to limit
methane in addition to VOCs, as
described in the BLM proposed rule, to
be codified in proposed 40 CFR part 60
subpart OOOOa.58 This rule also
proposed to limit methane and VOC
emissions from additional sources not
covered under the 2012 subpart OOOO
rule. EPA finalized 40 CFR part 60
subpart OOOOa on May 12, 2016, after
receiving over 900,000 public comments
and holding three public hearings, and
the rule went into effect in August 2016.
As with the subpart OOOO standards,
subpart OOOOa applies only to new,
modified, or reconstructed sources, and
not to existing equipment and
operations. The final OOOOa rule
regulates greenhouse gases through
limits on methane emissions that
owners and operators can meet using
readily available and cost-effective
technologies.59 It also requires leak
detection and repair at new, modified,
and reconstructed sources, and it covers
additional new, modified, and
56 79

FR 49490, August 16, 2012.
OOOO imposed emission standards for
pneumatic controllers, centrifugal compressors and
storage vessels, and required work practices for
reciprocating compressors and equipment leaks at
gas processing plants. Subpart OOOO also imposed
a sulfur dioxide emission standard for sweetening
units at gas processing plants.
58 80 FR 56593, Sept. 18, 2015.
59 81 FR 35823, June 3, 2016.
57 Subpart

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reconstructed equipment and activity in
the oil and gas production sector not
addressed in the subpart OOOO
standards, such as hydraulically
fractured oil well completions,
pneumatic pumps, and fugitive
emissions from well sites and
compressor stations. The final 40 CFR
subpart OOOOa rule includes several
changes from the EPA’s proposed rule
that are particularly noteworthy with
respect to the BLM’s rulemaking,
including: (1) It establishes a fixed semiannual schedule for monitoring leaks
from well sites; (2) it does not adopt a
proposed exemption from the LDAR
requirements for low-production wells;
and (3) it does not adopt proposed
requirements to limit emissions from
pneumatic piston pumps.
On May 12, 2016, EPA also
announced the availability of Control
Technique Guidelines (CTGs) to help
States reduce VOC emissions from
existing sources in certain ozone
nonattainment areas. Although reducing
methane emissions is not the purpose of
CTGs, control of VOC emissions also
results in co-control of methane
emissions. These CTGs identify many of
the same types of measures required by
the OOOOa standards, but the
guidelines are not legally binding.
Rather, the CTGs are a set of
recommendations that State and local
air pollution control agencies must
consider when evaluating what they
will identify as Reasonably Available
Control Technology (RACT) for existing
sources covered under State ozone
nonattainment plans to implement
Clean Air Act requirements, known as
State Implementation Plans (SIPs).
States are only required to include
RACT measures in their SIPs for ozone
nonattainment areas whose air quality
levels violate the Clean Air Act air
quality standard for ozone and are
classified as moderate nonattainment or
higher.60 In October of 2015, EPA
revised the health-based ambient air
quality standard for ozone pollution to
70 parts per billion. The changes to SIPs
required to address that pollution would
be due to EPA within two years after the
ozone classifications are published in
the Federal Register, which is projected
to be no later than Jan. 21, 2021.61 It
appears that few, if any, areas with
significant Federal or Indian oil and gas
production are likely to be classified as
moderate nonattainment or above for
the most recent ozone standard.
Moreover, even if some areas with
60 I.e., nonattainment areas designated
‘‘moderate’’ or above.
61 These are the attainment dates for areas
designated as moderate nonattainment or above.

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significant Federal or Indian oil and gas
production are identified as having
ozone pollution problems, the changes
to SIPs required to address that
pollution would not likely be due to
EPA for a number of years.
The EPA has also taken the first steps
to gather information to promulgate
regulations that would require
subsequent State regulation of existing
sources under Clean Air Act (CAA)
section 111(d). When the EPA
establishes NSPS for new sources in a
particular source category, as it did for
the oil and gas sector in its OOOOa
regulations promulgated in May 2016,
the EPA is also required, under CAA
section 111(d)(1), to prescribe
regulations for States to submit plans
establishing emissions performance
standards for existing sources in that
source category. Acting under this CAA
mandate, in March of 2016 the EPA
announced its intention to regulate
existing oil and gas sources for methane
and VOC emissions.62 To begin this
process, the EPA issued a draft
information collection request (ICR) on
May 12, 2016, and a second draft ICR on
September 23, 2016.63 Once the ICR is
approved by the Office of Management
and Budget, the ICR is expected to
gather a broad range of information on
the oil and gas industry regarding
emission control efficacy, costs, and
timing requirements.64 The EPA then
expects to use this information in
developing regulations to guide State
plans to reduce emissions from existing
sources. This rulemaking would then be
followed by State development and
adoption of State plans containing
enforceable performance standards for
sources, State plan approvals by EPA,
and subsequent implementation by
industry to meet compliance deadlines
established in the State plans. Given the
length of this process and the
uncertainty regarding the final
outcomes, and in light of the BLM’s
independent statutory mandate to
prevent waste from Federal and Indian
oil and gas leases based on information
currently available, the BLM has
62 McCarthy, Gina. ‘‘EPA Taking Steps to Cut
Methane Emissions from Existing Oil and Gas
Sources’’. March 10, 2016. Available at https://
blog.epa.gov/blog/2016/03/epa-taking-steps-to-cutmethane-emissions-from-existing-oil-and-gassources.
63 81 FR 35763 and 81 FR 66692.
64 On September 23, 2016, EPA issued a second
draft ICR, and public comments are due October 31,
2016. Once all of the public comments are reviewed
and incorporated, and the ICR is approved by the
Office of Management and Budget, the EPA will
issue a final ICR, using its authority under CAA
Section 114. Industry will have at least 30 days to
complete the operator survey and 120 days to
respond to the facility survey. https://www.gpo.gov/
fdsys/pkg/FR-2016-09-29/pdf/2016-23463.pdf.

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determined that it is necessary and
prudent to update and finalize this
regulation at this time.
b. State Regulations
In developing this rule, the BLM
consulted with State regulators and
reviewed analogous State requirements
related to waste of oil and gas resources.
Specifically, the BLM reviewed
requirements from Alaska, California,
Colorado, Montana, North Dakota, Ohio,
Pennsylvania, Utah, and Wyoming.
Most of these State requirements were
discussed in the preamble to the
proposed rule, which also explained
that these State requirements, and the
outcomes they produce, vary widely.65
As noted in the preamble to the
proposed rule, of the States with
extensive oil and gas operations on
BLM-administered leases, only one has
comprehensive requirements to reduce
flaring, and only one has comprehensive
statewide requirements to control losses
from venting and leaks.66 Furthermore,
State regulations do not apply to BLMadministered leases on Indian lands,
and States do not have a statutory
mandate or trust responsibility to
reduce the waste of Federal and Indian
oil and gas. Finally, because State laws
and regulations are subject to change,
BLM reliance on State standards risks
additional waste of public resources and
adverse environmental impacts to
Federal and Indian lands should the
State standards change to allow for
additional waste and environmental
impacts. There is therefore a need for
uniform, modern waste reduction
standards for oil and gas operations on
public and Indian lands across the
country. Nonetheless, the BLM did look
to some of the most effective State
approaches as models. In particular, we
have drawn on approaches that
Colorado, Wyoming and North Dakota
adopted to address rising rates of
flaring, waste of minerals, and pollution
impacts in those states.
The BLM also notes that at least two
States have recently expressed an intent
to further reduce methane emissions
through regulatory action. On February
1, 2016, California’s Air Resources
Board proposed new rules to reduce
emissions of methane through venting
and leaks during oil and gas production,
processing, and storage.67 These
proposed rules would require the use of
vapor collection systems and the control
of vapors with 95 percent efficiency.
65 81

FR at 6633–34.
FR at 6636.
67 State of California Air Resources Board Staff
Report: Statement of Reasons, available at: http://
www.arb.ca.gov/cc/oil-gas/
Oil%20and%20Gas%20ISOR.pdf.
66 81

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The rules would limit the use of
combustion; however, if a combustion
control device must be used, the rules
would require the use of a lowemissions incinerator. In January 2016,
the Pennsylvania Department of
Environmental Protection also
announced that it would pursue an
enhanced strategy for reducing methane
emissions.68 Importantly, though,
neither of these proposed regimes nor
any existing State regimes cover the full
suite of oil and gas activities addressed
by this rule.
C. Legal Authority
Pursuant to a delegation of Secretarial
authority, the BLM is authorized to
regulate oil and gas activities on Federal
and Indian lands under a variety of
statutes, including the MLA, the
MLAAL, FOGRMA, FLPMA, the IMLA,
the IMDA, and the Act of March 3,
1909.69 These statutes authorize the
Secretary of the Interior to promulgate
such rules and regulations as may be
necessary to carry out the statutes’
various purposes.70
The MLA rests on the fundamental
principle that the public should benefit
from mineral production on public
lands.71 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/or tribal governments. For
competitively issued leases, the MLA
requires the payment of a royalty ‘‘at a
rate not less than 12.5 percent in
amount or value of the production
removed or sold from the lease’’; for
non-competitive leases, the MLA sets
the royalty ‘‘at a rate of 12.5 percent in
amount or value of the production
68 Pennsylvania Department of Environmental
Protection, A Pennsylvania Framework of Actions
for Methane Reductions from the Oil and Gas
Sector, available at: http://files.dep.state.pa.us/Air/
AirQuality/AQPortalFiles/Methane/
DEP%20Methane%20Strategy%201-192016%20PDF.pdf.
69 Mineral Leasing Act, 30 U.S.C. 188–287;
Mineral Leasing Act for Acquired Lands, 30 U.S.C.
351–360; Federal Oil and Gas Royalty Management
Act, 30 U.S.C. 1701–1758; Federal Land Policy and
Management Act of 1976, 43 U.S.C. 1701–1785;
Indian Mineral Leasing Act of 1938, 25 U.S.C.
396a–g; Indian Mineral Development Act of 1982,
25 U.S.C. 2101–2108; Act of March 3, 1909, 25
U.S.C. 396.
70 30 U.S.C. 189 (MLA); 30 U.S.C. 359 (MLAAL);
30 U.S.C. 1751(a) (FOGRMA); 43 U.S.C. 1740
(FLPMA); 25 U.S.C. 396d (IMLA); 25 U.S.C. 2107
(IMDA); 25 U.S.C. 396.
71 See, e.g., California Co. v. Udall, 296 F.2d 384,
388 (D.C. Cir. 1961) (noting that the MLA was
‘‘intended to promote wise development of . . .
natural resources and to obtain for the public a
reasonable financial return on assets that ‘belong’ to
the public’’).

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removed or sold from the lease.’’ 72 The
BLM is responsible for specifying
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.
Another important means of ensuring
that the public benefits from mineral
production on public lands is
minimizing and deterring the waste of
oil and gas produced from the Federal
mineral estate. To this end, the MLA
requires oil and gas lessees to ‘‘use all
reasonable precautions to prevent waste
of oil or gas developed in the land,
. . .’’ 73 The MLA requires lessees to
exercise ‘‘reasonable diligence, skill,
and care’’ in their operations and also
requires oil and gas lessees to observe
‘‘such rules . . . for the prevention of
undue waste as may be prescribed by
[the] Secretary.’’ 74 Lessees are not only
responsible for taking measures to
prevent waste, but also responsible for
making royalty payments on wasted oil
and gas when waste does occur. In
FOGRMA, Congress expressly made
lessees ‘‘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 [FOGRMA] or any
mineral leasing law.’’ 75
In addition to ensuring that the public
benefits from oil and gas production
from public lands, the BLM is also
tasked with regulating the physical
impacts of oil and gas development on
public lands. The MLA directs the
Secretary to ‘‘regulate all surfacedisturbing activities conducted pursuant
to any lease’’ and to ‘‘determine
reclamation and other actions as
required in the interest of conservation
of surface resources.’’ 76 The MLA
requires oil and gas leases to include
provisions ‘‘for the protection of the
interests of the United States . . . and
for the safeguarding of the public
welfare,’’ which includes lease terms for
the prevention of environmental
harm.77 The Secretary may suspend
lease operations ‘‘in the interest of
conservation of natural resources,’’ a

phrase that encompasses not just
conservation of mineral deposits, but
also preventing environmental harm.78
The Secretary also may refuse to lease
lands in order to protect the public’s
interest in other natural resources and
the environment.79 BLM’s regulations
governing oil and gas operations on the
public lands have always required
operators to avoid damaging other
natural resources or environmental
quality.80
The MLA additionally requires oil
and gas leases to contain ‘‘a provision
that such rules for the safety and welfare
of the miners . . . as may be prescribed
by the Secretary shall be observed .
. . .’’ 81 This rule helps to ensure safety
of workers engaged in the production of
oil and gas on Federal and Indian lands
by requiring, except in special
circumstances, the combustion of
natural gas loosed from wells and
equipment during production.
FLPMA further authorizes BLM to
‘‘regulate’’ the ‘‘use, occupancy, and
development’’ of the public lands via
‘‘published rules.’’ 82 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.’’ 83 And
FLPMA authorizes BLM to ‘‘promulgate
rules and regulations to carry out the
purposes of this Act and of other laws
applicable to the public lands.’’ 84
FLPMA expressly declares that the BLM
should balance the need for domestic
sources of minerals against the need to
‘‘protect the quality of scientific, scenic,
historical, ecological, environmental, air
and atmospheric, water resources, and
archeological values; . . . [and] provide
for outdoor recreation and human
occupancy and use.’’ 85
FLPMA requires the BLM to manage
public lands under principles of
multiple use and sustained yield.86 The
statutory definition of ‘‘multiple use’’
explicitly includes the consideration of
environmental resources. Multiple use
is a ‘‘combination of balanced and
diverse resource uses that takes into
account the long-term needs of future
generations for renewable and

72 30 U.S.C. 226(b)(1)(A) (emphasis added); 30
U.S.C. 226(c)(1); see also 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 162⁄3%, absent approval
of the Secretary. 25 CFR 211.41, 212.41.
73 30 U.S.C. 225.
74 30 U.S.C. 187.
75 30 U.S.C. 1756.
76 30 U.S.C. 226(g).
77 See Natural Resources Defense Council, Inc. v.
Berklund, 458 F. Supp. 925, 936 n.17 (D. DC 1978).

78 30 U.S.C. 209; Copper Valley Machine Works
v. Andrus, 653 F.2d 595, 601 & nn.7–8 (D.C. Cir.
1981); Hoyl v. Babbitt, 129 F.3d 1377, 1380 (10th
Cir. 1997); Getty Oil Co. v. Clark, 614 F. Supp. 904,
916 (D. Wyo. 1985).
79 Udall v. Tallman, 380 U.S. 1, 4 (1965); Duesing
v. Udall, 350 F.2d 748, 751–52 (1965).
80 See 43 CFR 3162.5–1 to .5–2 (1983–2014).
81 30 U.S.C. 187.
82 43 U.S.C. 1732(b).
83 43 U.S.C. 1732(b).
84 43 U.S.C. 1740.
85 43 U.S.C. 1701(a)(8).
86 43 U.S.C. 1702(c), 1732(a).

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nonrenewable resources . . . .’’ 87
Multiple use also requires resources to
be managed in a ‘‘harmonious and
coordinated’’ manner ‘‘without
permanent impairment to the
productivity of the land and the quality
of the environment.’’ 88 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 or the greatest
unit output.’’ 89
Finally, the promulgation of this rule
helps to meet the Secretary’s statutory
trust responsibilities with respect to the
development of Indian oil and gas
interests. The Secretary’s management
and regulation of Indian mineral
interests carries with it the duty to act
as a trustee for benefit of the Indian
mineral owners.90 The Congress has
directed the Secretary to ‘‘aggressively
carry out [her] trust responsibility in the
administration of Indian oil and gas.’’ 91
In furtherance of her trust obligations,
the Secretary has delegated regulatory
authority for administering operations
on Indian oil and gas leases to the
BLM,92 which has developed
specialized expertise through regulating
the production of oil and gas from
public lands administered by the
Department. In choosing from among
reasonable regulatory alternatives for
Indian mineral development, the BLM is
obligated to adopt the alternative that is
in the best interest of the tribe and
individual Indian mineral owners.93
What is in the best interest of the tribe
and individual Indian mineral owners is
determined by a consideration of all
relevant factors, including economic
considerations as well as potential
environmental and social effects.94 The
BLM believes that this rule is in the best
interest of Indian mineral owners
because it will prevent unnecessary and
excessive losses (‘‘waste’’) of natural gas
from Indian lands. In so doing, this rule
will help ensure that the extraction of
natural gas from Indian lands results in
the payment of royalties to Indian
mineral owners, rather than the waste of
87 43

U.S.C. 1702(c).
U.S.C. 1702(c).
89 43 U.S.C. 1702(c).
90 See Woods Petroleum Corp. v. Department of
Interior, 47 F.3d 1032, 1038 (10th Cir. 1995) (en
banc).
91 30 U.S.C. 1701(a)(4).
92 235 DM 1.1.K.
93 See Jicarilla Apache Tribe v. Supron Energy
Corp., 728 F.2d 1555, 1567 (10th Cir. 1984)
(Seymour, J., concurring in part and dissenting in
part), adopted as majority opinion as modified en
banc, 782 F.2d 855 (10th Cir. 1986).
94 See 25 CFR 211.3.
88 43

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the owners’ mineral resources.95
Additionally, the BLM believes tribal
members and individual Indian mineral
owners who live near Indian oil and gas
development will realize environmental
benefits as a result of this rule’s
reductions in flaring and air pollution
from Indian oil and gas development.
During public comment hearings, the
BLM heard from a number of tribal
members who raised concerns about the
impacts of vented and leaked gas on
their health, highlighting in particular
increases in ozone pollution and air
toxics. Tribal members also detailed the
impacts of living near numerous large
flares, noting the resulting noise and
light pollution. The BLM believes that
this rule will help to reduce some of
these impacts on tribal members.
In short, the BLM has the authority to
manage public and tribal oil and gas
resources to reduce waste and ensure
environmentally responsible
development. In response to the notice
of proposed rulemaking, the BLM
received many comments asserting a
range of different arguments regarding
the BLM’s exercise of its legal authority
in promulgating this rule. The most
salient of these arguments are addressed
later in this preamble, but the BLM did
not make any changes to this rule based
on comments about the BLM’s
authority.

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D. Stakeholder Outreach
In 2014 and again in in 2016, the BLM
conducted a series of forums to consult
with tribal governments 96 and solicit
stakeholder views to inform the BLM’s
development of the proposed and final
rules. In 2014, the BLM held public
meetings in Denver, Colorado (March
19, 2014), Albuquerque, New Mexico
(May 7, 2014), Dickinson, North Dakota
(May 9, 2014), and Washington, DC
(May 14, 2014).97 On each of those days,
the BLM held a tribal outreach session
in the morning and a public outreach
session in the afternoon. In advance of
the tribal outreach sessions, the BLM
sent letters to over 200 tribal leaders
that have previously expressed interest
in oil and gas related matters. These
letters explained generally the proposed
rulemaking, invited the tribal leaders to
attend the outreach sessions, provided
95 The remainder of this preamble refers to this
analysis as the BLM’s determination that, as a result
of its trust obligations, it has an obligation or
mandate to reduce waste from Indian lands, just as
it does to reduce waste from BLM-administered
Federal Lands.
96 In developing this rule, the BLM consulted
with tribal stakeholders in compliance with 25
U.S.C. 2107, 512 DM 4, and 512 DM 5.
97 See the BLM oil and gas program’s outreachevents page: http://www.blm.gov/wo/st/en/prog/
energy/public_events_on_oil.

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contact persons for further information,
and provided an email address for
submitting comments. At the 2014
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 pre-proposal 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.
After the proposed rule was published
on February 8, 2016, we conducted a
second series of paired outreach
meetings, with a tribal meeting each
morning and a public meeting each
afternoon. We held these meetings at
four locations: Farmington, New Mexico
(February 16, 2016), Oklahoma City,
Oklahoma (February 18, 2016), Denver,
Colorado (March 1, 2016), and
Dickinson, North Dakota (March 3,
2016). Again, in advance of the tribal
outreach sessions, the BLM sent letters
to over 200 tribal leaders that have
previously expressed interest in oil and
gas related matters. These letters
explained generally the proposed rule,
invited the tribal leaders to attend the
outreach sessions, provided contact
persons for further information, and
provided an email address for
submitting comments. The public
outreach sessions included a telephone
conference call-in number to allow
members of the public who could not
attend in person to listen live to the
proceedings.
In addition, the BLM conducted
outreach to States with extensive oil and
gas production on BLM-administered
leases. Prior to the proposal, the BLM
reviewed State regulations and
guidance, and contacted State regulatory
bodies that oversee aspects of oil and
gas production to discuss their
requirements and practices. After
issuing the proposal, the BLM
conducted seven online meeting
sessions with State regulators from
Alaska, Colorado, New Mexico, North
Dakota, Utah (two meetings), and
Wyoming.

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In response to the proposed rule and
these outreach meetings, the BLM
received approximately 330,000 total
comment submissions from Federal,
State, and local governments and
agencies, tribal organizations, industry
representatives, non-governmental
organizations, individuals, and other
stakeholders. Of the approximately
330,000 comment submissions,
approximately 1,000 were unique
comments, with the remaining
comments coming from mass-mailing
campaigns from several organizations.
The BLM closely reviewed and analyzed
the comments we received, and made
revisions to the proposed rule based on
the information, data, analysis, insights,
and viewpoints provided in the
comments. The final rule reflects the
very extensive input that the BLM
gathered from these public meetings,
discussions with States and tribes, and
the public comment process.
IV. Summary of Final Rule
Like the proposed rule, the final rule
focuses on key areas in the oil and gas
production process where wasteprevention actions are most effective
and least costly. Specifically, we are
adopting requirements to reduce waste
from the following: Venting or 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.
Like the proposed rule, the final rule
requires operators to flare gas rather
than vent it, except in specified
circumstances, such as emergencies, the
routine operation of certain equipment,
and when flaring is technically
infeasible. The final rule then requires
operators to avoid wasteful flaring of gas
by capturing for sale or using on-site
specified percentages of their adjusted
total gas production. Beginning one year
from the effective date of the final rule,
operators must capture 85 percent of
their adjusted total gas production each
month, and this gradually increases to
98 percent by 2026. An operator’s
adjusted total gas production is based
on the quantity of high pressure gas
produced from the operator’s
development wells that are in

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production, adjusted to exempt a
specified volume of gas per well. The
exempted or ‘‘flaring allowable’’ volume
declines over time. Beginning one year
from the effective date of the final rule,
operators are allowed to exempt 5,400
Mcf gas per well per month, and this
quantity gradually declines to 750 Mcf
by 2025.
With respect to leaks, the final rule
largely follows the proposed rule,
except that the required frequency of
inspection is set at two times a year, and
does not vary according to the number
of leaks found. Operators must use
optical gas imaging equipment or
portable analyzers deployed according
to Method 21, and leaks must be
repaired and retested within specified
time frames. The final rule clarifies the
approval process for alternative leak
detection devices and for operators’
individual alternative leak inspection
programs.
Like the proposed rule, the final rule
includes requirements to update old and
inefficient equipment, and to follow
best practices to minimize waste
through venting. Thus, operators must
replace high-bleed pneumatic
controllers and certain pneumatic
pumps with less wasteful controllers
and pumps, and capture or flare any
high volumes of gas that would
otherwise be vented from tanks. In
addition, the final rule requires
operators to capture, flare, use, or
reinject gas produced during well
drilling and well completions, and it
limits the quantities of gas that may be
vented royalty-free during well testing.
The final rule continues to address
whether and when lost oil or gas is
royalty-bearing, based on whether the
loss is deemed unavoidable (royaltyfree) or avoidable (royalty-bearing).
Relative to the proposed rule, and after
our evaluation of public comments, the
final rule somewhat expands the list of
circumstances in which a loss of oil or
gas is deemed unavoidable (thereby
expanding the circumstances under
which the loss of gas is considered
royalty-free), and retains the proposed
approach that all oil or gas that is not
specifically defined as unavoidably lost
is deemed to be avoidably lost and
subject to royalties. Unavoidable losses
include oil or gas lost in emergencies,
losses from normal equipment operation
when the operator is in compliance with
all requirements to update equipment,
and gas that is flared from wells not
connected to a gas pipeline (unless the
operator has not met applicable gas
capture requirements). Because the BLM
believes that it is reasonable to expect
operators to reduce waste in order to
comply with the final rule’s capture

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percentage requirements, any quantities
of flared gas that cause the operator to
violate the applicable capture
requirements are deemed avoidable
losses and subject to royalties.
In addition, the BLM is finalizing the
proposed change to the royalty
provisions, to align the provisions with
the BLM’s statutory authority and allow
the BLM to set royalties for competitive
leases at or above 12.5 percent. At this
time, however, the BLM is not setting
the royalty rate above 12.5 percent in
this regulation.
Like the proposed rule, the final rule
aligns the requirements of this rule to
the extent practicable with EPA and
State requirements. It also avoids
potential regulatory overlap by
exempting certain equipment covered
by relevant EPA rules, and deeming the
operator’s compliance with relevant
EPA requirements to satisfy the BLM
requirements as well.
The final rule also allows a State or
tribe to request a variance from
particular BLM requirements. If the
variance is granted, the BLM has
authority to enforce the specific
provision(s) of the State, local, or tribal
rule for which the variance was granted,
instead of the comparable provision(s)
of the BLM rule. As clarified in the final
rule, the BLM may grant a State or tribal
variance request if the BLM determines
that the State, local, or tribal rule would
perform at least as well as the affected
BLM regulatory provision in reducing
waste of oil and gas, reducing
environmental impacts from venting
and or flaring of gas, and ensuring the
safe and responsible production of oil
and gas.
V. Major Changes From Proposed Rule
Based on information that has become
available since the proposed rule, and
the extensive material BLM received
through public comments, the BLM has
made changes and adjustments to the
proposed regulatory text. This section of
the preamble summarizes the most
significant of those changes and
addresses some of the key public
comments.
This section only addresses a few
substantive areas in which the BLM
made significant changes from the
proposed rule. Section VI discusses
significant comments received on other
aspects of the rule. The final text of all
of the rule provisions, and changes
made in light of all public comments,
are discussed in Section VII, Section by
Section. Finally, additional public
comments are addressed in the separate
Response to Comments document,
which is available to the public on the

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BLM Web site and is part of the rulemaking record.
A. Venting Prohibition and Capture
Targets
As discussed in section III.B.2.a of
this preamble, routine venting and
flaring of gas from oil or gas wells waste
significant volumes of natural gas. In
2014, for example, operators vented
about 30 Bcf and flared at least 81 Bcf
from BLM-administered leases—4.1
percent of the total production from
those leases in that year, and sufficient
gas to supply nearly 1.5 million
households with gas for a year.98 The
final rule aims to reduce this waste
using a two-pronged approach: A
prohibition on venting, and capture
targets to reduce flaring.
1. Venting Prohibition
a. Requirements of Final Rule
First, final rule § 3179.6 prohibits
venting from oil and gas wells, except
under certain enumerated conditions.
The circumstances in which venting is
permissible include: When flaring is
technically infeasible, such as when the
gas is not readily combustible or the
volumes are small; when the gas is
vented during normal operation of an
on-site, gas-activated pneumatic pump
or controller; when the gas is vented
from a storage vessel, provided that
§ 3179.203 does not require flaring of
the gas; when the gas is vented during
downhole well maintenance or liquids
unloading, provided those operations
are conducted in accordance with
§ 3179.204 of the final rule; and when
gas is vented through a leak, provided
that the operator is complying with the
rule’s LDAR provisions in §§ 3179.301–
3179.305. Venting is also permissible
during ‘‘emergencies,’’ which final rule
§ 3179.105 defines as situations in
which the loss of gas is
‘‘uncontrollable,’’ and venting or flaring
is ‘‘necessary to avoid risk of an
immediate and substantial adverse
impact on safety, public health, or the
environment.’’ In addition, venting is
allowed if necessary to allow facility or
pipeline non-routine maintenance to be
performed. Any venting of gas from oil
or gas wells that does not fit within one
of the circumstances listed in § 3179.6 is
a violation of this rule and could result
in enforcement actions. In addition, gas
vented in violation of this rule will be
deemed ‘‘avoidable’’ under final rule
§ 3179.4, and thus subject to royalties
under final rule § 3179.5.
98 BLM analysis of ONRR OGOR–B data provided
for 2009–2015 and EPA GHG Inventory data for
2014.

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b. Changes From Proposed Rule and
Significant Comments
The final venting prohibition largely
tracks proposed section § 3179.6,
although the BLM modified a few
provisions and added additional express
exemptions in response to comments
received. First, proposed § 3179.6(a)(3),
which exempted gas vented from
storage vessels subject to conditions
specified in § 3179.203, has been
renumbered § 3179.6(b)(4) and
reworded for clarity. Second, proposed
§ 3179.6(a)(4), which exempted gas
vented during normal operations of
natural gas-activated pneumatic
controllers and pumps, has been
renumbered § 3179.6(b)(3). Third, the
BLM added a provision, final rule
§ 3179.6(b)(5), to clarify that gas may be
vented during downhole well
maintenance or liquids unloading
activities, provided those activities are
performed in compliance with
§ 3179.204. This change responds to
comments noting that while this rule
requires operators to use best practices
to minimize venting from liquids
unloading operations, these operations
will still release some quantity of gas,
and it is not practical to capture and
flare that gas regardless of whether the
operator uses plunger lifts, manual
purging, or another method to unload
liquids. Fourth, in response to
comments noting that there are
additional losses through venting not
listed in the proposed provision, the
BLM added § 3179.6(b)(6) to the final
rule, to clarify that an operator is not
required to flare gas that is lost due to
leaks, provided the operator is in full
compliance with the leak detection and
repair requirements in final rule
§§ 3179.301–305. Fifth, the BLM added
§ 3179.6(b)(7) to the final rule, to
respond to commenters’ concern that
some gas is released when pressurized
equipment must be depressurized for
maintenance, and their assertion that it
is difficult and costly to route such
infrequent, low-volume emissions to
capture or a flare. This exemption from
the venting prohibition is limited to
venting associated with non-routine
maintenance activities. In justifying
their request for an exemption for
venting associated with maintenance
activities, commenters emphasized that
these activities release only small
quantities of gas in total because they
occur infrequently and each incidence
involves a relatively small volume of
gas. The BLM is aware, however, that
activities such as pigging a gathering
line may release a not insignificant
volume of gas, and, under some
circumstances, operators conduct

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pigging routinely, such as monthly,
weekly, or even several times a day.
Under those circumstances, the BLM
expects that a prudent operator would
configure its operations or deploy
capture or flaring equipment so as to
avoid routine venting, and the final rule
requires operators to avoid such routine
venting. Finally, the BLM added
§ 3179.6(b)(8) to the final rule in
response to commenters’ observations
that it may be necessary to vent gas
when applicable laws, regulations, or
permit terms prohibit flaring in
particular areas or at particular times,
such as flaring prohibitions that may be
imposed in permafrost areas or during
an extreme fire hazard.
2. Capture Targets
a. Requirements of Final Rule
The second prong of the final rule’s
approach to routine venting and flaring
is laid out in final rule §§ 3179.7 and
3179.8, which together target routine
flaring of associated gas from
‘‘development’’ oil wells.99 These final
rule provisions are based on proposed
rule §§ 3179.6(b) and 3179.7,
respectively, but the provisions have
been renumbered and revised in the
final rule in response to numerous
comments received during the public
comment period. This discussion first
describes the approach taken in the final
rule, and then, in part b., details how
this modified approach responds to
comments received.
First, in response to comments, the
final rule shifts from numerical limits
on per-well flaring volumes (the
approach taken in proposed rule
§ 3179.6(b)) to a more flexible approach
modeled in part on existing North
Dakota rules. The new approach sets
targets for the percent of associated gas
from development oil wells that must be
captured in a given month, either on a
per lease/unit/communitized area basis
or averaged over a county or state. The
capture targets do not, however, apply
to the full volume of gas that an operator
flares. Instead, like the proposed rule,
the final rule allows operators to flare a
specified volume of gas that declines
over time. In the final rule, however,
this allowed flaring has been recast as
a ‘‘flaring allowable’’ volume that
operators can subtract from their total
flaring volume prior to calculating their
capture percentage. Overall, then, the
99 As defined in final rule § 3179.3, a
‘‘development’’ oil or gas well is a well ‘‘drilled to
produce oil or gas, respectively, from an established
field in which commercial quantities of
hydrocarbons have been discovered and are being
produced.’’ The BLM retains the authority to
determine whether the well in question is a
development oil or gas well. Id.

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final rule’s approach to flaring has three
parts: Capture targets, which increase
over time; averaging provisions that
allow operators to choose whether to
comply with the capture targets one
lease/unit/communitized area at a time,
or instead on an area-wide average
basis; and finally, a flaring allowable
volume that declines over time, which
operators can subtract from their total
flaring prior to assessing their
compliance with the capture targets.
The mechanics of implementing this
approach are as follows. First, final rule
§ 3179.7 establishes required capture
targets that incrementally increase over
the first nine years of rule
implementation. The schedule for the
capture targets is provided in
§ 3179.7(b)(1)–(4) and reproduced in
Table 1:

TABLE 1

Date range

1/17/2018 through 12/31/2019
1/1/2020 through 12/31/2022 ...
1/1/2023 through 12/31/2025 ...
Beginning 1/1/2026 ...................

Required
monthly
capture
target
(percent of
associated
gas
captured
per month)
85
90
95
98

Section 3179.7(c)(3) of the final rule
then provides that, in order to
demonstrate compliance with the
relevant monthly capture target,
operators must choose the ‘‘relevant
area’’ over which they intend to assess
their capture percentage(s). An operator
may choose whether to comply with the
capture targets on each of the operator’s
leases, units, or communitized areas
(the ‘‘lease-by-lease approach,’’ see final
rule § 3179.7(c)(3)(i)), or instead to
comply on a county-wide or state-wide
basis (the ‘‘averaging approach,’’ see
final rule § 3179.7(c)(3)(ii)). An operator
that chooses the lease-by-lease approach
must demonstrate that each lease, unit,
or communitized area is individually in
compliance with the relevant capture
target each month. An operator that
chooses the averaging approach must
notify the BLM by Sundry Notice of its
choice by January 1 of the relevant year,
and may then demonstrate monthly
compliance with the relevant capture
target on an area-wide average basis.
The second step to demonstrating
compliance with the capture targets,
detailed in final rule § 3179.7(c), is for
an operator to determine its total
volume of gas produced from
development oil wells in the relevant

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area, subtract the flaring allowable
volume, and then divide the result of
that calculation into the total volume of
gas that the operator sold or used, to
determine the operator’s actual capture
percentage. The operator must then
compare its actual capture percentage to
the required gas capture percentage for
the applicable period, to determine
whether the operator meets or exceeds
the required capture target for the given
month.
More specifically, the volume of gas
that the operator sold or used is the
volume of gas that the operator sold
over the month from all of the operator’s
development oil wells in the relevant
area plus the volume of gas that the
operator used on lease, unit, or
communitized area across the relevant
area. The volume of gas flared is the
volume that the operator flared from
high pressure flares over the month in
the relevant area. The flaring allowable
concept derives from the flaring limits
introduced in proposed rule § 3179.6(b),
and it represents the volume of flared
gas that is exempt from the capture
target. Flaring allowable equals the total
number of development oil wells ‘‘in
production’’ 100 in the relevant area
multiplied by the relevant flaring
allowable quantity, which is specified
in final rule § 3179.7(c)(2)(i) through (iv)
and reproduced in Table 2. The final
rule allows an operator to choose
whether to calculate each of these
volumes—the volumes of gas sold, used,
or flared, and the flaring allowable
volume—for each BLM-administered
lease, unit, or communitized area (under
the lease-by-lease approach), or instead
to calculate them on an area-wide
average basis for all BLM-administered
leases, units, and communitized areas in
the county or State (under the averaging
approach).

If the operator’s actual capture
percentage for a given lease, unit, or
communitized area (lease-by-lease
approach), or for the county or State
(averaging approach), falls short of the
required capture target for the given
month, then the operator may face
enforcement action, and must pay
royalties on the excess flared gas, which
is considered avoidably lost. The excess
flared gas is the volume of gas by which
the operator missed its required capture
target, and it is calculated as follows:
Excess flared gas = (Required capture
target * (total volume of produced
gas¥flaring allowable))¥(volume
of gas sold or used).
Royalties on the excess flared gas would
be prorated across an operator’s leases,
units or communized areas that reported
high-pressure flaring during the month.
Alternatively, an operator may request
that the BLM establish an alternative
capture target under final rule § 3179.8,
if three conditions are met: (1) The
operator has chosen to comply with the
capture target using the lease-by-lease
basis rather than the averaging
approach; (2) the potentially
noncompliant lease was issued before
the effective date of this final rule; and
(3) the operator demonstrates via
Sundry Notice, and the BLM agrees, that
the applicable capture percentage under
final rule § 3179.7 ‘‘would impose such
costs as to cause the operator to cease
production and abandon significant
recoverable oil reserves under the
lease.’’
b. Changes From Proposed Rule and
Significant Comments

Proposed rule § 3179.6(b) would have
imposed a monthly limit on flaring,
beginning on the effective date of the
final rule, with the specific limit
decreasing over the first three years of
the final rule. Specifically, the proposed
rule would have established a flaring
TABLE 2
limit of 7,200 Mcf/month per
Monthly
development oil well in production on
flaring
the lease, unit, or communitized area,
Date range
allowable
for the first year the rule was in effect
per well
(proposed rule § 3179.6(b)(1)); 3,600
(Mcf)
Mcf/month per development oil well in
1/17/2018 through 12/31/2018
5,400 production on the lease, unit, or
1/1/2019 through 12/31/2019 ...
3,600 communitized area for the second year
1/1/2020 through 12/31/2020 ...
1,800 the rule was in effect (proposed rule
1/1/2021 through 12/31/2021 ...
1,500
§ 3179.6(b)(2)); and 1,800 Mcf/month
1/1/2022 through 12/31/2023 ...
1,200
1/1/2024 through 12/31/2024 ...
900 per development oil well in production
Beginning 1/1/2025 ...................
750 on the lease, unit, or communitized area
for every month beginning in year three
and thereafter (proposed rule
100 As defined in § 3179.7(c)(4), a well is
§ 3179.6(b)(3)).
considered ‘‘in production’’ after ‘‘a completion, a
The proposed rule included a broad
completion report, or a notice of first production,
request for comments on a range of
whichever occurs first, and only during a month in
issues relating to this section, including:
which it produces gas (that is sold or flared) for 10
or more days.’’
The feasibility and costs of imposing a

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long-term limit on routine flaring of
associated gas from development oil
wells; whether the specific long-term
flaring limit should be lower or higher
than 1,800 Mcf/month/well, to further
reduce flaring or reduce compliance
costs, respectively; operators’ likely
operational response(s) to the
imposition of a flaring limit; the
feasibility and costs of the proposed
three-year timeline for decreasing the
flaring limit from 7,200 to 1,800 Mcf/
month/well; and the effectiveness of the
proposed method and conditions in
§ 3179.7 for allowing operators to obtain
an alternative flaring limit.
The BLM developed the capture target
approach in final rule § 3179.7, and the
alternative capture target provisions in
final rule § 3179.8, after careful
consideration of the many comments
received on the flaring limit approach
set forth in proposed rule §§ 3179.6(b)
and 3179.7. In particular, the BLM gave
careful consideration to operators’
assertions that the numerical values of
the proposed flaring limits, the
proposed schedule for meeting those
limits, and the prescriptive nature of the
limits would make it prohibitively
expensive—and, in some areas of the
country, technically impossible—for
operators to comply with the terms of
the proposed rule. After reviewing the
flaring data provided by these
commenters, obtaining additional
updated and more detailed data from
ONRR, and reanalyzing these
provisions, the BLM determined that the
final rule should phase in its approach
to routine flaring over a longer period of
time, and provide operators with more
flexibility to take better account of
variable conditions on different leases,
units, and communitized areas in
different parts of the country.
The BLM remains committed to
requiring operators to significantly
reduce routine flaring of associated gas
from development oil wells on BLMadministered leases, thereby increasing
gas capture. We have structured final
rule §§ 3179.7 and 3179.8 to achieve a
comparable volume of flaring reductions
as proposed rule §§ 3179.6(b) and
3179.7, although over a somewhat
longer timeframe, and then to achieve
additional reductions in later years.
The final rule’s capture targets and
the proposed rules flaring limits operate
in a similar manner, with the latter
approach a refinement of the former to
enhance opportunities for compliance.
For example, the long-term flaring limit
of 1,800 Mcf/month/well in proposed
rule § 3179.6(b)(3) is exactly equivalent
to a capture target of 100 percent, with
a flaring allowable volume of 1,800 Mcf/
month/well, applied on a lease-by-lease

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basis. The final rule phases in a 98
percent (rather than 100 percent)
capture target over nine years, and
converts the proposed volumetric
flaring limits from the proposed rule
into declining allowances against the
capture target. The differences between
proposed rule § 3179.6(b) and final rule
§ 3179.7(b) are therefore more a matter
of form than function, with the final
rule designed to achieve flaring
reductions comparable to the reductions
that the BLM expected from the
proposed rule, but to allow operators
more compliance flexibility.
That said, the proposed and final
approaches to reducing routine flaring
do differ in certain key respects, as a
result of public comments. The five
most significant differences are as
follows.
First, the final rule uses specified
capture targets, rather than requiring
that operators capture 100 percent of
their associated gas above fixed
volumetric limits as initially proposed,
in response to comments indicating
that, in some states (notably North
Dakota and New Mexico), gas volumes
are so high and the availability of
capture infrastructure so variable that it
is extremely difficult to identify a fixed
volumetric limit on flaring that would
both be achievable and also provide
meaningful reductions in all States.
Commenters asserted that given the high
gas-to-oil ratios (GOR) in the Bakken
basin, there are certain areas where an
operator could exceed the proposed
flaring limit of 1,800 Mcf/month/well in
a period of hours. Commenters argued
that even after averaging over a month
and across a lease, as the proposed rule
would have allowed, the 1,800 Mcf/
month/well limit would significantly
impact future development in the
Bakken and Permian basins. Operators
in these areas suggested that allowing
averaging of flaring volumes across
multiple leases, units, or communitized
areas—or even across counties or across
a State—would enable operators to use
high capture rates in areas with low
GOR and/or significant gas capture
capability to offset lower capture rates
in other areas, and thereby avoid having
to curtail production.
Based on these concerns, the BLM
restructured the fixed flaring limits as
capture targets both to better take
account of geographically varying
volumes of associated gas and to allow
operators some greater flexibility to
absorb the impacts of intermittent
interruptions or reductions in capture
capacity. Final rule § 3179.7, therefore,
requires capture of a specified
percentage of gas above the flaring
allowable volume; this specified capture

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target incrementally increases from 85
percent in year two (e.g., one year after
the effective date of the final rule) to 98
percent in year nine. As noted, this
flexible capture target approach is
modeled in large part on North Dakota’s
regulations, which also impose an
escalating capture target, as described in
the preamble to the proposed rule.101
Second, the BLM extended the
compliance dates in response to
commenters’ concern that coming into
compliance with a long-term flaring
limit of 1,800 Mcf/month/well would
take longer than the three years that the
BLM had proposed. The final rule
postpones the effective date of any
capture requirements for one full year
after the effective date of the rule.
Thereafter, the final rule incrementally
increases the required capture targets
over a nine year period and
incrementally decreases the flaring
allowable volumes over an eight year
period. Final rule § 3179.7(b) extends
the time an operator has to meet the
flaring allowable volume of 1,800 Mcf/
month/well until calendar year 2021,
about four years after the effective date
of the final rule (and about two
additional years after the 1,800 Mcf/
month/well fixed flaring limit would
have taken effect under § 3179.6(b)(3) of
the proposed rule).
Third, and conversely, the BLM has
reduced the long-term flaring allowable
volumes that apply once the final rule
is fully phased in, in response to other
commenters’ concerns that the proposed
approach allowed significant quantities
of wasteful flaring to continue unabated
from 2020 on and did not provide
sufficient incentives for industry to
continue to decrease flaring over time.
Natural gas is a valuable resource that
should be put to productive use, and the
MLA requires that we minimize the
waste of public resources, consistent
with existing lease obligations. In
addition, if the only changes the BLM
made to the final rule were to allow
averaging over a broad geographic area
and to impose capture targets that never
ramp up to 100%, the final rule would
achieve far less of a reduction in
wasteful flaring than the proposed rule.
While providing operators more
flexibility to reduce flaring at lower
costs by shifting from the proposed
rule’s fixed flaring limits to the final
rule’s capture targets and allowable
flaring volumes, the BLM strived to
ensure that the final rule still achieves
meaningful flaring reductions,
comparable to the reductions that the
BLM expected from the proposed rule.
The key change necessary to meet that
101 81

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goal was the shift from a fixed long-term
flaring limit of 1,800 Mcf/month/well
(proposed rule § 3179.6(b)(3)) over three
years to a flaring allowable volume that
decreases over time to 750 Mcf/month/
well in year 2025 (final rule
§ 3179.7(c)(2)(iv)).
Fourth, the final rule allows greater
flexibility in how operators may comply
with the capture targets. Commenters
indicated that leases, units, and
communitized areas vary greatly in both
the volumes of associated gas produced
from oil wells and the availability of gas
capture infrastructure, and asserted that
complying with a single flaring limit
that applies uniformly to every lease,
unit, and communitized area would be
prohibitively expensive or even, in
some areas of the country, technically
impossible. Commenters contended that
as a result, they would be forced to
submit numerous Sundry Notices under
proposed rule § 3179.7 to request
alternative flaring limits. Commenters
asserted that North Dakota’s approach,
which allows operators to comply with
capture targets on a statewide average
basis, would reduce the need to request
alternative limits and thus achieve
comparable overall flaring reductions at
significantly lower cost. The BLM
agrees, and has in response to these
comments structured the final rule to
provide operators with greater
discretion in how they choose to
comply. Specifically, final rule
§ 3179.7(c)(3) allows an operator to
choose whether to comply with the
capture targets on a county- or statewide average basis, or instead to comply
on each lease, unit, or communitized
area. This flexibility, too, is modeled on
North Dakota’s regulations, which allow
for compliance on a well-, field-,
county- or state-wide basis, as described
in the preamble to the proposed rule.102
Fifth and finally, the final rule makes
certain changes to the alternative flaring
provisions (proposed rule § 3179.7,
renumbered as final rule § 3179.8) in
part to address some commenters’
concerns that the proposed renewable 2year exemption (proposed rule
§ 3179.7(d)) would allow too many
operators to evade the flaring limits and
should therefore be eliminated. The
changes also account for the change in
the final rule from flaring limits to
capture targets, and for the BLM’s
decision to allow operators to choose to
demonstrate compliance with the
capture targets on an area-wide average
basis. Specifically, the BLM deleted the
proposed 2-year exemption provision
and restyled proposed rule § 3179.7 as
an alternative capture target rather than
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an alternative flaring limit. The change
to a capture target approach and the
decision to allow operators to choose to
comply by averaging their flaring over
an entire county or State significantly
reduce the risk that a single remote
lease, unit, or communitized area with
high levels of flaring and little or no
access to capture infrastructure will
make it impossible for an operator to
comply. Under the averaging approach,
such leases, units, or communitized
areas need not receive a blanket
exemption from the capture target.
Rather, an operator concerned about the
ability of a lease, unit, or communitized
area to comply with the capture target
can either (a) reduce its flaring at other
sites in the relevant area to compensate
for the high levels of flaring at that
remote lease, or (b) apply for an
alternative capture target for that lease
under final rule § 3179.8 (if the
predicate conditions are met). Because
fewer leases are likely to raise such
concerns under the final rule’s capture
target approach than under the
proposed rule, the BLM anticipates
receiving fewer requests for alternative
capture targets and having an increased
capacity to process such requests on a
case-by-case basis.
To set the capture targets and flaring
allowable volumes in the final rule, the
BLM conducted a detailed analysis of
2015 data submitted to ONRR of sales,
on lease use and flaring volumes monthby-month for operators within a state.
These data go substantially beyond what
was available to BLM in preparing the
proposed rule, and while the results
show that the proposed rule would have
reduced flaring less than we initially
estimated, we have higher confidence in
the updated estimates. Using the new
data to reanalyze the likely flaring
reductions from the proposed rule, the
BLM estimates that the proposed rule
would have reduced the quantity of
flared gas in 2020 by 42 percent relative
to 2015 levels.
Using the same data and assumptions,
the BLM estimates that the final rule’s
approach, which allows operators to
average over their statewide production
and establishes a capture target of 98%
over time, will reduce the quantity of
flared gas in 2020 by roughly 26 percent
relative to 2015 levels. With the
additional time and flexibility provided
in the final rule, operators will be able
to plan for and build out the additional
infrastructure necessary to capture and
transport greater volumes of gas in later
years. Thus, the final rule further steps
down the allowable flaring volumes
after 2020, and likewise steps up the
required capture percentages, to achieve
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2025, 8 years after the rule comes into
effect.
Thus, the BLM expects that the final
rule’s schedule and targets for reducing
flaring will achieve a total volume of
flaring reductions somewhat greater
than the proposed rule, and at lower
cost, though over a longer timeframe.
Moreover, the final rule establishes a
structure in § 3179.7 for reducing
routine flaring that could be adapted to
achieve more ambitious flaring
reductions, if and when the BLM deems
those reductions to be technologically
feasible and cost effective. The BLM has
only specified capture targets and
flaring allowable volumes out to 2026.
As additional data on flaring become
available, and capture technologies
improve, the BLM could choose to
increase the capture targets further over
time, and/or decrease the flaring
allowable volumes, through future
rulemakings in order to continue to
reduce routine flaring of associated gas
from BLM-administered leases, units,
and communitized areas, consistent
with the United States’ March 2016
endorsement of the World Bank’s Zero
Routine Flaring by 2030 Initiative.103
B. Leak Detection and Repair
1. Requirements of Final Rule
As discussed in detail in the RIA, we
estimate using data from the EPA GHG
Inventory that about 4.01 Bcf of natural
gas was lost in 2014 as a result of leaks
or other fugitive emissions from various
components, including valves, fittings,
pumps, storage vessels and compressors
on well site operations on BLMadministered leases.104 This quantity of
gas would supply nearly 55,000 homes
each year.105
LDAR programs are a cost-effective
means of reducing waste of gas in the oil
and gas production process, as indicated
by the studies and State programs
discussed in the proposed rule, as well
as additional information provided
since the proposal, which is discussed
in the background section III. Provisions
in §§ 3179.301 through 3179.305 of the
final rule require operators to carry out
leak inspections and repairs at their
well sites and associated equipment,
103 ‘‘Zero

Routine Flaring by 2030’’ is a voluntary
initiative introduced by the World Bank in 2015
and endorsed by multiple governments, oil
companies, and development institutions. The
initiative focuses on the phase-out of routine, highpressure flaring of the type addressed by the BLM’s
capture targets in § 3179.7 of the final rule, not
flaring for safety and other non-routine reasons. For
more information and a list of endorsers, see http://
www.worldbank.org/en/programs/zero-routineflaring-by-2030.
104 RIA at 17.
105 Based on an estimate of 74 Mcf of gas used
per household per year. See footnote 2.

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meeting specified standards for leak
detection methodology and frequency,
and for the timing of repairs. Within one
year of the effective date of the rule (or
within 60 days of beginning production,
for new sites), operators must use an
instrument-based approach to conduct
semi-annual inspections at well sites
and quarterly inspections at compressor
stations. Operators may also request
BLM approval of an alternative
instrument-based leak detection
program, which the BLM may approve
if it finds that the program would
reduce leaked volumes by at least as
much as the BLM program. Operators
must repair a leak within 30 days of
discovery, absent good cause, and verify
that the leak is fixed. Operators must
also keep records documenting the dates
and results of leak inspections, repairs,
and follow-up inspections, and submit
annual reports with this information.
Section 3179.301 provides that the
leak detection requirements in the final
rule apply to sites 106 and associated
equipment that is used to produce,
process, compress, treat, store, or
measure natural gas from or allocated to
a Federal or Indian lease (or from a unit
or communitized area that includes
such a lease), where such sites are
upstream of or contain the approved
royalty point of measurements. These
requirements also apply to each site
located on a Federal or Indian lease, and
all associated equipment operated by
the operator, which is used to store,
measure, or dispose of produced water.
An operator is not required to inspect
sites that contain only a wellhead or
wellheads and no other equipment, nor
is the operator required to inspect the
‘‘leak components’’ 107 that are not
accessible
In response to multiple requests from
industry and NGO commenters, the
final rule provides greater specificity on
what constitutes a ‘‘leak’’, which
includes releases not associated with
the normal operation of the component
(e.g., releases from equipment designed
to vent that exceed the quantities and
frequencies expected during normal
operation of the equipment). Similarly,
106 A ‘‘site’’ is defined as a discrete area
containing a wellhead, wellhead equipment, or
other equipment used to produce, process,
compress, treat, store, or measure natural gas or
store, measure, or dispose of produced water, which
is suitable for inspection in a single visit.
107 Under the definitions in the final rule, ‘‘leak
component’’ means any component that has the
potential to leak gas and can be tested in the
manner described in sections 3179.301 through
3179.305 of this subpart, including, but not limited
to, valves, connectors, pressure relief devices, openended lines, flanges, covers and closed vent
systems, thief hatches or other openings on a
storage vessel, compressors, instruments, and
meters.

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releases due to operator error or
equipment malfunctions, or from
control equipment that does not meet
the level of control required by this or
other regulations, are also considered
leaks. These types of leaks include
releases from: A thief hatch left open; a
vapor recovery unit that is not operating
properly; a tank or combustor that is
inadequately sized to handle the
throughput of gas; or an intermittent
controller that actuates continuously.
Section 3179.301(j) and (k) integrate
the final rule with EPA NSPS
requirements for operators to conduct a
fugitive emissions inspection and repair
program. Section 3179.301(j) provides
that for new, modified or reconstructed
equipment, an operator will be deemed
to be in compliance with the BLM
LDAR requirements if the operator is in
compliance with the EPA subpart
OOOOa requirements applicable to the
equipment. Paragraph (k) further allows
an operator to choose to comply with
the EPA fugitive emissions monitoring
requirements in subpart OOOOa and
apply those requirements to all sites and
equipment on a lease not already
deemed in compliance with the BLM
LDAR provisions, in lieu of complying
with the BLM LDAR provisions. This
provision allows an operator with new,
modified or reconstructed facilities
(which must comply with subpart
OOOOa) as well as existing facilities
(which are not subject to subpart
OOOOa) to apply a single leak detection
regime to all of their facilities, rather
than complying with subpart OOOOa
for some facilities and the BLM
requirements for others.
The final BLM LDAR provisions also
apply to a few specific types of
equipment that EPA addresses under
requirements that are separate from
EPA’s subpart OOOOa fugitive
emissions program—specifically, certain
covers and closed vent systems, and
thief hatches or other openings on
controlled storage vessels, which are
covered under 40 CFR 60.5411a or
60.5395a, rather than under the fugitive
emissions requirements in subpart
OOOOa. The final rule provides that if
an operator chooses to comply with the
EPA subpart OOOOa fugitive emissions
requirements in lieu of the BLM LDAR
requirements for all equipment on a
lease, the operator must apply the EPA
fugitive emissions requirements to
sources covered under 40 CFR 60.5411a
or 60.5395a as well.108 Absent this
requirement, these equipment covers,
108 See Section VII, Section by Section, for
discussion of treatment of sources exempt from the
EPA fugitive emissions program specified in section
43 CFR 60.5397a.

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closed vent systems, and openings on
controlled storage vessels would not be
subject to the BLM’s LDAR
requirements or the EPA’s subpart
OOOOa fugitive emission inspection
requirements if the operator chose to
comply with the EPA requirements in
lieu of the BLM requirements.
The final rule requires operators to
use an instrument-based approach to
leak detection. This is consistent with
the proposed rule, and with EPA,
Colorado, and Wyoming leak detection
requirements. Under final rule
§ 3179.302, operators must use an
optical gas imaging device (also
commonly referred to as an infrared
camera), or a portable analyzer device
capable of detecting leaks and used
according to the specifications of
Method 21, a protocol prescribed by
EPA for effectively using these
devices.109 Use of a portable analyzer
device must also be assisted by audio,
visual, and olfactory (AVO) inspection,
as these devices have much more
narrowly-focused leak detection
capabilities compared to optical gas
imaging, which can be used to scan
across broad arrays of equipment. The
final rule includes specifications for
acceptable optical gas imaging
equipment, requires all instruments to
be used according to the manufacturer’s
specifications, and requires the operator
of any leak detection instrument to be
adequately trained in its proper use.
Final section 3179.302 also allows
any person to request and the BLM to
approve the use of an alternative
monitoring device, accompanied by a
monitoring protocol, and, in response to
comments, this section also details the
information that must be included in a
request. The BLM may approve an
alternative leak detection device and
inspection protocol, if the BLM finds
that the alternative would achieve equal
or greater reduction of gas lost through
leaks, compared with optical gas
imaging used as required. The BLM may
approve the device for use for all or
most applications, or may approve use
on a pilot project or demonstration
basis. Finally, the BLM will provide
public notice of a request for approval
of an alternative monitoring device and
will post on the BLM Web site a list of
each approved monitoring device and
protocol, along with any limitations on
its use. The BLM intends that the
decision to approve the use of an
alternative monitoring device would be
made only at the national level, by the
Director, Deputy Director, or an
Assistant Director, as, once approved,
109 See

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the alternative monitoring device could
be used anywhere in the country.
Section 3179.303 specifies the
required frequency for inspections,
which is fully aligned with the
requirements of Subpart OOOOa.
Operators must inspect each well site at
least semi-annually, with consecutive
inspections spaced at least four months
apart. Operators must inspect each
compressor station at least quarterly,
with consecutive inspections spaced at
least 60 days apart.
In addition to alternative monitoring
devices, the final rule allows for BLM
approval of alternative monitoring
programs. Specifically, like the
proposed rule, the final rule allows an
operator to request the BLM to approve
an alternative instrument-based leak
detection program in place of the
program specified in the regulations.
The BLM may approve the alternative
program if it finds that the alternative
program would achieve equal or greater
reduction of gas lost through leaks
compared with the approach specified
in the regulations. Because approval of
inadequate alternative programs could
unintentionally but significantly
undermine the effectiveness of the
LDAR requirements, the BLM intends
that the decision to approve an
alternative program would be made only
by the relevant BLM State Director, or,
with respect to requests that cover
operations in more than one State, at the
national level by the BLM Director,
Deputy Director, or an Assistant
Director. In addition, the BLM will post
approved alternative programs online
both to provide public transparency and
to allow other operators to see examples
of alternative programs that the BLM
believes will be effective.
Section 3179.304 requires operators to
repair the leaks that they find. Operators
must repair a leak as soon as
practicable, and within 30 days of
discovery, unless there is good cause to
delay the repair. When an operator
repairs a leak, the operator must verify
that the repair was effective within 30
days of the date of the repair using
optical gas imaging, a portable analyzer
using Method 21, or a soap-bubble test.
Section 3179.305 requires operators to
keep records related to leak detection
inspections and repairs, make them
available to the BLM upon request, and
submit an annual summary report on
the previous year’s inspection activities.
2. Changes From Proposed Rule
The final rule provisions on leak
detection and repair largely track the
proposal, however, we adjusted the
frequency of inspections, based upon
public comments along with a desire to

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align these requirements with EPA’s
final rule, and made other minor
adjustments. The BLM had proposed an
approach in which the initial required
frequency of inspection was semiannual, but then the frequency varied
for each site according to the number of
leaks found. An operator that found
more than three leaks in each of two
inspections would have been required
to increase its inspection frequency to
quarterly, while an operator that found
fewer than three leaks in each of two
inspections would have been allowed to
drop its inspection frequency to
annually. A broad swathe of
commenters opposed this approach in
the proposed rule (as well as in the
EPA’s proposed OOOOa). The final rule
replaces this approach with a fixed
semi-annual rate of inspections for all
sites other than compressor stations,
and a quarterly inspection rate for
compressor stations, consistent with the
final OOOOa as well.
Another change from proposed to
final rule concerns the effective date of
the leak detection requirements. The
proposed rule would have imposed the
leak detection requirements as of the
effective date of the rule, with the first
inspection required within six months
of that date. In response to comments,
the final rule extends the time for initial
compliance to give operators one year
from the effective date of the rule to
make their first inspection.
The BLM made several other changes
that adopt commenters’ suggestions. We
added a provision allowing approval of
an alternative, potentially less effective,
leak detection program for an operator
that demonstrates that compliance with
the LDAR requirements would impose
such costs as to cause the operator to
cease production and abandon
significant recoverable oil or gas
reserves. We also added a requirement
that operators provide an annual
summary report on the results of their
leak inspections. Consistent with the
final subpart OOOOa, the final rule also
includes a new exemption from LDAR
requirements for sites that contain only
a wellhead(s), and no other equipment.
In addition, the BLM made various
smaller changes to enhance the clarity
of the final rule. The final rule has
refined and clarified the specific sites
and equipment subject to the leak
inspection requirements. The final rule
applies to all equipment handling
Federal or Indian gas, upstream of and
including the site where the royalty
measurement point is located—whether
the equipment is on or off the lease and
regardless of the ownership of the
equipment. The final rule also specifies
that with respect to equipment

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associated with the storage,
measurement, or disposal of produced
water, the leak detection requirements
apply only to such equipment operated
by the operator and located on the
Federal or Indian lease.
The final rule retains and refines the
proposed rule’s provision allowing an
operator to satisfy the leak detection
requirements by complying with the
EPA leak detection requirements under
40 CFR part 60, subpart OOOOa. First,
the final rule provides that for new,
modified and reconstructed equipment,
an operator that is in compliance with
the EPA fugitive emissions requirements
will be deemed to be in compliance
with the BLM LDAR requirements,
without any requirement to file a
Sundry Notice and demonstrate
compliance, as the BLM had proposed.
Second, it clarifies that that an operator
who chooses to comply with the EPA
fugitive emissions monitoring
requirements in subpart OOOOa in lieu
of the BLM LDAR requirements must
apply the EPA requirements to all sites
and equipment on a lease not already
deemed in compliance with the BLM
LDAR provisions.
The final rule includes this change
because leaks from some types of new,
modified and reconstructed equipment,
such as covers and closed vent systems,
and thief hatches on controlled storage
vessels, are not covered by the fugitive
emissions requirements under subpart
OOOOa, but instead are addressed
through specific provisions for storage
vessel affected facilities and any
associated covers and closed vent
systems in subpart OOOOa—namely 40
CFR 60.5395a and 60.5411a. These
provisions establish comprehensive
control programs for storage vessel
affected facilities, including separate
and distinct inspection regimes. This
final rule ensures that if an operator
elects to comply with the EPA fugitive
emissions requirements in lieu of the
BLM leak detection requirements for
equipment on a given lease, the operator
must apply the EPA fugitive emissions
requirements to all equipment covered
by the BLM leak detection requirements,
including equipment such as covers,
closed vent systems, and thief hatches.
Absent this provision, operators could
potentially avoid any leak detection
program with respect to existing sources
in these categories.
The final rule also modifies the
requirement in the proposed rule that
operators who choose to comply with
the EPA requirements in lieu of the
BLM requirements must file a Sundry
Notice demonstrating compliance with
the EPA rule. The final rule provides
that the operator need only notify the

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BLM through a Sundry Notice that it is
complying with the EPA rule in lieu of
the BLM requirements for equipment on
a lease. While the BLM needs to know
for oversight purposes if an operator has
elected not to comply with the BLM
requirements, we agree with
commenters that requiring a
‘‘demonstration’’ of compliance with the
EPA requirements is unnecessary.
As noted earlier, the final rule also
contains a more detailed definition of a
‘‘leak’’ than the proposed rule, as well
as more detailed specifications of
approved leak detection instruments
and methods. In addition, the final rule
separates approval of an alternative
monitoring device and protocol from
approval of an operator’s alternative
leak detection program, and it adds
specificity on what is required for each
of these. The final rule also adds a
required minimum interval between
inspections, which was not specified in
the proposal, but is consistent with final
subpart OOOOa. Other minor changes
that align the rule with final subpart
OOOOa include: A 30- rather than 15day period for repair and follow-up
inspections; additional detail on what
constitutes good cause for delay of
repair; and a new, two-year outer limit
on the timeline for completing repairs
delayed for good cause. In addition,
while the proposal had required
operators to verify the effectiveness of
repair using the same method used to
identify the leak, in response to
comments, the final rule allows
operators to use any approved
monitoring instrument or the soap
bubble test to verify the effectiveness of
repair.
3. Significant Comments
Commenters provided many detailed
comments on numerous aspects of the
leak detection program. This section
highlights the most significant
comments; additional comments are
addressed in Section V. and the
Response to Comments document.
Comments addressed here include:
Coverage of the program (i.e., which
types of operations and equipment
should be included in the program);
program structure (how inspection
frequency is to be determined, and the
required frequency of inspection); the
instruments and methods to be used for
leak detection; opportunities for use of
new instruments and methods;
requirements for repairs; and potential
exemptions from the requirements.
a. Coverage
Comments: Many commenters
addressed the coverage of the program.
Some commenters supported applying

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the program broadly to catch as many
leaks as possible, while others urged the
BLM to use risk-based or other
approaches to target the program more
narrowly to exclude certain types of
sites and equipment and/or to focus on
the most likely sources of significant
leaks and improve the program’s costeffectiveness.
Some commenters urged the BLM to
exclude sites where the commenters
asserted that there is less likelihood of
leaks and/or smaller leaks. For example,
they suggested excluding oil or gas low
production wells (also commonly called
‘‘marginal’’ or ‘‘stripper’’ wells) that
produce less than 15 barrels of oil
equivalent per day; oil well sites that
produce crude oil with either an API
gravity less than 18° or a GOR less than
300 scf/bbl; and sites that have just
wellheads without co-located
production equipment.
Some commenters alleged that wells
producing less than 15 BOE per day do
not have the potential to emit at the
same rate as larger producing facilities
or enough production to have
significant waste from leaks. Hence,
they argued, the costs of LDAR for a
marginal well far outweigh any benefits
in terms of recovery of lost gas. One
commenter stated that sites with
marginal wells have less equipment onsite, fewer components that could leak,
and thus a smaller likelihood of leaks.
Commenters also noted that the EPA
proposed to exclude low production
wells from its fugitive emissions
program, and argued that the BLM
should do the same. Some asserted that
these wells are only marginally
profitable to begin with, and the costs of
LDAR could make these wells
uneconomical, leading to premature
shut-in and a loss of mineral resources.
Commenters also recommended that, at
minimum, these low production wells
should be subject to more relaxed LDAR
requirements, such as one-time or
annual instrument-based inspections,
possibly in combination with AVO
inspections, rather than semi-annual
instrument-based inspections.
Commenters also asserted that the
requirement to inspect for leaks should
be limited to certain specified facilities
or components because those facilities
or components are more likely to leak,
and to have higher leak rates. Various
commenters recommended that the rule
focus on valves, open-ended lines,
pumps, or components with potential to
operate at or above sales line pressure.
Other commenters suggested limiting
the LDAR requirements to facilities with
components that tend to vibrate or are
in thermal operation, and specifically
those with controlled storage vessels,

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compressors, and/or vapor recovery
units. Commenters also asserted that the
2013 Carbon Limits Study and the 2014
CAPP study show that compressor
stations leak more than well sites, and
that components tend to have greater
average emissions when subjected to
frequent thermal cycling, vibrations or
cryogenic service.
In addition, commenters urged the
BLM to exclude from the LDAR
requirements storage vessels that would
not be required to have emission
controls under the proposed BLM and
final EPA rules (i.e., tanks with the
potential to emit less than 6 tpy of
VOCs), and equipment designed to vent,
such as pneumatic pumps and
pneumatic controllers, as well as other
types of equipment and sites discussed
in Section V.
On the other hand, other commenters
strongly opposed narrowing the
applicability of the LDAR program, and
in particular, excluding low production
wells from that program. These
commenters cited recent peer-reviewed
studies concluding that the occurrence
of leaks is fairly random; the probability
of a production site being among the
highest emitting sites does not increase
uniformly with production volumes;
and relatedly, both high- and lowproducing sites can be associated with
high-emitting events. These commenters
provided estimates of calculated
methane emissions from low production
and non-low production wells
nationwide based on data reported to
EPA and the EPA GHG Inventory,
finding that 83 percent of the total
methane emissions from oil and gas
wells was attributable to low production
wells, while only 17 percent was
attributable to other wells. The
commenters also provided calculations
based on an EPA estimate of the cost of
semi-annual inspections. These
calculations showed, the commenters
argued, that even for low production
wells, the cost of LDAR compliance
would on average be only a small
fraction of the annual revenue per well.
These commenters further argued that
the majority of all existing wells,
including those on public lands, meet
the definition of ‘‘marginal,’’ and that
excluding such wells from the LDAR
requirements would allow large
amounts of gas waste to continue
unabated.
Response: The final rule covers
largely the same types of sites and
equipment as the proposed rule, with a
few small exceptions. As discussed
above, natural gas leaks during the oil
and gas production process are wasteful
and can cause significant environmental
harm. The BLM is adopting a broadly

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83029

applicable LDAR requirement to reduce
leaks as much as reasonably possible.
The BLM carefully considered
numerous and varied approaches that
might improve the program’s costeffectiveness by narrowing the coverage
of the LDAR program while maintaining
its benefits. In evaluating suggestions to
exclude certain types of sites from the
LDAR requirements, the BLM looked for
evidence indicating that the frequency
of leaks, size of leaks, and overall
amounts of gas lost through leaks relate
to the type of site being inspected. In
requesting comments on this topic, the
BLM had urged commenters to present
data or other information to support
their assertions, and specifically
requested ‘‘information regarding the
relationship between well production
and levels of leaked methane from a
site.’’ 110
With respect to suggestions that the
BLM exclude low production wells from
the LDAR requirements, we note that
roughly 85 percent of wells on Federal
and Indian leases are classified as low
production wells (i.e., produce 15
barrels of oil equivalent per day or less).
Thus, unless these wells are, in fact,
unlikely to leak significant volumes of
gas, a decision to exclude these wells
from the LDAR program would have a
significant negative effect on the waste
reduction benefits of this rule.
The information submitted by
commenters on low production wells
does not support their exclusion from
the LDAR requirements. As discussed
above, some commenters suggested,
without providing supporting data, that
sites with low production would be
expected to lose smaller quantities of
gas overall from leaks. However, others
disagreed, pointing to the Zavala-Araiza
study. As discussed in section III, this
study showed that the probability of a
production site being among the highest
emitting sites does not increase
uniformly with production volume, and
it found significant opportunities to
reduce losses by finding and fixing leaks
at lower production wells. These
commenters noted that the Lyon et al.
study also demonstrates that both highand low-production sites can be
associated with high-emitting events
with roughly 15 percent of the
identified high-emissions sites in that
study being associated with low
production wells. Commenters urging
an exclusion for low production wells
did not provide data refuting these
findings. Without additional data on
this issue, the BLM simply cannot
conclude that low-production sites pose
110 Proposed

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low leak risks and therefore merit
exclusion from semi-annual LDAR.
As commenters noted, the EPA had
proposed to exclude wells with less
than 15 barrels a day oil-equivalent
production from the OOOOa fugitive
emissions requirements. In the final
OOOOa rule, however, the EPA reached
the same conclusion as the BLM and
dropped the proposed exemption. EPA
found that the record for the final rule
did not support excluding these wells
from the fugitive emissions
requirements. In the preamble to the
final rule, EPA stated: ‘‘We did not
receive data showing that low
production well sites have lower GHG
(principally as methane) or VOC
emissions other [sic] than non-low
production well sites. In fact, the data
that were provided indicated that the
potential emissions from these well sites
could be as significant as the emissions
from non-low production well sites
because the type of equipment and the
well pressures are more than likely the
same.’’ 111 Thus, including low
production wells under the BLM
requirements also maintains consistency
between the BLM and EPA rules.
In addition, the BLM does not
anticipate a significant number of
individual well shut-ins or any leasewide shut-ins as a result of the LDAR
requirements, even with respect to low
production wells. As discussed in the
RIA, third-party providers offer LDAR
services at a relatively modest cost, and
operators may recoup some of the costs
of the program through the saved gas.
Also, operators have the option to
design and request approval of an
alternative LDAR program that is less
costly for their particular circumstances,
provided they can demonstrate that
their alternative program is equally
effective. Finally, an operator may
request approval of an alternative leak
detection program that is not as effective
as the BLM’s requirements, if the
operator demonstrates that compliance
with the BLM’s LDAR requirements or
an equally effective alternative would be
so costly as to cause the operator to
cease production and abandon
significant recoverable oil or gas
reserves under a lease.
With respect to oil well sites that
produce crude oil with either an API
gravity less than 18° or a gas-to-oil ratio
(GOR) less than 300 scf/bbl, as with low
production wells, the BLM does not
have data to be able to conclude that
these oil well sites are likely to be
responsible for a sufficiently small
quantity of gas lost through leaks that
they should be excluded from the LDAR
111 81

FR at 35856.

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requirements or subject to less stringent
requirements.
The BLM does, however, agree with
commenters that the risk of leaks is
substantially lower at sites with only a
wellhead, compared to sites with one or
more pieces of production equipment,
such as a tank, compressor, dehydrator,
or vapor recovery unit. Industry
commenters asserted that there is a
greater likelihood of leaks from moving
or vibrating equipment, or from
equipment in thermal operation,
because a valve may stick open,
vibrations may cause a connection to
loosen, or heat may cause a seal to
degrade. While the BLM does not have
data about the likelihood and/or size of
leaks in these circumstances, the BLM’s
experience in the field supports the
general point. In addition, studies have
identified many leaks from the
identified equipment, including tanks,
compressors, and dehydrators.112 At a
wellhead without co-located production
equipment, there are significantly fewer
components capable of leaking.
Exempting these sites from the LDAR
requirements will provide some cost
savings for operators, and based on the
information available, the BLM believes
that realizing those savings will have
only a minimal impact on the overall
benefits of the LDAR program.
Moreover, excluding wellhead-only
sites is directionally consistent with
some of the other suggestions for
narrowing program applicability, such
as focusing on sites with tanks or
compressors. In the final OOOOa rule,
the EPA reached the same conclusion
and exempted wellhead-only sites from
its fugitive emissions requirements.
Other than the exclusion for sites with
only a wellhead, the BLM is not limiting
the LDAR requirement to covering only
certain specified types of equipment or
equipment components. BLM does not
believe that it has sufficient information
to appropriately distinguish between
types of production equipment or
equipment components on the basis of
the likely quantity of gas lost through
leaks. In addition, once an operator is at
a site conducting a leak detection
inspection, inspecting all of the on-site
equipment should add little time and
cost, particularly when the operator is
using optical gas imaging. The BLM
believes that trying to identify and
exclude specific types of equipment
from inspection adds complexity to the
inspection system and introduces the
112 See, e.g., Warneke, C., Geiger, et al.: Volatile
organic compound emissions from the oil and
natural gas industry in the Uintah Basin, Utah: oil
and gas well pad emissions compared to ambient
air composition, Atmos. Chem. Phys., 14, 10977–
10988, doi:10.5194/acp-14-10977-2014, 2014.

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likelihood of errors that would allow
leaks to escape detection. It is simpler
and more effective for operators simply
to inspect all of the equipment located
at a site. If, however, an operator has
data that show it is possible to conduct
an equally effective LDAR monitoring
program while excluding certain types
of equipment, or sites that only have
that type of equipment, the operator
may submit a proposed alternative
monitoring protocol to BLM for review
and potential approval.
Some commenters pointed out that
pneumatic controllers are designed to
vent and argued that these releases
should not be considered leaks. The
BLM agrees, and has excluded normal
operation of this equipment from the
final rule’s leak definition. The BLM
notes, however, that pneumatic
controllers can and do malfunction,
such as getting stuck in an open
position, which can lead to unnecessary
losses of gas. Additionally, as other
commenters stated, these malfunctions
can be identified through leak
inspections. The BLM, therefore,
believes it would be inappropriate to
exclude this equipment from the rule’s
LDAR requirements.
Commenters make similar arguments
with respect to uncontrolled storage
vessels (i.e., tanks that are not required
to capture or flare their releases), which
are allowed to release up to 6 tons per
year of VOCs. Commenters argued that
venting from an uncontrolled tank is
necessary for proper relief of
overpressure. Again, the BLM believes
that the commenters’ concerns should
be addressed through the definition of a
‘‘leak,’’ which now excludes releases
due to normal operation of a storage
vessel or pressure relief valve, rather
than by removing uncontrolled storage
vessels from coverage under the LDAR
program.
As an initial point, uncontrolled tanks
are not open to the atmosphere—rather,
they are typically vapor tight, slightly
pressurized, and equipped with a thief
hatch to allow measurement of
production and a pressure relief valve to
allow gas release of overpressure. This
standard industry practice, which
preserves the product and prevents
unlimited release of vapors, was
recently reinforced in the BLM’s oil
measurement rule, 43 CFR subpart 3174.
The oil measurement rule requires oil
storage tanks, hatches, connections, and
other access points to be vapor tight,
and it sets specifications for pressure
relief valves. Using leak inspections to
ensure that thief hatches are closed,
seals are sound, and pressure relief
valves are operating properly will
reduce waste of gas.

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Moreover, as discussed in section III.,
recent studies indicate that tanks are a
very significant source of lost gas. As
noted earlier, the Lyon et al. study, a
helicopter survey of over 8,000 oil and
gas wells, reported that over 90 percent
of the detected emission incidences
were from tanks. Similarly, the Colorado
State University studies found
substantial venting at tanks, and the
City of Fort Worth study found that thief
hatches are the largest source of fugitive
emissions. The BLM believes that
including both controlled and
uncontrolled storage tanks in the LDAR
program will allow operators to identify
leaks and malfunctions that allow
significant quantities of gas to be lost.
b. Definition of a Leak
Comments: Many commenters noted
that the proposed rule did not define a
‘‘leak,’’ and they asserted that this
would cause confusion, variations in
interpretations, and inequitable
implementation of these provisions, as
well as potentially requiring repairs for
very small releases. Some commenters
also urged the BLM to define a leak to
distinguish it from normal, intended
operation (e.g., pneumatic device
actuation, crank case ventilation, etc.).
Many commenters suggested that
BLM identify the quality or quantity of
a release that would trigger repair
requirements under the leak detection
program. Commenters generally
supported defining a leak as any visible
hydrocarbon emission detected by use
of an optical gas imaging instrument, or
the formation of visible bubbles when
equipment is tested with soap solution.
With respect to portable analyzers,
commenters generally supported setting
a numeric threshold, but differed on the
number. Some commenters urged the
BLM to use 10,000 ppm of hydrocarbon
as the threshold for a ‘‘leak,’’ while
others recommended using 500 ppm,
stating that this is protective and
consistent with the Colorado
requirements.
Response: The BLM agrees that the
rule should define what constitutes a
‘‘leak’’ and has included a definition in
the final rule. As noted earlier, the
definition excludes losses due to normal
operation of equipment intended to
vent, provided the releases do not
exceed the quantities and frequencies
expected during normal operations. The
definition further clarifies that ‘‘leaks’’
include releases due to operator errors
or equipment malfunctions.
The purpose of a leak detection
program is to find and fix losses of gas
that are not part of normal operations.
A prudent operator should conduct
reasonable levels of monitoring, staff

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training, and preventative maintenance
to minimize the occurrence and
duration of such losses. We are adopting
a definition of ‘‘leak’’ sufficiently broad
in coverage to give operators the
incentive to avoid wasteful losses,
whether they occur due to aging
equipment or due to operator error,
including errors in appropriately sizing
equipment to handle the quantities of
production. As found in multiple recent
surveys, all of these types of
unnecessary losses occur and they are
frequently identified using leak
detection methods.
The BLM has also slightly modified
the definition of ‘‘leak component,’’ and
clarified that the inspection requirement
applies to leak components at a covered
site. Industry commenters had requested
that the BLM limit the inspection
requirement to specific components on
a site. For the reasons previously
discussed, the BLM believes it is
reasonable to require operators to
inspect all pieces of equipment that
have the potential to leak gas and that
can be tested for leaks. Moreover, as
discussed in the proposed rule,
repairing leaks generally pays for itself
over a reasonably short time-frame
through gas savings. To provide
additional clarity, the BLM has added to
the definition of ‘‘leak component’’
examples of specific types of
components that are covered, including
but not limited to: Valves, connectors,
pressure relief devices, open-ended
lines, flanges, covers and closed vent
systems, thief hatches or other openings
on a storage vessel, compressors,
instruments, and meters.
With respect to leak thresholds, and
consistent with the proposed rule, EPA
and State provisions, and commenters’
suggestions, the BLM is defining ‘‘leak’’
as including ‘‘a visible hydrocarbon
emission’’ detected using optical gas
imaging, or a release of gas forming
visible bubbles with soap solution.
Including soap solution allows
operators to deploy an additional
detection methodology that is
inexpensive and effective in confirming
that leak repairs have worked. The BLM
agrees with commenters that portable
analyzers can detect extremely small
releases, so the rule needs to specify a
threshold for the size of leak that
requires repair. The final rule identifies
500 ppm as the appropriate threshold.
This threshold is consistent with both
the Colorado and EPA fugitive
emissions programs, and aligning the
BLM and other Federal, State and tribal
programs is important to enhance clarity
and consistency and reduce confusion
and costs. Additionally, the BLM does
not believe that this threshold is too

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burdensome for operators because once
a leak is identified, repairs are generally
cost-effective. On average, many repairs
pay for themselves in terms of gas
savings, and even if some smaller leaks
may cost more to repair than they return
in gas savings, we generally expect that
the benefits to the public exceed the
costs of repair.113
c. Inspection Frequency
Comments: Numerous commenters
opposed the BLM’s proposed approach
to the frequency of inspections, under
which the frequency would initially be
semi-annual, but then could increase or
decrease depending on the number of
leaks found. Commenters stated that
this approach: Is not consistent with
Colorado and Wyoming leak detection
programs; is confusing, overly
complicated, and burdensome;
inappropriately relies on past
performance, which is not indicative of
future performance due to the random
nature of leaks; creates an incentive for
operators not to find leaks; and
incorrectly assumes that loss through
leaks is homogenously distributed,
rather than heterogeneously distributed,
which means that just one leak can be
responsible for the majority of the
waste.
While commenters generally
supported fixed frequency inspections,
different commenters supported
different frequencies. Some called for
quarterly inspections, while others
preferred annual. Still others suggested
an approach like Colorado’s, which
requires different frequencies, from
monthly to once, depending on the
estimated uncontrolled VOC emissions
from the highest emitting storage tank at
a site.
Commenters supporting a
requirement for quarterly inspections
asserted that: The costs are reasonable
(and lower than calculated by the BLM);
Colorado, Wyoming, and other states
already require quarterly inspections for
many sites; and optical gas imaging is
most effective when performed
frequently, which can make up for its
tendency to miss smaller leaks
compared to other leak detection
methods. Commenters who
recommended annual inspections
asserted that: The costs of LDAR
programs outweigh the benefits (and are
higher than calculated by the BLM);
operators find far fewer leaks after the
initial inspection, so repeated
inspections produce diminishing
113 Carbon Limits AS report entitled, Improving
utilization of associated gas in US tight oil fields
by Anders Pederstad, April 2015 found on the
internet at: http://www.catf.us/resources/
publications/files/Flaring_Report.pdf.

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returns; and even requiring annual
inspections will likely cause operators
to prematurely shut-in some wells.
Commenters also objected to inspection
frequencies that differ from EPA and
State requirements.
Response: Upon review of the
comments, the BLM agrees that
requiring leak inspections at a fixed
frequency will make the program easier
to implement, less burdensome for
operators, and more effective. The BLM
has concluded that requiring semiannual inspections is a reasonable
approach that balances the leakdetection advantages of more frequent
inspections against the associated costs.
Further discussion of the costeffectiveness of this approach is
provided in the RIA.
Requiring semi-annual inspections
also aligns the BLM and EPA
requirements. The BLM notes that it is
not possible to align the BLM program’s
inspection frequency with both EPA
requirements and all State requirements
because the EPA and States have
different inspection frequencies, and
frequencies differ even among the States
and among different EPA leak detection
programs for different sources. The BLM
expects that States with comprehensive
and effective LDAR requirements that
differ from the requirements of this rule
are likely to obtain variances under
section 3179.401, which would
eliminate conflict concerns. Also, as a
legal matter, operators on a Federal or
Indian lease, unit, or communitized area
will be subject to EPA fugitive
emissions requirements for their new,
modified and reconstructed facilities
and BLM LDAR requirements for their
existing facilities. By aligning the timing
of the BLM and EPA requirements, and
separately allowing operators to comply
with EPA requirements in lieu of BLM
requirements, the rule provides
operators with options for implementing
a single leak inspection program across
all of their facilities on a lease, unit, or
communitized area.
d. Instruments/Methods for Leak
Detection
Comments: Commenters generally
supported allowing the use of optical
gas imaging for leak detection, but
differed on whether also to allow
portable analyzers, or portable analyzers
deployed according to Method 21, as an
alternative instrument for leak
detection. In addition, most commenters
opposed the BLM’s proposal to allow
operators with less than 500 wells
within the jurisdiction of a BLM field
office to use portable analyzers in lieu
of optical gas imaging. Some argued that
Method 21 should be an option for all

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operators, while others argued that the
BLM should only allow the use of
optical gas imaging, stating that portable
analyzers are less effective. Some
commenters urged the BLM also to
allow use of AVO inspections as the
method of leak detection.
Response: Upon reviewing the
comments, the BLM has concluded that
portable analyzers, if used appropriately
and supplemented by AVO inspection,
can be as effective as optical gas imaging
for leak detection. Thus, the BLM has
revised the proposed approach to allow
operators to use optical gas imaging, or
to use portable analyzers according to
Method 21 and supplemented by AVO
inspection. The BLM believes that
concerns about the accuracy of portable
analyzers are ameliorated by requiring
the use of Method 21, Determination of
Volatile Organic Compounds Leaks,
which is a procedure established by the
EPA for detecting VOC leaks from
process equipment using a portable
detecting instrument.114 Method 21
contains requirements for equipment
specifications, performance, calibration,
and use to ensure that the analyzers are
used properly and will identify leaks
that are occurring. The BLM agrees with
commenters that allowing the use of
portable analyzers according to Method
21 will reduce costs by aligning with
existing EPA, State, and local
requirements. The BLM did not receive
information supporting some
commenters’ contention that AVO
inspections can be as effective as a
technology-based program, and thus the
final rule does not allow operators to
inspect for leaks only using AVO.
e. Approval of Alternative Leak
Detection Instruments/Methods and
Alternative Leak Detection Programs
Comments: Many commenters
strongly supported the provisions
allowing the BLM to approve additional
technologies and methods for leak
detection when they are found to be
effective, and they urged the BLM to
establish clear criteria for rapid
approval of alternative monitoring
devices and new technology. Some
commenters included alternative
monitoring programs in their comments
on this topic. Commenters noted
ongoing research and development
investment in new monitoring
technologies and methods, such as the
DOE’s ARPA–E MONITOR program and
the Environmental Defense Fund’s
114 U.S. EPA, Leak Detection and Repair, A Best
Practices Guide (Oct. 2007) (https://www.epa.gov/
sites/production/files/2014-02/documents/
ldarguide.pdf). 40 CFR part 60, Appendix A–7.

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Methane Detectors Challenge,115 and
they stated that several new
technologies for continuous or periodic
monitoring may become commercially
available within the next 2 years.
Many commenters urged the BLM to
detail the information that must be
included in an application for approval
of alternative technologies, as well as
the process and criteria that the BLM
would use to respond to an application.
Various commenters emphasized that
the process should be rapid, efficient,
transparent, predictable, consistent, and
rigorous. In addition, commenters
suggested that any person should be
able to submit an application, and that
any operator should be able to use an
approved technology.
Response: The BLM agrees on the
need for a clear, consistent, and rigorous
process and criteria for approval of
alternative leak instruments and
methods, and we have modified the
regulations accordingly. The final rule
provides that any person may request
approval of an alternative monitoring
device and protocol for using that
device by submitting a Sundry Notice to
the BLM that contains information that
the BLM would need to evaluate the
effectiveness of the alternative device
compared to the base program.
Once a device is approved for general
use, any operator may use it without the
need for additional notification or
approval. Because an approved device
could potentially be used by an operator
on any Federal or Indian lease, unit, or
communitized area, the BLM intends
that the request will be evaluated by the
BLM Director, Deputy Director, or
Associate Director. The BLM may
approve the device if the BLM finds that
the device would achieve equal or
greater reduction of gas lost through
leaks compared to optical gas imaging
used in a leak detection program that
meets the rule requirements. The BLM
believes that this is an appropriate
criterion for approval because it ensures
that the program will achieve its leak
reduction goals regardless of the type of
leak detection device used. The BLM
understands that different types of
devices may achieve equivalent results.
For example, a device that monitors
continuously, but is less sensitive than
optical gas imaging, might achieve
results equivalent to optical gas imaging
due to the gas savings from early
detection. The information submitted
must be sufficient to support such a
115 American Petroleum Institute (API).
Comments on the ‘‘Waste Prevention, Production
Subject to Royalties, and Resource Conservation’’
Proposed Rule. Submitted April 22, 2016. Docket ID
BLM–2016–0001–9073: Available at
regulations.gov.

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finding, however. Finally, the rule states
that the BLM will post online each
approved alternative monitoring device
and protocol, along with any limitations
on its use.
The BLM also clarified the distinction
between alternative leak detection
devices or methods and alternative leak
detection programs, which are both
included in the proposed and final
rules. Separate from the provisions for
approval of an alternative device, the
final rule allows an operator to request
BLM approval of an alternative leak
detection program that uses optical gas
imaging, a portable analyzer or another
approved device according to approved
specifications. As with an alternative
device, the final rule spells out the
information that an operator would
need to submit to request approval of an
alternative program. The BLM intends
that the request would be reviewed and
potentially approved by the BLM State
Director (or Director, if the request
covers operations in more than one
State). The BLM could approve an
alternative leak detection program if the
BLM finds that the alternative program
would achieve equal or greater
reduction of gas lost through leaks
compared to the leak detection program
required under the rule. The rule does
not allow other operators to use an
alternative leak detection program
requested by and approved for a specific
operator, as the results may not be
transferable. The BLM expects each
operator to make a detailed showing,
specific to their particular
circumstances, that an alternative
program would be equally or more
effective. For example, an operator
might propose a program that included
more frequent inspections for some sites
and less frequent for others, compared
to the final rule requirements, or an
operator may be able to deploy an
alternative leak detection device or
system, approved by the BLM, on a
continuous basis and achieve results
that would allow for less frequent
inspections using optical gas imaging.
f. Timing
Comments: Several commenters
recommended that the BLM extend the
phase-in period for the proposed LDAR
program. They stated that operators or
contractors will need time to ramp up
LDAR efforts, including acquiring the
necessary equipment and hiring and
training inspectors. Commenters
variously recommended phase-in
periods of one year or three years.
Response: The BLM agrees and has
modified the final rule to allow for a one
year phase-in period. Thus, the first
round of leak detection inspections

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must be completed by January 17, 2018.
The BLM notes that equipment
manufacturers, service providers, and
operators are already taking action to
produce and procure leak detection
equipment and establish programs in
response to EPA’s OOOOa requirements
published on June 3, 2016. Under those
requirements, all operators with new,
modified or reconstructed facilities will
already be conducting leak detection
inspections as of June 3, 2017.
Expanding such programs to cover
additional well sites should take less
time than the initial development and
deployment. The BLM also believes that
one year from the effective date of the
rule will provide ample time to
manufacture the needed equipment,
given the number of additional sources
that will be covered by this rule.
g. Repair Requirements
Comments: Commenters raised
several primary concerns. First, many
commenters opposed the BLM’s
proposal to require that an operator
verify a repair using the same method
used to detect the leak. They noted that
it may be more efficient to allow the
operator to test a repair using, for
example, a soap bubble test than to
bring the leak surveyor back to the site
to check the repair.
Second, some commenters urged the
BLM to allow 30 rather than 15 days for
leak repair. Commenters stated that
some leaks require more time to repair
due to safety issues, availability of
personnel or replacement parts, hostile
weather conditions, or other logistical
issues related to sites being remote,
dispersed, unmanned, and unelectrified. One commenter argued that
if an operator contracts with a
consultant to perform the monitoring,
the consultant will not be able to make
the repair at the time the leak is
detected, thus requiring more time to
complete the repairs.
Third, commenters requested more
clarification on what would constitute
‘‘good cause’’ for delay of repair, noting
that where the operator must blowdown
(depressurize) the equipment before
making the repair, this could release
more gas than would be released by the
leak prior to the next scheduled
equipment blowdown.
Response: The BLM modified the
final rule to address each of these
concerns, as well as align the rule with
the final subpart OOOOa. The BLM
agrees that optical gas imaging, portable
analyzers using Method 21, and the
soap bubble test are all effective means
to identify whether a leak has been
repaired, and providing operators the

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flexibility to select a verification method
should minimize costs.
The BLM also has modified the final
rule to provide operators up to 30 days
to make a repair, although the rule still
requires operators to repair leaks as
soon as practicable. We recognize that
some State LDAR programs require
repairs to be made sooner—within 5 to
15 days of finding a leak. The
requirement to repair leaks as soon as
practicable means that many leaks will
be repaired upon discovery or within a
shorter timeframe than 30 days, as many
leaks can be repaired on the spot or as
soon as a maintenance technician can
get out to the site. However, according
to industry commenters, allowing up to
30 days will meaningfully reduce the
time and costs involved in filing Sundry
Notices for leaks that could not be fixed
in 15 days but could be fixed in 30.
The final rule also provides additional
detail regarding what constitutes ‘‘good
cause’’ for delay of repair beyond 30
days. Good cause for delay exists if
repair within 30 days is technically
infeasible; would require a pipeline
blowdown, a compressor station
shutdown, or a well shut-in; or would
be unsafe to conduct during operation of
the unit. In addition, the operator must
complete the repair at the earliest
opportunity, and in no case may the
repair be delayed beyond two years.
Technical infeasibility includes a need
to order parts, in which case the
operator must complete the repair as
soon as the parts are available. Where
the cause for delay is the need to
blowdown or shut-down equipment, the
operator must complete the repair
during the next equipment blowdown or
shutdown that occurs after the leak is
found.
h. Interaction With EPA Fugitive
Emission Requirements and State LDAR
Requirements
Comments: Many commenters argued
that the proposed BLM LDAR program
overlaps and in some ways conflicts
with the EPA fugitive emissions
requirements under OOOOa and various
State LDAR requirements. These
commenters urged the BLM to drop the
LDAR program altogether or, at
minimum, align the BLM requirements
with the EPA and State requirements
and/or allow operators to comply with
EPA or State requirements in lieu of the
BLM requirements.
Response: While the BLM cannot
abdicate its statutory responsibility to
ensure safe, responsible, and
nonwasteful production of public oil
and gas resources, the BLM has worked
closely with the EPA and consulted
with States to align the regulations as

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much as possible, consistent with the
agencies’ separate statutory authorities.
In final form, the EPA and BLM
programs use the same criteria to
identify what constitutes a leak that
must be repaired, and they require
operators to use the same types of leak
detection equipment, inspect the same
types of sources at the same frequencies,
and repair leaks within the same
timeframes. In addition, the final rule
provides that operators complying with
EPA requirements for new, modified
and reconstructed equipment are
deemed in compliance with the BLM
requirements for such equipment,
eliminating the possibility of overlap
where both regulations apply. Also, the
final rule gives operators the option to
comply only with the EPA requirements
at existing facilities as well.
The BLM notes that there are a few
small differences between the BLM and
EPA programs, but these should not
increase compliance burdens for
operators. First, while the programs
both cover largely the same sources, the
programs differ somewhat in their
coverage. The BLM LDAR provisions
apply to all covers, closed vent systems,
and storage vessels, while the EPA
fugitive emissions requirements only
apply to covers and closed vent systems
not subject to § 60.5411a, and thief
hatches or other openings on a
controlled storage vessel not subject to
§ 60.5395a. Subpart OOOOa has a
separate, detailed set of requirements in
§ 60.5411a for sources covered by that
section, and another set of requirements
in § 60.5395a for storage vessel affected
facilities, and section 60.5416a
prescribes a separate and different leak
inspection regime for these sources.
For waste reduction purposes, the
BLM did not believe it was necessary to
adopt separate requirements for storage
vessels, covers and closed vent systems.
Instead, the BLM elected to require
controls for storage vessels with high
levels of gas loss and to include storage
vessels, covers, and closed vent systems
under the LDAR program. Thus, the
final rule provides that operators that
choose to comply with the EPA fugitive
emissions program in lieu of the BLM
leak detection program for both new and
existing equipment on a lease must
apply the EPA fugitive emissions
requirements to all equipment covered
by the BLM requirements, including
storage vessels, covers and closed vent
systems, to ensure that these types of
equipment are covered by at least one of
the agencies’ leak detection
requirements.
Second, a few elements of the BLM
LDAR requirements are less prescriptive
than the EPA requirements, but again,

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the BLM does not believe that these
differences would impose any
additional burdens on operators. The
BLM regulations do not require
operators to develop a monitoring plan
or specify their walking path for
inspections, nor do they include
requirements for scheduling inspection
of components that are difficult-tomonitor or unsafe-to-monitor. The BLM
record-keeping requirements are also
less specific than the EPA requirements.
The BLM regulations do not provide
specific direction to operators on the
proper calibration and use of leak
detection instruments, instead simply
requiring operators to operate the
instruments according to the
manufacturer’s specifications. Also, the
BLM requirements define ‘‘leak
component’’ slightly more broadly than
the EPA definition of ‘‘fugitive
emissions component.’’ For existing
equipment that is not also subject to the
EPA requirements, the final rule
provides operators the choice of
complying with the EPA or the BLM
requirements, allowing operators to
comply with a single set of requirements
for all of their sources if they so choose,
or to comply with the somewhat less
prescriptive BLM requirements with
respect to their existing sources.
With respect to State leak detection
requirements, the BLM notes that
because requirements differ both among
the individual States and between the
EPA and the individual State rules, it is
not possible to align the BLM
requirements with all of the other
potentially applicable requirements. In
addition, the BLM does not believe it is
appropriate to exempt operators from
the BLM requirements if they are subject
to any State requirement relating to leak
detection, as some commenters
suggested. That approach would not
ensure achievement of an equivalent
reduction in gas losses. Instead, the final
rule has a variance provision that allows
State or local requirements to substitute
for any of the BLM requirements under
these rules, upon a showing that the
State or local requirement at issue
would perform at least equally well in
terms of reducing the waste of oil and
gas, reducing environmental impacts
from venting and or flaring of gas, and
ensuring the safe and responsible
production of oil and gas.
C. Liquids Unloading at New Wells
1. Requirements of Final Rule and
Changes From Proposed Rule
The requirements to reduce venting
from liquids unloading activities at
natural gas wells are generally discussed
in Section VII. Section by Section. This

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section highlights one significant
change to those provisions from the
proposed rule. In the final rule, liquids
unloading activities at new wells are
subject to the same best practices and
reporting requirements as those at
existing wells. The BLM had proposed
to prohibit liquids unloading through
manual well purging at new wells
drilled after the effective date of the
rule, but we are not carrying this
proposal forward into the final rule.
2. Significant Comments
Comments: Many commenters
opposed the proposed well purging
prohibition for wells drilled after the
effective date of the rule. These
commenters stated that even with
optimized liquids unloading
management and a highly sophisticated
automated system, some purging would
still be necessary. One commenter
asserted that there are a large number of
different technologies, tools, and
practices for liquids unloading that are
matched to an individual well’s
characteristics at each stage of its
lifecycle (e.g., wellbore design, tubular
design and condition, use of packers,
and the frequency of unloading needed
to maintain or increase production), and
that no single technique will be
adequate or appropriate across the full
lifecycle of a well. Others argued that it
is inappropriate to have different
standards apply to similar wells
depending on the date on which they
are drilled.
Several commenters apparently
assumed that the prohibition on well
purging would effectively require
operators to install a plunger lift system
during initial well construction, and
these commenters provided multiple
reasons that would not be appropriate.
First, they asserted that new wells are
not likely to require liquids unloading
until later in the life of the well. Second,
they argued that the characteristics of
the well at the time that deliquification
is needed impact the technical
feasibility and cost of using methods
other than purging for liquids
unloading, and that operators are not
likely to know during initial
construction which option is optimal.
Third, commenters contended that
installing plunger lift systems at initial
construction would also ‘‘lock in’’
technology choices that may preclude
the use of more appropriate or improved
technology when deliquification is
needed. Lastly, commenters asserted
that even if equipment was installed on
new wells to accommodate plunger lifts,
by the time liquids unloading is
required, the equipment may need to be
fixed or replaced.

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Other comments supported BLM’s
proposal to prohibit purging during
liquids unloading activities at new
wells. They stated that operators could
effectively design wells and deploy
mitigation technologies in a way that
would eliminate emissions, and that
these technologies are cost effective.
Citing datasets showing that a small
minority of wells are responsible for a
large amount of venting during liquids
unloading events, these commenters
also argued that the BLM should
address this issue by applying the
purging prohibition to these highemitting existing wells as well.116
Response: Upon reviewing the
information provided by the
commenters, the BLM has determined
that it is not appropriate to prohibit
manual well purging at new wells. It is
often less expensive to design in
performance specifications (such as no
purging) than to retrofit an existing
source. However, in this case, the BLM
agrees with commenters that there is no
single technology or set of technologies
that could appropriately be deployed at
all new gas wells to avoid manual
purging later in the well’s life. The BLM
did not intend the proposed purging
prohibition to force all new wells to
install plunger lift systems, and we do
not believe that would be a costeffective way to minimize venting from
liquids unloading activities.

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D. Variances Related to State and Tribal
Regulations
1. Requirements of Final Rule
Like the proposed rule, the final rule
provides a variance procedure to allow
an equally or more effective State, local
government, or tribal requirement to
substitute for the comparable BLM
requirement under this subpart. The
BLM may grant a variance request
submitted by a State or tribe if the BLM
State Director finds that the State, local
government, or tribal rule or regulation
would perform at least as well as the
relevant provision of the BLM rule in
terms of reducing waste of oil and gas,
reducing environmental impacts from
venting and/or flaring of gas, and
ensuring the safe and responsible
production of oil and gas.
The rule identifies what a State or
tribe would need to include in a request
for a variance. The request must identify
the provision or provisions of the BLM
requirements from which the State or

tribe is requesting a variance, and must
identify the State, local, or tribal
provisions that would substitute for the
BLM provision or provisions. The
variance request must also explain why
the variance is needed, and demonstrate
how the State, local or tribal rules
would perform at least as well as the
BLM provisions they would replace.
2. Changes From Proposed Rule
The variance provisions in the final
rule largely track the proposed rule,
with a few additions and clarifications.
The criterion for approval of a variance
request in the proposed rule was a
determination that the State or tribal
regulation ‘‘meets or exceeds the
requirements of the provision(s) from
which the State or tribe is requesting the
variance.’’ The final rule requires
instead a finding that the State or tribal
rule ‘‘would perform at least equally
well in terms of reducing waste of oil
and gas, reducing environmental
impacts from venting and/or flaring of
gas, and ensuring the safe and
responsible production of oil and gas,
compared to the particular provision(s)
from which the State or tribe is
requesting the variance.’’ The final rule
changes the phrase ‘‘any individual
provision of this subpart’’ to ‘‘any
provision(s) of this subpart,’’ to make
clear that a variance request can apply
to a specific provision or a group of
provisions.
The final rule also: Allows local
government requirements, in addition to
State and tribal requirements, to support
a variance request and substitute for
BLM requirements; adds a requirement
that the State or tribe must notify the
BLM of any substantive changes to the
State, local government, or tribal rules
to be applied under the variance; and
clarifies that a variance allows State,
local government, or tribal rules to
apply in place of the BLM requirements,
but does not eliminate Federal
enforcement of waste prevention
requirements on Federal or Indian
leases, units, or communitized areas.
Rather, under a variance, the BLM has
the authority to enforce the rules
identified by the State, locality, or tribe
as if the requirements were BLM
regulations. The final rule further
clarifies that State, local, and tribal
enforcement of their own regulations
would not be affected by the BLM’s
approval of a variance.
3. Significant Comments

116 See

EDF, Comments on Proposed Regulation
Order Article 3: Greenhouse Gas Emission
Standards for Crude Oil and Natural Gas Facilities:
Part II of Comments 8 (May 22, 2015), available at
http://www.arb.ca.gov/cc/oil-gas/meetings/EDF_5–
22–15.pdf.

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a. Criteria for Variance Approval and
Scope of Variance
Comments: Several commenters
expressed concerns with the proposed

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criteria for BLM approval of a variance
request. Many commenters stated that a
patchwork of State, Federal, and tribal
regulations could cause compliance
difficulties and confusion for both the
regulators and the regulated entities.
These commenters requested that the
variance approval criterion be less
restrictive, and opposed the proposed
language stating that the State or tribal
regulation must ‘‘meet or exceed’’ the
requirements of this rule. Stating that
many of the State and tribal regulations
that limit venting and flaring are
qualitative, not quantitative,
commenters asserted that determining
what ‘‘meets or exceeds’’ the BLM’s
requirements would be arbitrary.
Instead, some commenters suggested
that the BLM change the language to ‘‘is
consistent with the intent of,’’ stating
that this would allow State regulations
that meet the intent of the proposed
rule, and are adequate and complete in
achieving similar goals, to meet the
variance criterion.
Other commenters suggested changes
to make the variance application and
approval process more restrictive, or
opposed allowing variances altogether.
One commenter supported the proposed
criteria for approval but suggested
strengthening this requirement by
specifying how the BLM would evaluate
the relative effectiveness of the State
program, for example by requiring
additional data or modeling to support
a variance request. Commenters also
requested that variance requests be
made publicly available, and that there
be an opportunity for the public to
comment on the requests.
Several commenters suggested that
variances should be allowed for all
provisions and for entire State
programs, stating that this approach
would eliminate an involved process
requiring variance requests for specific
provisions. Others raised concerns
about allowing a programmatic
variance, and urged the BLM to limit
variances to specific provisions of the
rule or allow for a variance only when
the State and BLM requirements are
duplicative. They noted that in many
cases State regulations do not address
all of the areas covered by the BLM
rule—i.e., venting, flaring, and leaks—
and State and tribal regulations may
also not cover the same specific sources
of these losses as the BLM rule.
Response: The BLM agrees that it
could be helpful to add further detail to
the proposed criteria for approving a
variance. In addition, the BLM agrees
that it could be helpful to clarify
whether several provisions could be
considered together and be found, in
combination, to meet the criteria for

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approving a variance. The BLM has
revised the variance provisions to
address both of these issues.
First, the goal of the variance
provision is to allow State, local, or
tribal regulations to substitute for the
BLM requirements where they will
produce benefits at least equivalent to
the expected benefits of the BLM
regulations. The final rule spells out this
criterion by identifying three key
benefits of the BLM rules: (1) Reducing
waste of oil and gas; (2) reducing
environmental impacts from venting
and/or flaring of gas; and (3) ensuring
the safe and responsible production of
oil and gas. To replace provisions of the
BLM rule with a State or tribal
requirement, the State or tribe must
demonstrate that their rules would
perform at least as well in achieving
these benefits.
The final rule would allow States and
tribes to request variances for specific
sets of provisions, as well as individual
provisions. For example, a State that
had a leak detection program similar to
the BLM program, but with a different
required inspection frequency, might
request a variance for the frequency
provisions or for the whole leak
detection program. The State would
need to demonstrate that even if the
State or local program would identify a
different set of leaks compared to the
BLM program, overall the State or local
program would be at least as effective as
the BLM program in reducing an
equivalent quantity of gas losses—
which would, in turn, reduce waste,
reduce the environmental impacts of
venting, and enhance safe and
responsible production.
The final rule provisions are not,
however, structured to support a broad
approval of a variance for an entire
State, local, or tribal oil and gas
production oversight program, and the
BLM agrees with the commenters who
raised concerns about such an approach.
The BLM recognizes that all States and
many tribes regulate various aspects of
oil and gas production, but different
States and tribes focus on different
aspects of the production process and
aim for different goals. For example, one
State may primarily regulate flaring,
while another aims primarily to reduce
methane emissions from tanks. The
focus on at least equivalent performance
requires a specific look at the results
achieved from a particular provision or
set of provisions, and it would not allow
approval of, for example, a stringent
flaring regime to substitute for leak
prevention requirements.
The final rule does not require that
variance requests be made publicly
available or that there be an opportunity

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for the public to comment on the
requests. In the past, the BLM has not
made individual variance requests
publicly available or provided an
opportunity for public comment.
b. Enforcement Under an Approved
Variance
Comments: Commenters requested
clarification on who would be
responsible for enforcement if a
variance were approved. Commenters
stated variously that: The State or tribe
should enforce the applicable State,
local or tribal requirements; States and
the BLM should establish memoranda of
understanding for enforcement; or the
BLM should retain authority to enforce
any State, local, or tribal provision for
which a variance is granted (noting that
States or tribes might lack resources to
operate effective enforcement
programs).
Response: The final rule clarifies that
the variance provisions allow operators
to comply with State, local, or tribal
requirements in lieu of BLM provisions
where a variance has been approved,
but the BLM is still responsible for
enforcing those requirements insofar as
they would replace the BLM
requirements. As a practical matter, the
BLM and States, localities, or tribes will
likely enter into memoranda of
understanding to coordinate
enforcement activities and efficiently
deploy enforcement resources, avoiding
overlap or redundancy. Ultimately,
however, the BLM remains responsible
for ensuring that operators comply with
Federal requirements, or in this case,
State, local, or tribal requirements that
the BLM deems to be an acceptable
substitute for the Federal requirements.
This is in contrast to situations in
which a Federal agency is authorized by
law to formally delegate administration
and enforcement of a regulatory
program to a State agency. Here, the
BLM is not delegating its regulatory or
enforcement authority to the State,
locality, or tribe. Rather, the BLM is
recognizing that, in the absence of a
variance, an operator would be required
to comply with overlapping
requirements. Where States, localities,
or tribes have regulations in place that
are different from, but at least as
effective as, the BLM requirements,
applying two sets of requirements is
burdensome for operators and would
not generate additional benefits. The
variance process avoids the potential
duplication and inefficiencies that
could otherwise occur in this situation,
while still holding the BLM responsible
for ensuring that operators meet the
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for the public that would have been
provided under the BLM regulations.
VI. Additional Significant Comments
and Responses
This section summarizes and
responds to some additional comments
on the proposed rule, that, while
significant, did not lead to major
changes in the final rule, and that are
more cross-cutting in nature than the
provision-specific comments addressed
in the Section VI. Section-by-Section.
These include comments on: The
interaction between the BLM rule and
EPA regulations; the BLM’s authority to
require flaring of vented gas; when gas
should be considered ‘‘avoidably lost’’;
application of these requirements to
units and communitized areas; delays in
permitting for natural gas pipeline rights
of way; and the interplay between this
rule and the BLM’s land use planning
activities.
A. Interaction With EPA Regulations
Comment: Many commenters raised
concerns about how the proposed BLM
regulations would interact with EPA
regulations on oil and gas production.
Some commenters urged the BLM not to
finalize some or all of the provisions of
this rule, arguing that its provisions
regulate air pollution, and that task
should be left to EPA. Some of these
commenters further suggested that if the
BLM does regulate waste from oil and
gas production, the BLM should exempt
sources covered by the EPA regulations,
and align its requirements with the EPA
requirements where they overlap, to
avoid duplication and inconsistencies.
Some commenters highlighted specific
provisions that could potentially
overlap with EPA’s requirements, and
expressed concern about differences or
conflicts between the two agencies’
regulatory regimes.
Response: We discuss the necessity
for BLM regulations to reduce waste
from oil and gas production in section
III.B.3.a of this preamble, and the BLM’s
legal authority for the rule in section
III.C. The BLM agrees with commenters,
however, that in those areas covered by
both this rule and EPA requirements,
the two sets of regulations should align
to the maximum extent possible. We
have addressed comments raising
potential inconsistencies between the
proposed BLM text in specific
provisions and corresponding EPA text
in sections VI.A of this preamble, and in
the Section by Section discussion in
section VII, where those specific
provisions are discussed. The remainder
of this section addresses comments on
the generalized potential for duplication
and overlap.

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We do not believe that the final BLM
and EPA rules impose conflicting
requirements on operators, and we
further believe that we have addressed
issues of regulatory overlap. First, much
of this rule regulates activities or areas
that are not regulated by EPA. This
includes the rule’s provisions on routine
flaring during the oil and gas production
process, well maintenance and liquids
unloading, well drilling, well testing,
emergencies, royalties due on lost gas,
royalty rates, measurement and
reporting of lost gas, and operators’
royalty-free use of gas. Second, where
both EPA and the BLM regulate an
activity, the rules largely apply to
different sources. In particular, the BLM
requirements on venting from
pneumatic controllers, pneumatic
pumps, and storage vessels all explicitly
apply to existing sources that are not
subject to EPA’s subpart OOOOa, but
would be subject to that rule if they
were new, modified, or reconstructed
sources. In addition, even where the
BLM and EPA requirements address the
same type of activity, but apply to
different sources (existing (BLM) versus
new, modified, or reconstructed (EPA)),
the agencies have worked together to
align the text and substance of the
requirements as closely as practicable.
Third, in those few instances in
which both agencies regulate an activity
and could potentially cover the same
source—specifically well completions
and leak detection—the BLM final rule
provides that an operator can comply
with just one set of requirements.
Specifically, the rule aligns the BLM’s
requirements with the corresponding
EPA requirements to a substantial
degree, and also provides that an
operator will be deemed to be in
compliance with the BLM rules if the
operator complies with the applicable
requirements of subpart OOOOa.
Comment: Commenters noted that in
addition to the existing EPA regulations
of new, modified, and reconstructed air
pollution sources at oil and gas
facilities, EPA announced in March
2016 its intention to regulate existing oil
and gas sources under CAA section
111(d), and EPA is currently developing
an information collection request (ICR)
as the first step in that process.
Commenters argued that this EPA action
negates any argument that the BLM rule
is necessary to address emissions from
the existing sources that subpart OOOO
and subpart OOOOa do not cover.
Response: The ICR and EPA’s
intention to conduct a rulemaking under
CAA section 111(d) are discussed in
detail in section III.B.3.a of this
preamble. In summary, establishing
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existing sources under the CAA would
entail the following steps:
• EPA issues a final ICR;
• Industry submits the required
information;
• EPA develops and proposes a rule
under CAA section 111(d);
• EPA reviews public comment on
that proposal and finalizes the CAA
section 111(d) rule;
• Because rules under section 111(d)
do not have independent effect but are
implemented by States, States then
develop and submit to EPA State plans
to implement the 111(d) rule (a process
that generally requires State rulemaking
and may require State legislation);
• EPA approves the State Plan (or
prescribes a Federal implementation
plan where the State fails to submit a
satisfactory plan); and
• Industry implements the
requirements in time to meet
compliance deadlines established in the
State plans.
Clearly, it will be many years before
existing sources in this sector are
subject to binding requirements under
CAA section 111(d), and it is not yet
evident what shape those requirements
will take. Given the substantial
uncertainty surrounding the timing and
content of any EPA regulation of
existing oil and gas sources, the BLM
has both the authority and the
obligation to act now to rein in the
ongoing waste of large quantities of
public and Indian natural gas.
B. Authority To Require Flaring of Gas
Citing several specific provisions of
the proposed rule that would require
operators to flare rather than vent gas
that is not captured for sale or use,
including the venting prohibition and
provisions on storage tanks, several
industry commenters asserted that the
BLM lacks the authority to require
flaring instead of venting of Federal and
tribal gas. These commenters argued
that the BLM’s sole authority is to
prevent waste, and a provision that
requires flaring rather than venting does
not aim at waste prevention because
shifting from venting to flaring does not
conserve the gas. The sole purpose of
such provisions, these commenters
asserted, is to regulate air pollution and
GHG emissions. Commenters further
asserted that regulation of air pollution
and GHG emissions is the exclusive
province of the EPA, and by extension,
the BLM may not regulate in this arena.
For several reasons, the provisions of
the rule that require flaring instead of
venting are within the BLM’s statutory
authority. First, as noted above, the
MLA grants the BLM the authority to
promulgate rules for the prevention of

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undue waste or for safety purposes.117
As explained further in the Section by
Section analysis in Preamble Section
VII, each provision of this rule that
requires flaring rather than venting is a
waste prevention and/or a safety
measure. For instance, the requirement
to flare and not vent high-pressure
associated gas constitutes waste
prevention because any flaring at a
given well will likely cause the operator
to capture more gas at its other wells in
order to stay within the capture
percentage under § 3179.7. These
provisions therefore fall comfortably
within the BLM’s waste prevention and
safety authority under the MLA,
irrespective of the BLM’s environmental
mandate.
Second, as discussed above, the MLA
and FLPMA grant BLM the authority to
regulate oil and gas development on the
public lands, including to protect the
public’s interest in other natural
resources and the quality of the
environment.118 In its traditional role as
manager of the public lands and steward
of publically owned resources, BLM
must regulate the development of
federally owned oil and gas deposits
pursuant to principles of multiple use
and sustained yield.119 Under those
principles, BLM may consider air
quality and GHG emissions when
deciding how to regulate mineraldevelopment operations. FLPMA
expressly declares that BLM should
balance the need for domestic sources of
minerals against the need to protect the
quality of ‘‘air and atmospheric’’
resources.120 Furthermore, as part of its
resource management plans, the BLM
has recently exercised its authority
under FLPMA to include emission
mitigation standards for oil and gas
operations.121
117 The BLM has acted on the latter authority
since DATE: longstanding rules promulgated under
the MLA require the operator to ‘‘perform
operations and maintain equipment in a safe and
workmanlike manner’’ and ‘‘take all precautions
necessary to provide adequate protection for the
health and safety of life and the protection of
property.’’ 43 CFR 3162.5–3.
118 See 30 U.S.C. 187, 189; 43 U.S.C. 1732(b),
1740.
119 43 U.S.C. 1732(a).
120 43 U.S.C. 1701(a)(8), (a)(12).
121 See, e.g., BLM Tres Rios Field Office, Resource
Management Plan and Record of Decision at II–63
(Feb. 27, 2015), available at http://www.blm.gov/
style/medialib/blm/co/field_offices/san_juan_
public_lands/land_use_planning/approved_
lrmp.Par.66402.File.dat/Part%20II%20%20RMP%20Chapter%202.pdf (setting forth
specific standards to mitigate oil and gas emissions
that will apply to all approved site-specific projects,
including NOx limits for engines, use of ‘‘green
completions technology,’’ storage tank controls
designed to achieve 95% emission reduction, and
use of low or no-bleed pneumatics).

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Third, the rule’s provisions requiring
flaring rather than venting further the
BLM’s trust responsibilities with respect
to Indian oil and gas development
because they will prevent the waste of
gas and will reduce the environmental
impacts to Indian lands from oil and gas
development. The BLM believes that
these provisions, like all the provisions
in this rule, are in the best interest of
Indian mineral owners and that the
extension of these provisions to oil and
gas production from Indian lands is
therefore justified.
Finally, while the CAA indeed
delegates responsibility for
implementing its air pollution and GHG
emissions control program to EPA,
nothing in the Act bars the BLM from
considering air pollution and GHG
emissions when deciding how to
regulate the development of federally
owned oil and gas deposits. The EPA
and the Department of the Interior have
distinct statutory authorities and
missions that may, in some cases, result
in overlapping policy goals. This rule
does not infringe on EPA’s prerogative
to regulate air quality through sourcespecific performance standards and
cooperation with State partners. Nor
does EPA’s authority infringe on or
otherwise restrict the BLM’s mandate to
prevent waste from and manage the
environmental impacts of activities on
public lands and using public resources.
The CAA does not displace other
Federal agencies’ Congressionallygranted authority to address
environmental and climate change
concerns.122 Congress may grant
agencies overlapping spheres of
authority, and such agencies merely
have a responsibility to coordinate with
each other.123 The BLM has worked
closely with EPA to ensure that this rule
and EPA’s subpart OOOO and subpart
122 See, e.g., 42 U.S.C. 7610 (‘‘Except as provided
in subsection (b) of this section, this chapter shall
not be construed as superseding or limiting the
authorities and responsibilities, under any other
provision of law, of the Administrator or any other
Federal officer, department, or agency.’’).
123 See, e.g., Massachusetts v. EPA, 549 U.S. 497,
531–32 (2007) (finding overlap but no conflict
between EPA’s authority to regulate greenhouse
gases from new motor vehicles under the CAA
section 202(a) and the authority of the National
Highway Transportation Safety Administration
(NHTSA) under the Energy Policy and Conservation
Act (EPCA) to promote energy efficiency by setting
mileage standards); see also Green Mt. Chrysler
Plymouth Dodge Jeep v. Crombie, 508 F. Supp. 2d
295, 350 (D. Vt. 2007) (concluding that ‘‘the
preemption doctrines do not apply to the interplay
between’’ EPA’s responsibilities under the Clean
Air Act and NHTSA’s duties under the EPCA, and
noting that ‘‘[s]hould a conflict between [the two
agencies’ processes] become apparent, the federal
agencies involved—EPA and NHTSA— are capable
of and even encouraged to cooperate in a joint
accommodation or resolution’’).

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OOOOa regulations harmonize to the
maximum extent practicable.
C. ‘‘Avoidably Lost’’ Oil or Gas
As noted above, the MLA requires
royalties on oil and gas to be paid as a
‘‘percent in amount or value of the
production removed or sold from the
lease.’’ 124 As interpreted in a judicial
decision addressing waste prevention
regulations issued by the Department in
the 1970’s,125 production ‘‘removed or
sold from the lease’’ does not include oil
or gas that is ‘‘unavoidably lost’’ during
production. ‘‘Avoidably lost’’ oil or gas,
on the other hand, constitutes waste and
is subject to royalties. As explained in
the preamble to the proposed rule,
NTL–4A distinguished between
‘‘avoidably lost’’ and ‘‘unavoidably lost’’
oil and gas, though it defined those
terms in a general way that was subject
to inconsistent application.126 In
§ 3179.4, this rule clarifies the
distinction between ‘‘avoidable’’ and
‘‘unavoidable’’ losses by limiting
‘‘unavoidable’’ losses to specific
circumstances in which the operator has
not been negligent and has complied
fully with applicable laws, lease terms,
and regulations. Industry commenters
objected to this approach on the ground
that whether a loss of oil or gas is
‘‘avoidable,’’ and therefore royaltybearing under the MLA, requires a caseby-case evaluation of a lessee’s
reasonableness in light of the economic
circumstances. That is, they argued that
a loss of oil or gas should be deemed
‘‘unavoidable’’ if taking measures to
avoid the loss would have been
‘‘uneconomic’’ from the operator’s
perspective.
For several reasons, the BLM did not
change the final rule based on these
comments. As an initial matter, there is
no statutory or jurisprudential basis for
the commenters’ position that the BLM
must conduct an inquiry into a lessee’s
economic circumstances before
determining a loss of oil or gas to be
‘‘avoidable.’’ Although the BLM’s
practice under NTL–4A has generally
been to engage in case-by-case economic
assessments before making avoidable/
unavoidable loss determinations, the
BLM has not always done so 127 and is
not legally required to do so.
124 30 U.S.C. 226(b)(1)(A), 226(c)(1) (emphasis
added).
125 See Marathon Oil Co. v. Andrus, 452 F. Supp.
548, 552–53 (D. Wyo. 1978).
126 81 FR at 6665.
127 Compare Ladd Petroleum Corp., 107 IBLA 5,
7 (1989) (requiring opportunity for operator to show
that gas capture would be ‘‘uneconomic’’ before
flaring is deemed avoidable), with Lomax
Exploration Co., 105 IBLA 1, 7 (1988) (flaring
without prior approval constitutes per se avoidable
loss under NTL–4A).

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Furthermore, in the absence of clear
statutory language or legislative history
delineating what should be considered
‘‘avoidably lost’’ oil or gas under the
MLA, the BLM’s past practice does not
prohibit it from revising its
interpretation of that term. Finally,
FOGRMA provides BLM with an
independent statutory authorization to
impose royalties on oil or gas lost as a
result of an operator’s negligence or
failure to comply with any rule or
regulation issued under the mineral
leasing laws, without further economic
analysis. Specifically, section 308 of
FOGRMA, provides that ‘‘[a]ny 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.128
Some commenters argued that the
BLM’s existing interpretation of what
constitutes an ‘‘avoidable loss’’ has
become a ‘‘fundamental term’’ of the
BLM’s existing oil and gas lease
contracts upon which lessees relied in
entering into the contracts and making
subsequent business decisions. Citing
Mobil Oil Exploration & Producing
Southeast, Inc. v. United States, 530
U.S. 604 (2000), commenters argued that
the proposed rule would substantially
impair the value of their lease contracts
and therefore subject the BLM to
contract damages or takings claims.
On the contrary, in promulgating this
final rule the BLM is acting within its
authority under the MLA and thus
within the terms of existing leases. First,
the MLA requires lessees to ‘‘use all
reasonable precautions to prevent waste
of oil or gas,’’ 129 and provides the
Secretary with the continuing authority
to ‘‘prescribe necessary and proper rules
and regulations’’ in order to carry out
the purposes of the MLA.130 The MLA
further requires that each lease contain
a provision ‘‘that such rules . . . for the
prevention of undue waste as prescribed
by [the] Secretary shall be observed.’’ 131
The BLM’s standard form lease makes
clear that the rights granted to the lessee
are ‘‘subject to . . . the Secretary of the
Interior’s regulations and formal orders
in effect as of lease issuance, and to
regulations and formal orders hereafter
promulgated when not inconsistent
with the lease rights granted or specific
provisions of [the] lease.’’ 132 Both the
128 30

U.S.C. 1756.
U.S.C. 225.
130 30 U.S.C. 189.
131 30 U.S.C. 187.
132 BLM Form 3100–11 (emphasis added).
129 30

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plain meaning of this language and the
BLM’s longstanding interpretation of it
extend to ‘‘incorporat[ing] future
regulations, even though inconsistent
with those in effect at the time of lease
execution, and even though to do so
creates additional obligations or
burdens for the lessee.’’ 133 The BLM’s
legal and contractual authority to
update its regulations governing oil and
gas leases should thus foreclose
successful breach of contract claims
based on this rule.
The Mobil Oil decision cited by
commenters is not pertinent. In that
case, a permitting delay mandated by a
subsequently enacted statute constituted
a breach of the lease because the terms
of the lease did not subject it to the
burdens of such later-enacted
statutes.134 Today’s rule constitutes a
‘‘hereafter promulgated’’ regulation to
which Federal oil and gas leases are
expressly subject. The application of
this rule to existing lessees, therefore,
does not breach their contract rights
because their existing leases incorporate
the rule by reference.
That said, the BLM is cognizant that
some of the requirements of this rule
may pose more substantial burdens for
existing lessees than for future lessees,
because future lessees can take account
of the requirements of the rule in
making their leasing decisions.
Accordingly, certain sections of the rule,
including sections 3179.8 and 3179.201,
are structured to reduce the burden on
existing lessees. For further discussion
of these provisions, see Section VII,
Section by Section.
D. Application to Units and
Communitized Areas
Some commenters objected to the
application of this rule to operations on
State and private tracts that are
committed to a Federally-approved unit
or communitized area. These
commenters admit that the BLM has the
authority under FOGRMA to regulate oil
and gas activities on such tracts for the
purposes of royalty accountability, but
fail to recognize the various royaltyaccountability purposes of this rule,
including identifying and imposing
royalties on wasteful losses of oil and
gas, clarifying the circumstances under
which production may be used royalty
free, and setting measurement standards
for venting and flaring (some of which
is royalty bearing). More to the point,
though, these commenters did not
explain why the BLM’s waste
133 Coastal Oil & Gas Corp., et al., 108 IBLA 62,
66 (1989).
134 Mobil Oil Exploration & Producing Southeast
v. United States, 530 U.S. 604, 613–20 (2000).

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prevention authority under the MLA
does not extend to the waste of Federal
oil and gas that occurs on non-Federal
tracts in a Federally-approved unit or
communitized area. Commenters cited
the BLM’s decision not to apply
Onshore Oil and Gas Order No. 1
(‘‘Order 1’’) to operations on nonFederal lands in units and
communitized areas 135 as evidence that
the BLM lacks authority to apply this
rule to such lands. However, the cited
passage from the preamble to Order 1
did not address the scope of the BLM’s
regulatory authority with respect to nonFederal tracts in Federally-approved
units and communitized areas; rather,
the passage addressed what was
‘‘appropriate’’ in light of the
jurisdictional limitations contained in
43 CFR. § 3161.1.
Commenters also asserted that
because the regulation of State and
private minerals is under the
jurisdiction of the States, the BLM lacks
the authority to apply its waste
prevention regulations to units and
communitized areas in a manner that
would affect the production of State and
private minerals unitized or
communitized with Federal minerals.
While the BLM agrees that the
regulation of State and private minerals
is under the jurisdiction of the States,
the BLM does not agree that States’
jurisdiction over State and private
minerals precludes the BLM from
promulgating a waste prevention
regulation that has incidental impacts
on State and private minerals unitized
or communitized with Federal or Indian
minerals. The purpose of this rule is to
ensure that operators take reasonable
precautions to prevent the waste of
Federal and Indian oil and gas, a matter
that BLM has the authority to regulate
pursuant to its statutory and trust
responsibilities described in Section
III.C.
The fact that States and private parties
have chosen to enter into unitization or
communitization agreements whereby
State or private oil or gas is commingled
with Federal or Indian oil or gas, and
produced concurrently with Federal or
Indian oil or gas, does not deprive the
BLM of its authority to impose
reasonable waste prevention
requirements on operators producing
Federal or Indian oil or gas.
E. ROW Permitting
Under section 28 of the MLA, the
BLM is responsible for granting most of
the ROWs for oil and natural gas
gathering, distribution, and
transportation pipelines and related
135 72

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83039

facilities on public lands. Specifically,
the BLM has ROW approval authority
for ROWs that cross lands administered
by the BLM, or lands administered by
two or more Federal agencies,136 except
lands in the National Park System or
lands held in trust for Indians or Indian
tribes.137
Several commenters expressed
concern that they have experienced
significant delays in obtaining ROW
approvals for gathering lines, and that
these delays impede producers’ ability
to capture and sell gas. These
commenters stated that the BLM should
streamline the ROW approval process.
They asserted that accelerating the
permitting process for pipeline ROWs
would allow energy producers to more
easily capture and market gas that might
otherwise be flared due to a lack of
infrastructure. Some commenters
further asserted that the BLM could
quickly and easily reduce flaring by
processing ROWs in a timely manner,
and that streamlining ROW permitting
would provide a more cost-effective
solution to the problem of gas waste
than imposing the requirements in the
proposed rule.
Commenters suggested several ways
in which the BLM could increase
permitting speed for gas gathering lines
on Federal land. One commenter stated,
for example, that the BLM should
expand the use of categorical exclusions
under the National Environmental
Policy Act (NEPA) when permitting gas
gathering lines, and another suggested
using a ROW ‘‘corridor’’ approval
approach, so that small adjustments in
a project footprint would not delay the
full approval process.
The BLM’s experience is that while
processing time for ROW applications
can sometimes be an issue, particularly
in a handful of offices where staff
retention has been difficult over the past
few years, processing time is not the
primary cause of the large volume of
current flaring. For example, BLM data
indicate that many applications to flare
gas come from wells that are already
connected to pipeline infrastructure, or
for which operators are not seeking
ROWs to build new pipelines. For
instance, in Dickinson, North Dakota,
large volumes of gas are being flared
from over 1,700 Federal and Indian oil
wells,138 yet the local BLM field office
136 43

CFR 2881.11.
Leasing Act section 28(b)(1)
(definition of ‘‘Federal lands’’ excluding lands in
the National Park system or lands held in trust for
Indians or Indian tribes).
138 Based on internal BLM analysis of North
Dakota activity from AFMSS queried on April 16,
2015.
137 Mineral

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currently has just four ROW
applications pending.
While the BLM data indicate that the
current speed of the BLM’s ROW
processing is not a significant factor in
the rate of flaring at most wells, the
BLM recognizes the importance of
timely ROW approvals and continues to
make improvements aimed at increasing
the efficiency of the ROW permitting
process. A variety of factors, some in the
BLM’s control but some beyond the
BLM’s control, can impact the timely
approval of ROWs and other actions that
may be needed to construct a pipeline
or gas processing facility. For example,
fee land owners may delay or block a
pipeline project that crosses both public
and private lands, even when the
Federal portion of the ROW is
permitted. The time period for
permitting ROWs may also be extended
if, for example: The ROW grant is
pending consultation or concurrence
from another agency, e.g., pursuant to
the Endangered Species Act or Section
106 of the National Historic
Preservation Act; the ROW application
is incomplete; the corresponding APD
has not yet been processed; or a high
volume of applications is submitted in
a short period of time.
Last year, the BLM instituted key
program changes to more quickly
process pending oil- and gas-related
ROW applications, and we have seen
progress as a result of these efforts.
These steps included using strike teams
to add additional permit-processing
resources at high-volume offices,
working with the Office of Personnel
Management to identify pay strategies to
address staff shortages in key offices,
and increasing formal training for
critical staff. Additionally, particular
field offices are actively pursuing other
actions to decrease permitting times,
including: (1) Coordinating aspects of
the pipeline ROW and corresponding
APD reviews, so that they occur
concurrently rather than consecutively;
(2) working with project proponents to
minimize surface disturbance to help
expedite environmental reviews; (3)
fully and consistently utilizing
applicable Categorical Exclusions to
NEPA to streamline reviews; (4)
encouraging project proponents to
develop oil and gas Master Development
Plans and Master Leasing Plans as well
as right-of-way Master Agreements,
which are negotiated with a single
applicant for processing and monitoring
multiple applications covering facilities
within a specific geographic area; (5)
encouraging unitization to help
streamline permitting by avoiding the
need for multiple ROWs (or potentially
for any ROW at all, if the gas can be

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gathered and transmitted without
crossing Federal or Indian land); and (6)
working closely with proponents to
determine which projects are priorities.
F. Planning
Finally, many stakeholders requested
that the BLM address waste reduction
through requirements under the MLA
relating to the BLM’s land use planning
and environmental review processes.
Commenters stated that the BLM should
use its authority to reduce waste by
proactively using all available planning,
analysis and permitting tools including
Applications for a Permit to Drill
(APDs); lease stipulation decisions in
resource management plans (RMP);
master leasing plans (MLPs); waste
minimization plans (WMPs); and
unitization agreements. Commenters
also stated that the proposed rule fails
to exercise the BLM’s full authority at
the planning and leasing stages, and
further, that land-use planning should
be used to support well-planned fossil
fuel development that would, for
example, limit the leasing of lands
where infrastructure constraints are
expected to be significant, so as to
minimize the need for venting or flaring
of associated gas.
Commenters asserted that if the BLM
conducted more robust NEPA reviews
prior to oil and gas development, the
reviews would identify additional waste
reduction opportunities. Commenters
further requested that the rules
governing development of RMPs be
modified to support the intended
purpose of the rule to capture gas and
prevent venting or flaring. These
commenters also asserted that detailed,
site-specific MLPs can support methane
capture and waste minimization once an
RMP is in place.
Commenters disagreed with the
BLM’s decision not to propose changes
to the BLM land use planning
regulations as part of this rulemaking.
They suggested that the BLM’s failure to
link the proposed rule to the BLM’s
foundational planning and management
framework misses opportunities to
foster orderly and efficient development
of oil and gas that would prevent
methane pollution and waste. Some
commenters suggested that although
changes to the BLM’s land use planning
rules are not required to enhance the
use of planning mechanisms available to
the BLM when developing RMPs and
MLPs, referencing these tools in the
final rule would emphasize their
importance.
While the BLM is not making changes
to the BLM land use planning
regulations or NEPA review processes as
part of this rulemaking, as stated in the

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preamble to the proposed rule, the BLM
agrees that the land use planning and
NEPA processes are critical to achieving
our simultaneous goals of responsible
oil and gas development, land
stewardship and resource conservation,
and protection of air quality on (and
reduction of air emissions from) Federal
lands.
The BLM already has land use
planning and NEPA tools and processes
in place that can be used to help achieve
the specific goals of this rulemaking—to
reduce the wasteful and
environmentally harmful loss of gas
through venting, flaring, and leaks. The
BLM conducts NEPA analyses for both
regional planning decisions and project
level decisions. These analyses take a
hard look at the direct effects, indirect
effects, and cumulative effects of the
proposed federal action on various
resources during the land use planning
or project approval process, such as the
effects on wildlife, air quality, or
recreation opportunities. The BLM’s
NEPA analyses also quantify GHG
emissions associated with the proposed
planning decision alternatives under
consideration. In particular, the land
use planning and NEPA processes for
new RMPs and MLPs provide important
opportunities to consider the effects of
oil and gas development over a larger
area and to optimize planned
development to minimize impacts from
venting and flaring, among other
activities. The planning process gives
the BLM the opportunity to consider
how a specific land management plan
could address the timing and location of
development of oil and gas and related
infrastructure, such as pipelines, and
the projected consequences of such
decisions in terms of the quantities of
vented and flared gas and the impacts
associated with those emissions.
Thus, the BLM already has the NEPA
processes and tools in place to evaluate
the effects of the gas that would be
flared, vented, and leaked from
proposed oil and gas production,
including impacts to wildlife and air
quality, as well as GHG emissions,
which contribute to climate change. The
NEPA analyses can also identify ways to
minimize such effects, such as
evaluating alternative options for siting
and timing of development that would
maximize the opportunities for gas
capture in lieu of flaring.
In addition, the BLM is in the process
of completing a comprehensive update
to its land use planning regulations,
which should further enhance the
opportunities to address gas waste in
new oil and gas production approvals.
The BLM proposed its new planning
regulations in February 2016. The

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proposed changes would boost public
participation and facilitate earlier
stakeholder engagement in the planning
process. For example, the new planning
regulations would provide for a
planning assessment at the initiation of
an RMP, which would involve
stakeholders and other agencies in
identifying key issues and obtaining
better data early in the process. These
new regulations would also enhance the
existing opportunities for stakeholders
to highlight options to reduce waste
from proposed oil and gas production in
BLM land use planning.
G. Exemptions Through Sundry Notices
Some commenters expressed concerns
that because the rule provides for
operators to request various exemptions
through submission of Sundry Notices
to the BLM, these provisions could
impose a paperwork burden on
operators and the requests could be
difficult for the BLM staff to process in
a timely manner. The BLM believes that
the number of requests for exemptions
will be fairly limited, as the BLM’s
analysis does not indicate that the costs
of these provisions will be substantial
for the vast majority of operators.
Nevertheless, the BLM recognizes that
these are valid concerns, and is
committed to minimizing unnecessary
paperwork burdens on operators and
continuing to streamline its own
operations.
Thus, the BLM is providing here some
additional information regarding how
we expect operators to submit requests
and how we may process them, and we
will provide additional guidance as we
move forward to implement the final
rule. Concerns have been raised in this
regard with respect to requests for
exemption from multiple requirements
of the rule for a lease. Specifically,
operators have asked whether they
could submit a single request for an
exemption from multiple provisions of
the rule, and how the BLM would
evaluate it. The final rule requires an
operator to make a demonstration that
each requirement for which the operator
is requesting an exemption would itself
cause the operator to cease production
and abandon significant recoverable
reserves on the lease. An operator could
not simply add up the costs of
compliance with multiple requirements
of the rule to show that the cumulative
costs of the requirements would cause
the operator to cease production and
abandon significant recoverable reserves
under the lease, and thereby obtain an
exemption from all of those
requirements. In making the showing for
a specific requirement, however, the
operator could take into account as part

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of the baseline costs any requirements of
the rule for which an exemption is not
being requested. In addition, to the
extent that there is common data
supporting multiple exemption
requests, such as the data on production
and revenues from a given lease, the
BLM intends that an operator would be
able to provide that data once on a
single submission containing a separate
showing for each of the specific
requests, rather than providing multiple
separate submissions.
VII. Section by Section
This section discusses the final rule
provisions, substantial changes from the
proposed rule, and some of the most
significant comments received. Public
comments not addressed in this section
or elsewhere in this preamble are
addressed in the separate Response to
Comments document, which is available
on the BLM Web site and is part of the
rule-making record.
Part 3100
Section 3103.3–1 Royalty on
Production
The final rule’s amendments to
existing 43 CFR 3103.3–1 focus on
existing § 3103.3–1(a)(1), and do five
things: (1) Remove two provisions of the
existing regulations that are no longer
necessary (§ 3103.3–1(a)(1)(i) and (ii));
(2) add a new § 3103–1(a)(2); (3) specify
that the royalty rate on all leases
existing at the time the rule becomes
effective will remain at the rate
‘‘prescribed in the lease or in applicable
regulations at the time of lease
issuance’’; (4) specify the statutory rate
of 12.5 percent for all noncompetitive
leases issued after the effective date of
the final rule; and (5) 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.’’ 139 All of these changes were
in the proposed rule.
The final rule also renumbers existing
§ 3103–1(a)(2) and (a)(3) as § 3103–
1(a)(3) and (a)(4) and makes minor
changes to existing § 3103–1(a)(3)) (final
§ 3103–1(a)(4)) for clarity.
Additionally, the final rule reprints
existing §§ 3103–1(b) and (c), for clarity.
Finally, the BLM made a minor revision
to § 3103.3–1(d) from the proposed rule.
139 Note that the rule renumbers current 43 CFR
3103.3–1(a)(2) and (3) but does not otherwise
change the content of those provisions. Further, the
rule does not alter 43 CFR 3103.3–1(b), (c), or (d).
Those provisions are reprinted in this rule solely to
clarify the numbering of the revised § 3103.3–1, and
for ease of reference.

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To improve the clarity of this provision,
final § 3103–1(d) adds the language
‘‘from the gas stream’’ in two places that
address any helium component that is
not conveyed with the mineral estate in
a Federal oil and gas lease.
Several commenters stated that a new
royalty rate above the current rate of
12.5 percent would create uncertainty in
the leasing process, and would
disadvantage Federal leases compared
with State and private leases and
disincentivize investments on Federal
lands. One commenter objected to the
proposed rule’s use of the term ‘‘base
rate,’’ because the BLM did not provide
a definition of that term. The
commenter also noted that the proposed
rule does not describe the process by
which the rate will be determined, to
whom it will apply, or how and when
it will be reevaluated and reset. One
commenter noted that under the BLM’s
recent regulatory revision of Onshore
Oil and Gas Order Number 3, the BLM
proposes to authorize commingling
allocations and approvals (CAAs) for
properties with identical fixed royalty
rates. The commenter suggested that a
variable royalty rate would have the
unintended consequence that most
CAAs would not be approved.
Other commenters supported the
BLM’s proposal to ensure that the
royalty rate of 12.5 percent represents a
floor and not a ceiling. The commenters
contended that this would allow the
American public to receive a fair market
return on their resources. Some
commenters suggested that the royalty
rate be raised to 18.75 percent to be in
line with the royalty rate assessed on
Federal offshore leases. Commenters
also noted that the current rate is far
below several state rates. One
commenter suggested that the increase
in royalty rate should be informed by
the social and environmental costs of oil
and gas production, including the social
cost of methane emissions. Another
commenter stated that if the BLM were
to increase the royalty rate, it should be
a constant rate, rather than a sliding
scale, as this would reduce
administrative and reporting burdens.
Some commenters requested that the
BLM set the royalty rate at least 60–90
days prior to any lease sale and publish
notice in the Federal Register and the
BLM Web site for public comment.
The BLM did not revise the rule in
response to these comments. As stated
in the proposed rule preamble, the BLM
is not currently proposing to raise the
base royalty rate for new competitively
issued leases above 12.5 percent; rather,
we are conforming the regulatory
provisions governing royalty rates for
new competitive leases to the

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corresponding rate provisions in the
MLA. The BLM would engage in
additional process before raising the
rate.

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Section 3160.0–5 Definitions
This amendment to § 3160.0–5 deletes
the 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 is superseded by the
provisions in new subpart 3179,
particularly § 3179.4, governing when
the loss of oil or gas is deemed
avoidable or unavoidable. The BLM did
not receive comments on removing this
definition and is finalizing this deletion
as proposed.
Section 3162.3–1 Drilling Applications
and Plans
This section describes the
requirements for drilling applications
and plans, including the information
that an operator must provide with an
APD. The BLM is amending this section
to add paragraph 3162.3–1(j), which
requires that when submitting an APD
for an oil well, an operator must also
submit a waste minimization plan.
Submission of the plan is required for
approval of the APD, but the plan will
not itself become part of the APD, and
the terms of the plan will not be
enforceable against the operator.
The purpose of the waste
minimization plan is for the operator to
set forth a strategy for how the operator
will comply with the requirements of
subpart 3179 regarding the control of
waste from venting and flaring. The
waste minimization plan must include
information regarding: The anticipated
completion date(s) of the proposed
well(s); a description of anticipated
production from the well(s);
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
identification of a gas pipeline to which
the operator plans to connect.
Based on comments received
requesting that the information required
in the plans be streamlined, the final
rule provides that certain kinds of
information are only required if an
operator cannot identify a gas pipeline
with sufficient capacity to accommodate
the anticipated production of the
proposed well(s). This conditionallyrequired information includes: A gas
pipeline system location map showing
the proposed well(s); the name and
location of the gas processing plant(s)

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closest to the proposed well(s); all
existing gas trunklines within 20 miles
of the well, and proposed routes for
connection to a trunkline; the total
volume of produced gas, and percentage
of total produced gas, that the operator
is currently venting or flaring from wells
in the same field and any wells within
a 20-mile radius of that field; and a
detailed evaluation, including estimates
of costs and returns, of potential on-site
capture approaches.
Some commenters requested that
waste minimization plans required by
other states, such as North Dakota and
New Mexico, should be allowed to
satisfy the requirements set forth in this
section. The BLM recognizes that some
States have similar waste minimization
plan requirements under State law. To
the extent that an operator is already
preparing, under State requirements, a
waste minimization plan that meets all
or most of the requirements for a waste
minimization plan under section
3162.3–1, the BLM requirements should
impose little additional burden on the
operator. The operator would be able to
submit the same plan to the BLM,
supplemented as necessary to meet each
of the requirements of section 3162.3–1.
Other commenters stated that the
preparation and review of the waste
minimization plans would be a burden
both on applicants and the BLM,
because in the commenters’ view, the
proposed rule significantly
underestimated the number of plans
that would be required and the time
required to prepare them. The
commenters asserted that the BLM can
be slow in approving APDs, and argued
that the review of the additional waste
minimization plans could slow the
process further. Other commenters
suggested that the requirement to
prepare a waste minimization plan be
limited only to wells that anticipate
flaring a high volume of associated gas
after completion. The BLM disagrees
with these comments and believes that
requiring operators to prepare a waste
minimization plan for all wells is a
reasonable, low cost, and effective way
to encourage operators to consider and
plan for capturing gas before the
development of every new well. As
stated previously, however, the final
rule streamlines some of the elements
required in the plan. Further, the BLM
presently plans to review the
effectiveness of the plan requirement
within 3 years after the final rule’s
effective date, to assess the costs to
operators of preparing the plans, the
costs to the BLM of reviewing the plans,
and the effectiveness of the plans in
driving flaring reductions at new wells.

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Commenters also expressed concern
that the waste minimization plan
requirement could trigger the need for
additional analysis under NEPA for
non-federal/non-Indian wells within a
unit or communitized area. Under
existing regulations, wells that are not
located on federal or Indian surface and
do not pierce federal or Indian minerals
are not required to obtain BLM’s
approval of an APD, even if those wells
are within a unit or communitized area
from which federal or Indian minerals
are produced. Commenters were
concerned that the requirement for a
waste minimization plan would
somehow require those wells to file
APDs or subject them to NEPA.
The BLM believes these concerns are
unfounded. Operators would be
required to submit waste minimization
plans only for wells that already require
an APD under part 3160—i.e., for wells
that are located on federal or Indian
surface or pierce federal or Indian
minerals. Operators may need to
incorporate information in their waste
minimization plans regarding wells on a
unit or communitized area that do not
require APDs (see, e.g., § 3162.3–
1(j)(2)(ii), requiring anticipated
production information for all wells on
a multi-well pad). Also, to the extent
that gas from a nonfederal mineral estate
is mixed with federal or Indian gas, the
waste minimization plan may
effectively minimize waste of both
federal or Indian and non-federal or
non-Indian gas. However, nothing under
this provision requires operators to file
an APD for any well, much less extends
the APD requirements under part 3160
to wells that are not located on federal
or Indian surface and do not pierce
federal or Indian minerals. Moreover,
waste minimization plans are not
enforceable, and BLM will only review
and approve them in the course of
acting on an APD. While the BLM will
analyze potential indirect impacts of
execution of the waste minimization
plan as part of its NEPA analyses for
APDs submitted after the rule takes
effect, there is no independent federal
action here that would trigger NEPA for
a waste minimization plan separate
from an APD. Other commenters stated
that the BLM should strengthen the
requirements of the waste minimization
plans and make them enforceable. The
BLM declined to do so. The BLM
believes that waste minimization plans,
like the environmental analyses
performed under the National
Environmental Policy Act, can drive
significantly better outcomes by
ensuring that the operator and
midstream companies have more

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information at an earlier stage, to allow
for better planning and coordination. To
achieve that result, however, the plans
must be quite detailed and contain all
relevant information. The BLM believes
that the plan’s unenforceability helps
achieve that outcome: Because the terms
of the plans cannot be enforced against
the operator, the BLM avoids creating an
incentive for operators to develop very
general plans with few specific details.
Additionally, the BLM is concerned that
circumstances could change between
when the plan is developed and when
well production begins, making strict
adherence to the plan difficult. In such
a circumstance, the existence of the plan
would still be useful, because operators
would have information at their
fingertips that would enable them
respond nimbly to the changed
circumstance, but operators would not
be held to the specific terms of the now
outdated plan.
Commenters also requested that the
BLM make the waste minimization
plans publicly available. The BLM
already publicly posts APDs for a period
prior to approval, and we plan to post
the waste minimization plans
accompanying the APDs in the same
manner, subject to any protections for
confidential business information.
Subpart 3178—Royalty-Free Use of
Lease Production

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Section 3178.1

Purpose

This 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 supersedes
those parts of NTL–4A pertaining to oil
or gas used for ‘‘beneficial purposes.’’
The BLM received a comment on this
section requesting that the BLM clarify
whether the rule will replace all of
NTL–4A, or just those parts ‘‘pertaining
to use of oil or gas for beneficial
purposes.’’ The BLM notes that Subpart
3178 replaces the portion of NTL–4A
pertaining to the use of oil or gas for
beneficial purposes and Subpart 3179
replaces the portion of NTL–4A
pertaining to venting and flaring of
produced gas, unavoidably and
avoidably lost gas, and waste
prevention. Together, the combined
revisions to Subparts 3178 and 3179
supersede NTL–4A in its entirety. The
BLM disagrees that the regulatory text
requires clarification beyond what is
stated here, and did not revise this
section in response to this comment.
Section 3178.2

Scope of This Subpart

This section specifies which leases,
agreements, wells, and equipment are

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covered by this subpart. The section
also states that the term ‘‘lease’’ in this
subpart includes IMDA agreements,
unless specifically excluded in the
agreement or unless the relevant
provisions of this subpart are
inconsistent with the agreement. In the
final rule, in response to comments, the
BLM edited proposed paragraph (a)(5) to
clarify the list of items to which this
subpart applies. Paragraph (a)(5) in the
final rule provides that this subpart
applies to wells and production
equipment, and also, under specified
circumstances, compressors.
Additionally, the final rule omits
proposed paragraph (a)(6) relating to
coverage of gas lines, as the BLM has
determined that gas lines do not ‘‘use’’
production for purposes of this subpart.
One commenter suggested replacing
‘‘other facilities’’ with ‘‘production
equipment,’’ and suggested
distinguishing compressors that
promote production at the wellhead
from those that promote pipeline flow.
The BLM agrees that these suggested
changes improve the clarity of the rule,
and we have revised the text
accordingly. The text now refers to
‘‘production equipment’’ and limits
coverage to compressors that both are
located on a lease, unit or
communitized area and compress
production from the same lease, unit or
communitized area.
Commenters also suggested
distinguishing among flow lines,
gathering lines and transmission lines,
and requested revisions to highlight the
limits of the BLM’s authority over gas
lines. We believe that these comments
are no longer applicable with the
elimination of proposed paragraph
(a)(6).
Section 3178.3 Production on Which
Royalty Is Not Due
This section sets forth the general rule
that royalty is not due on oil or gas that
is produced from a lease or
communitized area and used for
operations and production purposes
(including placing oil or gas in
marketable condition) on the same lease
or communitized area without being
removed from the lease or
communitized area. This section also
treats oil and gas produced from unit
PAs—that is, the productive areas on a
unit—and used for operating and
production purposes on the unit, for the
same PA, in the same way. Units often
include different PAs composed of
multiple leases with varied ownership.
This section therefore limits 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

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83043

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.
As discussed below, § 3178.5 qualifies
the general provisions of § 3178.3 by
listing specific operations for which
prior written BLM approval will be
required for royalty-free use.
The BLM received a few relatively
technical comments on § 3178.3, which
are addressed in the Response to
Comments document. The BLM did not
make any changes to this section from
the proposed rule.
Section 3178.4 Uses of Oil or Gas on
a Lease, Unit, or Communitized Area
That Do Not Require Prior Written BLM
Approval for Royalty-Free Treatment of
Volumes Used
This section identifies uses of
produced oil or gas that will not require
prior written BLM approval for royaltyfree treatment. The uses listed in this
section involve routine production and
related operations. In addition,
paragraph (b) clarifies that even when a
use is authorized, the royalty-free
volume is limited to the amount of fuel
reasonably necessary to perform the
operation on the lease using
appropriately sized equipment. This
ensures that royalty-free on-site use
remains subject to the requirement to
avoid waste of the resource.
While the royalty-free uses described
here are generally similar to the uses
identified as ‘‘beneficial purposes’’ in
NTL–4A, this rulemaking further
clarifies which uses warrant royalty-free
treatment.
In addition, this section clarifies 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 communitized area has
historically been understood by the
BLM and by operators as a royalty-free
use, it is not specifically addressed in
NTL–4A but is now included in this
final rule.
As mentioned above, the BLM
received comments requesting that other
uses of oil or gas be identified as
royalty-free, including fuel for power
generation, pilot and assist gas, fuel for
heating, fuel for ancillary equipment,

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fuel to treat gas to remove impurities,
fuel to run completion and work over
equipment, and gas used for gas lift. The
BLM agrees that these uses are routine,
and therefore should not require prior
approval to be royalty-free.
Regarding using oil as a circulating
medium in drilling operations, or
injecting gas produced from a lease, unit
PA, or communitized area into the same
lease, unit, PA, or communitized area to
increase the recovery of oil or gas, the
BLM had proposed to include these uses
in the list in § 3178.5 of uses requiring
prior approval. As operators are already
required to report the use of oil as a
circulating medium in drilling
operations under Onshore Order
Number 1, and the use of gas for
injection under applicable regulations
in parts 3100, 3160 and 3180 of this
title, however, the BLM has decided not
to require prior approval for these uses.
In addition to the injection of gas for the
purpose of increasing the recovery of oil
or gas, the BLM has added the injection
of gas ‘‘for the purpose of conserving
gas’’ as a royalty-free use that does not
require prior written BLM approval
under the final rule. Often, gas injection
is used to enhance resource recovery by
maintaining or slowing the reservoir
pressure decline which leads to higher
oil recovery. The BLM also understands
that, in some circumstances, excess gas
that cannot be captured and sold or
used on lease may be injected in order
to conserve the gas. This practice occurs
in Canada’s Bakken field. While not all
reservoirs are conducive to gas
injection, the BLM believes it important
to provide that as an option to conserve
any gas that can’t be sold immediately.
Finally, this rule does not address
some uses that are already 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).
Overall, in response to comments
received, the BLM made the following
changes in the final rule:
• Modified paragraph (a)(1) to more
broadly address the use of fuel to
generate power, including the use of
fuel to operate ‘‘combined heat and
power,’’ which is a particularly efficient
means of generating power from gas;
• Combined and modified proposed
paragraphs (a)(2) and (a)(3) to include
artificial lift equipment and completion
and workover equipment;
• Renumbered the remaining
paragraphs accordingly;
• Added use of gas as a pilot fuel or
as assist gas for a flare, combustor,
thermal oxidizer, or other control
device, as paragraph (a)(5);

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• Added treatment of gas to
paragraph (a)(6); and
• Added two uses that will not
require prior written BLM approval for
royalty-free treatment, which were
identified in § 3178.5 in the proposed
rule as requiring prior approval: (1)
Using oil as a circulating medium in
drilling operations (paragraph (a)(8)),
and (2) injecting gas produced from a
lease, unit PA, or communitized area
into the same lease, unit PA, or
communitized area to for the purposes
of conserving gas or increasing the
recovery of oil or gas (paragraph (a)(9).
• Added injection of gas that is
cycled in a contained gas-lift system, as
paragraph (a)(10).
Section 3178.5 Uses of Oil or Gas on
a Lease, Unit, or Communitized Area
That Require Prior Written BLM
Approval for Royalty-Free Treatment of
Volumes Used
This section identifies uses of oil or
gas that will 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 all of the identified uses,
operators will 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 or gas that was removed
from the pipeline at a location
downstream of the approved facility
measurement point (FMP). The BLM
anticipates that these situations will 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 communitized
area, 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
will bear the burden of establishing the
necessity of off-lease treatment.

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• Any other types of use for
operations and production purposes
which are not identified in § 3178.4.
This provision clarifies that the BLM
retains discretion to consider approving
royalty-free use under circumstances
that are not now anticipated.
In response to comments described
below, the BLM made the following
three changes to the proposed rule
requirements: (1) Removed proposed
paragraphs (a)(1) and (a)(2) from this
section and moved them to § 3178.4
(royalty-free without prior approval); (2)
Added language to paragraph (2)
(paragraph (4) in the proposed rule) to
clarify that the provision applies to the
physical characteristics of the gas ‘‘that
require the gas to be treated or
processed prior to use’’; and (3)
Removed proposed paragraph (c) and
added language to paragraph (b)(1) that
indicates that royalties must be paid on
volumes when the BLM disapproves a
request for royalty-free treatment under
this section, and that any approvals for
royalty-free treatment will be effective
from the date the request was filed. Each
change is discussed below along with a
summary of the comments that lead to
the change.
Several commenters indicated that
some of the activities in proposed
§ 3178.5 should not require prior
approval. The BLM agrees and, in
response to this and other comments on
§ 3178.4, moved some provisions to
§ 3178.4, as described previously.
Additionally, some commenters
stated that operators should not be
required to seek prior approval for the
following two royalty-free uses: Gas
removed from a pipeline at a location
downstream of the FMP and gas initially
removed from a lease, unit participating
area, or communitized area for
treatment or processing where the gas is
returned to the lease, unit, or
communitized area for lease operation.
The BLM disagrees with these
comments and retained these
paragraphs in paragraphs (a)(1) and
(a)(2) of this section. Gas that is
removed from a lease, unit participating
area, or communitized area would
normally be royalty-bearing. Inclusion
of these uses in this section allows the
BLM the discretion to approve royaltyfree uses under the unique
circumstances in which gas is removed
and returned to the same lease, unit
participating area, or communitized
area.
Several commenters also stated that
the BLM did not adequately explain
why operators must ever receive agency
approval for royalty-free use of
production. Commenters stated that the
BLM must specify the standard or

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Federal Register / Vol. 81, No. 223 / Friday, November 18, 2016 / Rules and Regulations
criteria used to evaluate requests for
approval. The BLM has determined that
royalty-free uses requiring prior
approval are uses that do not typically
occur, that are not likely to apply to a
large number of operators, and that have
a higher risk of loss of gas depending on
the individual circumstances
surrounding the use. These factors
warrant individual approval by the BLM
on a case-by-case basis, and are not
situations in which development of
standard approval criteria is
appropriate.
Some commenters argued that the
BLM should remove the limitation,
included in the proposed rule, that gas
removed from the lease may only be
used on the lease royalty-free if it was
removed for treatment or processing ‘‘to
address a particular characteristic of the
gas.’’ The commenters stated that the
operator should not have the burden of
establishing the necessity of off-lease
treatment. In response to this comment,
the BLM revised paragraph (a)(2)
(paragraph (a)(4) in the proposed rule)
to clarify that the provision applies to
particular physical characteristics of the
gas ‘‘that require the gas to be treated or
processed prior to use.’’
Some commenters suggested that an
identified use should be royalty-free
until the BLM denies it, rather than
having to wait for the BLM to approve
it. In addition, one commenter
suggested that if the BLM does not,
within 30 days, respond to a Sundry
Notice requesting approval, the Notice
should be deemed approved. Another
commenter requested that approvals
should go into effect when the request
is filed. In response to these comments,
the BLM revised § 3178.5(b)(1) to
indicate that approvals will be effective
from the date the request was filed.
However, if the BLM disapproves a
request, the operator must pay royalties
on all volumes used, including those
used while the request was pending.
Several commenters stated that
exceptions for royalty-free use should
not be considered, that the rule allows
too much royalty-free venting and
flaring, or that the rule does not
sufficiently restrict royalty-free use that
results in emissions to the environment.
As stated in the proposed rule preamble,
however, royalty-free on-site use is
limited to reasonable uses that are not
wasteful. The BLM does not intend to
grant prior approval of royalty-free uses
under § 3178.5 unless it determines, in
light of available technology, that the
requested use is reasonable and not
wasteful. As a result, the BLM did not
revise this section in response to these
comments.

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Section 3178.6 Uses of Oil or Gas
Moved Off the Lease, Unit, or
Communitized Area That Do Not
Require Prior Written Approval for
Royalty-Free Treatment of Volumes
Used
This section identifies two
circumstances in which royalty-free use
of oil or gas that has been moved off the
lease, unit, or communitized area would
be permitted without prior BLM
approval. The first situation is where an
individual lease, unit, or communitized
area includes non-contiguous areas, and
oil or gas is piped directly from one area
of the lease, unit, or communitized area
to another area where it is used, and no
oil or gas is added to or removed from
the pipeline, even though the oil or gas
crosses lands that are not part of the
lease, unit, or communitized area.
Under this section, the BLM will
consider such production as not having
been ‘‘removed from the lease.’’ This
will provide the lessee or operator the
same opportunity for royalty-free use as
if the lease, unit, or communitized area
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 communitized
area, but produced oil or gas is used on
the same well pad for operations and
production purposes for that well. In
such situations, the rule allows for
royalty-free use at the well pad, without
prior approval. Use at off-lease well
heads is an established royalty-free
use.140
Commenters asserted that the
language in proposed paragraph (a) that
described reasons why oil or gas would
be moved off the lease, unit, or
communitized area was ambiguous. In
response to this comment, the BLM
simplified the language in this
paragraph to clarify the original intent
discussed above. Paragraph (a) of the
final rule now states: ‘‘The oil or gas is
transported from one area of the lease,
unit, or communitized area to another
area of the same lease, unit, or
communitized area where it is used, and
no oil or gas is added to or removed
from the pipeline while crossing lands
that are not part of the lease, unit, or
communitized area; . . . .’’
Section 3178.7 Uses of Oil or Gas
Moved Off the Lease, Unit, or
Communitized Area That Require Prior
Written Approval for Royalty-Free
Treatment of Volumes Used
This section addresses the royalty
treatment of oil or gas used in
140 Plains Exploration & Production Co., 178
IBLA 327, 341 n.16 (2010).

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83045

operations conducted off the lease, unit,
or communitized area. When
production is removed from the lease,
unit, or communitized area, it becomes
royalty-bearing unless otherwise
provided. This principle is reflected in
paragraph (a) of this section, which
provides that with only limited
exceptions, royalty is owed on all oil or
gas used in operations conducted off the
lease, unit, or communitized area.
Existing 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.’’ 141 New § 3178.6 will add
clarity and consistency in
implementation of that ONRR
regulation.
Paragraph (b) of this section identifies
circumstances in which, despite the
general rule articulated in paragraph (a),
the BLM will consider approving offlease royalty-free use (referred to here as
‘‘off-lease royalty-free uses’’). These
include situations in which the
operation is conducted using equipment
or at a facility that is located off the
lease, unit, or communitized area (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
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) requires the operator to
obtain BLM approval for off-lease
royalty-free use via a Sundry Notice
containing the information required
under proposed § 3178.9 of this subpart.
In response to a comment described
below, in the final rule the BLM added
the following provision to paragraph (c)
141 30

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of this section: ‘‘If the BLM disapproves
a request for royalty-free treatment for
volumes used under this section, the
operator must pay royalties on the
volumes. If the BLM approves a request
for royalty-free treatment for volumes
used under this section, such approval
will be deemed effective from the date
the request was filed.’’
Paragraph (d) of this section clarifies
that approval of off-lease measurement
or commingling under other regulatory
provisions does not constitute approval
of off-lease royalty-free use. An operator
or lessee must expressly request, and
submit its justification for, approval of
off-lease royalty-free use. The BLM
anticipates that generally such approval
would be appropriate only in some of
the situations in which the BLM has
approved measurement at a location off
the lease, unit, or communitized area, or
has approved commingling production
off the lease, unit, or communitized area
and allocating production back to the
producing properties.
Paragraph (e) of this section addresses
circumstances in which equipment
located on a lease, unit, or
communitized area also treats
production from other properties that
are not unitized or communitized with
the property on which the equipment is
located. An operator is allowed to 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 communitized area
on which the equipment is located,
unless otherwise authorized by the
BLM.
A commenter proposed that an
identified use should be royalty-free
until the BLM denies an application for
prior approval, rather than requiring an
operator to wait for the BLM to approve
the use. As stated above, in response to
these comments, the BLM revised
§ 3178.7(c) to indicate that approvals
will be effective from the date the
request was filed. However, if the BLM
disapproves a request, the operator must
pay royalties on all volumes used,
including those volumes used during
pendency of the request.
Commenters also suggested that the
proposed language in paragraph (e) was
inconsistent with the BLM’s goal of
encouraging operators to reduce the
amount of surface disturbance because
this provision would discourage
production from multiple leases. The
BLM disagrees. This section indicates
that only the portion of the oil or gas
used as fuel that is properly allocable to
the lease, unit, or communitized area on
which the equipment is located (onlease) is royalty-free; however, the
proportion of the oil or gas used from

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off-lease production may be approved
by the BLM for off-lease royalty-free use.
The BLM recognizes both the operating
efficiency and resource conservation
advantages of locating production
equipment from multiple wells on a
common site. The BLM did not revise
this paragraph in response to these
comments.
Another commenter suggested that
the BLM should approve all requests
unless it can demonstrate that particular
circumstances related to lease
operations justify disallowing royaltyfree use. The BLM disagrees with this
comment and did not modify the rule in
response to this comment. The MLA
exempts from royalties production that
is used on the lease for lease operations.
This rule allows for royalty-free off-lease
uses in some cases, including those
specified in § 3178.6 as not requiring
prior approval. The circumstances
described in § 3178.7 give the BLM the
flexibility to approve additional offlease royalty-free uses where the BLM
believes those uses are reasonable and
not wasteful.
Section 3178.8 Measurement or
Estimation of Volumes of Oil or Gas
That Are Used Royalty-Free
This 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 is free to choose whether to
measure or estimate, with the exception
that the operator must in all cases
measure the following volumes: (1)
Royalty-free gas removed downstream of
the FMP and used pursuant to sections
3178.4 through 3178.7; and (2) royaltyfree oil used pursuant to sections 3178.4
through 3178.7. When royalty-free oil or
gas is removed downstream of the FMP
and used pursuant to sections 3178.4
through 3178.7, the operator must apply
for a new FMP under section 3173.12 to
measure the gas that is removed for use.
If oil is used on the lease, unit or
communitized area, it is most likely to
be removed from a storage tank on the
lease, unit or communitized area. Thus,
paragraph (c) also requires the operator
to document the removal of the oil from
the tank or pipeline.
Paragraph (e) requires that operators
use best available information to
estimate gas volumes, where estimation
is allowed. For both oil and gas, the
operator must report the volumes
measured or estimated, as applicable,
under ONRR reporting requirements. As
revisions to Onshore Oil and Gas Orders
No. 4 and 5 have now been finalized as
43 CFR subparts 3174 and 3175,
respectively, the final rule text now
references § 3173.12, as well as § 3178.4

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through § 3178.7 to clarify that royaltyfree use must adhere to the provisions
in those sections. The BLM received
few, highly technical comments on this
section, which are addressed in the
Response to Comments document.
Section 3178.9 Requesting Approval of
Royalty-Free Treatment When Approval
Is Required
This section describes how to request
BLM approval of royalty-free use when
prior-approval is required under
§ 3178.5 or § 3178.7. The operator must
submit a Sundry Notice containing
specified information, which is
necessary for the BLM to determine if
approval is appropriate. The
information includes 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 use of the oil or gas. This
section was finalized as proposed, with
minor wording changes to improve
clarity. The BLM received few, highly
technical comments on this section,
which are addressed in the Response to
Comments document.
Section 3178.10 Facility and
Equipment Ownership
This section clarifies that although the
operator is not required to own or lease
the equipment that uses oil or gas
royalty-free, the operator is responsible
for all authorizations, production
measurements, production reporting,
and other applicable requirements. The
BLM did not receive significant
comments on this section and did not
revise this section from the proposed
rule.
Subpart 3179—Waste Prevention and
Resource Conservation
Section 3179.1 Purpose
As in the proposed rule, this section
states that the purpose of subpart 3179
is to implement 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
section also provides that subpart 3179
supersedes those parts of NTL–4A that
pertain to venting and flaring of
produced gas, unavoidably and
avoidably lost gas, and waste
prevention.
One commenter stated that BLM
should clarify whether subpart 3179
replaces NTL–4A and that NTL–4A is
no longer applicable, or if subpart 3179
only supersedes part of NTL–4A. As
stated previously, subpart 3178 replaces
the portion of NTL–4A pertaining to the

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use of oil or gas for beneficial purposes,
and subpart 3179 replaces the portion of
NTL–4A pertaining to flaring and
venting of produced gas, unavoidably
and avoidably lost gas, and waste
prevention. Together, the combined
revisions to subparts 3178 and 3179
supersede NTL–4A in its entirety.

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Section 3179.2 Scope
This section specifies which leases,
agreements, tracts, facilities, and gas
lines are covered by this subpart. The
section also states that the term ‘‘lease’’
in this subpart includes IMDA
agreements, unless specifically
excluded in the agreement or unless the
relevant provisions of this subpart are
inconsistent with the agreement. The
BLM did not revise this section from the
proposed rule.
Some commenters stated that the
scope of the rule is too broad. Some
commenters suggested limiting its scope
to leases with more than 51 percent
Federal interest, while others suggested
that the BLM clarify that this subpart
does not apply to exploration, wildcat,
or delineation wells. The BLM disagrees
that the scope of the rule is too broad,
and did not revise this section based on
these comments. As discussed earlier in
this Preamble, the BLM has both the
authority to ensure that operators take
reasonable precautions to prevent the
waste of Federal and Indian oil and gas.
The fact that this final rule may impact
some leases with minority Federal or
Indian interest does not deprive the
BLM of its authority to impose
reasonable waste prevention
requirements on operators producing
Federal or Indian oil or gas.
Finally, the BLM notes that the rule
generally applies to all oil and gas wells,
including exploratory, wildcat, and
delineation wells. Provisions of the rule
that apply more narrowly explicitly
indicate the narrower scope; for
example, the gas capture requirements
in section 3179.7 apply only to
‘‘development oil wells.’’
Section 3179.3 Definitions and
Acronyms
This section contains definitions for
terms that are used in subpart 3179:
‘‘accessible component’’; ‘‘automatic
ignition system’’; ‘‘capture’’ and
‘‘capture infrastructure’’; ‘‘compressor
station’’; ‘‘continuous bleed’’;
‘‘development oil well’’ or
‘‘development gas well’’; ‘‘gas-to-oil
ratio’’; ‘‘gas well’’; ‘‘high pressure flare’’;
‘‘leak’’; ‘‘leak component’’; ‘‘liquid
hydrocarbon’’; ‘‘liquids unloading’’;
‘‘lost oil’’ or ‘‘lost gas’’; ‘‘pneumatic
controller’’; ‘‘storage vessel’’; and
‘‘volatile organic compounds.’’ Some

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defined terms have a meaning particular
to this rule. Other defined terms may be
familiar to many readers, but are
defined in the regulatory text to enhance
the clarity of the rule.
In response to comments, the final
rule adds several definitions that were
not included in the proposed rule,
including ‘‘automatic ignition system’’;
‘‘continuous bleed’’; ‘‘high pressure
flare’’; ‘‘leak’’ and ‘‘leak component’’
(which replaced the term ‘‘component’’
from the proposed rule); and
‘‘pneumatic controller.’’ The final rule
also adds a definition of ‘‘compressor
station’’ that is consistent with the
definition in subpart OOOOa, as the
final rule leak detection provisions and
the subpart OOOOa leak detection
provisions both refer to compressor
stations. In addition, the definition of
‘‘storage vessel’’ has been expanded to
clarify the types of vessels covered by
section 3179.203. The definitions of
‘‘development oil well’’ and
‘‘development gas well’’ include minor
wording changes for clarity.
Some commenters expressed concerns
that the proposed definition of a storage
vessel in § 3179.3 does not match the
definition provided in subparts OOOO
and OOOOa. Commenters asserted that
the definition proposed by the BLM
applies the 6 tpy VOC threshold for
applicability to a whole tank battery, as
well as to a single tank, making the
proposed rule significantly more
stringent than the EPA OOOOa rule,
which only applies if an individual
storage vessel exceeds the threshold.
Commenters also noted that the EPA
definition of storage vessel excludes
portable tanks temporarily located at the
well site, and they recommended that
the BLM take the same approach as the
EPA by aligning the BLM’s definition
with the EPA definition. Other
commenters supported the BLM’s
proposed definition of storage vessel, as
it could apply the requirements for
storage vessels to a collection of lowemitting single tanks that would not
otherwise meet the threshold.
Based on input from commenters, the
BLM has revised its definition of storage
vessel to be largely consistent with the
EPA subpart OOOO and subpart
OOOOa definitions. The BLM removed
the reference to a ‘‘battery of tanks’’ and
added provisions excluding temporary
tanks from the definition of a storage
vessel. The BLM believes that this is a
reasonable approach. The 6 tpy
threshold identifies a quantity of lost
gas that is reasonably cost-effective to
address at an individual tank, without
regard to the type of vessel or fluid
stored. Avoiding the same quantity of
lost gas from a battery of tanks would

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effectively lower the tank size threshold
for coverage and would be considerably
less cost-effective, as the same type of
equipment would have to be installed
on multiple tanks with smaller releases.
The BLM has also excluded from the
definition of storage vessel tanks storing
hydraulic fracturing fluid prior to
implementation of an approved
permanent disposal plan under Onshore
Oil and Gas Order No. 7. This revision
ensures that the final rule will not
overlap with BLM rules governing
hydraulic fracturing activities.
Commenters also suggested that the
BLM adopt definitions for ‘‘pneumatic
controllers’’ and ‘‘continuous bleed’’
that are consistent with the definitions
in subpart OOOOa. The BLM agrees that
aligning the definitions in the BLM and
EPA rules to the extent possible will
reduce the potential for confusion.
Accordingly, § 3179.3 includes
definitions for ‘‘pneumatic controllers’’
and ‘‘continuous bleed’’ that are
consistent with the definitions of these
terms in subpart OOOOa.
In order to provide clarity, BLM has
included definitions of ‘‘automatic
ignitor system’’ and ‘‘high pressure
flare’’ in the final rule. The final rule
defines an ‘‘automatic ignition system’’
as an automatic ignitor and, where
needed to ensure continuous
combustion, a continuous pilot flame. A
‘‘high pressure flare’’ is defined as an
open-air flare stack or flare pit designed
for the combustion of natural gas
leaving a pressurized production vessel
(such as a separator or heater-treater)
that is not a storage vessel.
Section 3179.4 Determining When the
Loss of Oil or Gas Is Avoidable or
Unavoidable
This section describes the
circumstances under which lost oil or
gas is classified as ‘‘unavoidably lost.’’
‘‘Avoidably lost’’ oil or gas is then
defined as oil or gas that is not
unavoidably lost. The descriptions in
the rule enhance clarity and consistency
by listing specific circumstances under
which oil and gas may be ‘‘unavoidably
lost’’ when the 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 also defines 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.
Finally, this section defines
‘‘avoidably lost’’ oil or gas as lost oil or
gas that does not meet this section’s

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definition of ‘‘unavoidably lost.’’ Also
included in the ‘‘avoidably lost’’
category is any ‘‘excess flared gas,’’
which § 3179.7 defines as the quantity
of flared gas by which the operator fell
short of the applicable capture
requirement specified in that section.
In response to comments received, the
final rule added two new items to the
list of operations and sources that are
considered unavoidably lost: (1) Gas lost
during facility and pipeline
maintenance, such as when an operator
must blow-down and depressurize
equipment to perform maintenance and
repairs, which includes ‘‘pigging’’ of
lines to remove liquids, and (2) flaring
of gas from which at least 50 percent of
natural gas liquids have been removed
and captured for market, if the operator
has notified the BLM through a Sundry
Notice that the operator is conducting
such capture.
The final rule also makes the
following four clarifications to items
that were included on the proposed list
of operations and sources that are
considered unavoidably lost, and that
remain on that list in the final rule: (1)
Normal operating losses from a natural
gas-activated pneumatic controller or
pump are considered unavoidable,
provided the controller or pump
complies with §§ 3179.201 and
3179.202; (2) normal operating losses
from storage vessels and other low
pressure production vessels are
considered unavoidable provided the
vessels are in compliance with
§§ 3179.203 and 3174.5; (3) losses from
well venting in the course of downhole
well maintenance and/or liquids
unloading are considered unavoidable
provided those operations are
conducted in compliance with
§ 3179.204; and (4) leaks are considered
unavoidable, provided the operator has
complied with the leak detection and
repair requirements of §§ 3179.301
through 3179.305.
The BLM also modified the proposed
treatment of gas that is lost from a well
that is not connected to a pipeline to
align this provision with the revised
approach in the final rule that addresses
flaring through capture targets instead of
flaring limits. The BLM had proposed
that gas flared in excess of the
applicable flaring limit would be
considered avoidable. The final rule
deems avoidable any gas that is
‘‘excess’’ relative to the capture target.
The term ‘‘excess flared gas’’ is defined
in § 3179.7.
The principle underlying both the
proposed and final regulatory text with
respect to excess flared gas is that a
prudent and reasonable operator will
not routinely flare an unlimited quantity

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of natural gas from a development oil
well. In this rulemaking, the BLM is
modernizing and clarifying the criteria
for determining when incidental and
necessary disposal of gas accompanying
oil production crosses the line into
unreasonable waste of public gas
resources, and the final rule expresses
these criteria in the form of a gas
capture target. When an operator is not
meeting the applicable gas capture
target, specified in § 3179.7 the BLM
deems the excess flared gas volume—
that is, the volume that caused the
operator to fall short of the capture
target—to be waste, avoidable, and
subject to royalties.
Several commenters disagreed with
BLM’s proposed definitions of ‘‘waste’’
and ‘‘avoidably lost.’’ Many commenters
felt that the BLM should maintain the
definitions used in NTL–4A, including
applying an economic test to determine
what degree of capture is economical for
the operator. These comments are
addressed in section V.C of this
preamble.
Some commenters stated that the
BLM should consider gas lost during
force majeure events as unavoidably
lost. The BLM does not agree that all
losses during force majeure events
should be considered unavoidable. Such
events may be out of the control of
operators, but they are often expected
and operators can therefore plan for
them. The final rule does include as
justifications for unavoidable loss some
specific events that are generally
considered force majeure events, such
as emergencies. However, the gas
capture requirements in the final rule
are structured to provide operators
substantial flexibility to meet the
capture targets without providing a
blanket exemption for all events that the
operator does not directly control. For
example, scheduled maintenance of
downstream pipeline or processing
plants is neither unexpected nor
unusual, and the BLM believes an
operator should be able to plan ahead to
address those events—for example, by
identifying alternative capture
approaches or planning to temporarily
reduce production or shut in the well to
address these circumstances.
Moreover, as described in Preamble
Section V.A, Venting Prohibition and
Capture Targets, the final rule allows
operators to meet the capture target on
average over a month at all of the wells
on a lease, unit, or communitized area,
or alternatively, on average over a
month at all of the operator’s wells in
a county or state. A prudent and
reasonable operator will be able to take
advantage of this flexibility to ensure
that it has captured enough gas over the

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month, somewhere in the averaging
area, to provide itself a sufficient buffer
in meeting the gas capture targets to
accommodate force majeure events that
may not be within its control, but are
common and predictable.
Relatedly, some commenters
requested that gas lost because of ROW
delays should be considered
unavoidably lost. This preamble
addresses the issue of ROW delays in
Section VI.E. For the reasons discussed
there, the BLM declines to make this
change, which goes to the central
premise of the gas capture requirement.
The BLM has determined that it is not
reasonable for operators to develop oil
wells and plan to use flaring as the
primary and routine disposal method
for the associated gas. Rather, these
rules require oil well operators, over
time, to plan to capture an increasing
percentage of their associated gas. In the
near-term, the BLM believes that the gas
capture targets, combined with the
quantities of allowable flaring and the
ability to average, are sufficiently
generous to allow operators to manage
short-term delays in planned gas
pipeline infrastructure with little
difficulty, using production deferment
and on-site capture at some wells where
necessary. Over the longer term, a
reasonable operator can continue to use
those tools as well as working with the
midstream companies to ensure that
there is adequate pipeline capacity
available to support transport of
associated gas prior to building out large
well developments.
Many commenters requested that the
BLM grandfather all existing
determinations of royalty-free flaring.
Again, this change would undercut a
key goal of this rulemaking: Gradually,
over time, to require operators to reduce
routine flaring of associated gas from
development oil wells. With the
generous phase-in schedule for the gas
capture targets and the quantities of
allowable flaring, this rule requires only
modest near-term reductions in flaring
from existing wells. The BLM believes
that it is entirely reasonable to expect
operators to work, over time, to reduce
flaring from their existing wells, as well
as from new developments. Moreover,
for this rule to have any meaningful
effect on flaring, it must cover both
existing and new development.
Allowing all current determinations of
royalty-free flaring to persist in
perpetuity is unnecessary and would
substantially undercut the effectiveness
of this rule.

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Section 3179.5 When Lost Production
Is Subject to Royalty
This section provides that royalties
are due on all avoidably lost oil or gas,
but not on unavoidably lost oil or gas.
We received no significant comments on
this section, and the final rule is very
similar to the proposed rule with minor
wording changes to improve clarity.

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Section 3179.6 Venting and Flaring
From Gas Wells and Venting Prohibition
This section expressly prohibits all
venting and flaring from gas wells,
except where the gas is unavoidably lost
pursuant to section 3179.4(a). In
addition, this section requires operators
to flare rather than vent all gas that is
not captured, except under certain
limited circumstances. Operators will be
allowed to vent gas in the following
situations: (1) When flaring is
technically infeasible—for example if
the volumes of gas are too small to
operate a flare (such as so-called
bradenhead gas), or if the gas is not
readily combustible; (2) under
emergency conditions, when the loss of
gas is uncontrollable or venting is
necessary for safety; (3) when the gas is
vented through normal operation of a
natural gas-activated pneumatic
controller or pump; (4) when the gas is
vented from a storage vessel, provided
that § 3179.203 does not require the
combustion or flaring of the gas; (5)
when the gas is vented during downhole
well maintenance or liquids unloading
activities performed in compliance with
§ 3179.204; (6) when the gas is vented
through a leak where the operator is in
compliance with § 3179.301–305; (7)
when venting the gas is necessary to
allow non-routine facility and pipeline
maintenance to be performed, such as
when an operator must, upon occasion,
blow-down and depressurize equipment
to perform maintenance or repairs; and
(8) when release of gas is unavoidable
and flaring is prohibited by Federal,
State, local or Tribal law, regulation, or
enforceable permit term.
The BLM made the following changes
to the proposed rule requirements: (1)
Changed the title of this section; (2)
added a new section (a) that expressly
prohibits venting or flaring gas from gas
wells, except where the gas is
unavoidably lost pursuant to section
3179.4(a); (3) renumbered paragraphs
(a)(1) and (2) paragraphs (b)(1) and (2);
(4) moved discussion of venting from a
storage vessel from proposed paragraph
(a)(3) to paragraph (b)(4) and added
language clarifying that such venting is
permitted when § 3179.203 does not
require combustion or flaring of the gas;
(5) renumbered proposed paragraph

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(a)(4) as paragraph (b)(3) and qualified
that venting from a natural gas-activated
pneumatic controller or pump is
permitted during normal operation and
when the pump is in compliance with
§ 3179.201 and § 3179.202; (6) Added
paragraphs (b)(5) through (b)(8) that
describe additional cases when venting
of gas is permitted (situations 4–8 in the
previous paragraph); (7) Removed all of
proposed paragraph (b) describing
venting or flaring volume limits,
because flaring limits are now addressed
in a new § 3179.7; and (8) Added a new
paragraph (c), which requires that all
flares or combustion devices be
equipped with an automatic ignition
system.
Section 3179.6(a) carries forward
NTL–4A’s express prohibition on
venting and flaring from gas wells.
Section IV.A of NTL–4A prohibits the
venting or flaring of gas well gas, except
for unavoidable losses and short-term
venting and flaring during emergencies,
well purging and evaluation tests, initial
production tests, and wells tests
(circumstances now defined as
unavoidable in section 3179.4(a)).
Similar restrictions on venting and
flaring from gas wells were implied in
the proposed rule; the BLM has chosen
to state this explicitly in the final rule
in order to avoid confusion.
Key comments received on this
section are discussed in Section III.B.1.b
of this preamble. Additional substantial
comments received on the venting
prohibition provisions are discussed
below.
The BLM received comments
asserting that the BLM lacked the
statutory authority to require operators
to flare rather than vent gas that is not
captured. Commenters argued that such
a requirement does not fall within the
BLM’s waste-prevention authority under
the MLA because shifting from venting
to flaring does not prevent waste as the
gas is lost in either case. These
commenters then argued that the only
possible justification for the
requirement to flare rather than vent is
control of GHGs and other air
pollutants, which commenters assert is
exclusively within the EPA’s domain.
The BLM disagrees with these
comments for several reasons. First, the
requirement in this section to flare
rather than vent does result in waste
prevention, because it is paired with
provisions that limit total flaring—
namely, the gas capture requirements in
§ 3179.7. Under § 3179.7(c), the
denominator in the gas capture
percentage calculation is ‘‘the total
volume of gas captured over the month
plus the total volume of gas flared over
the month from high-pressure flares

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from all of the operator’s development
oil or gas wells in the relevant area,
minus’’ a declining ‘‘flaring allowable’’
volume.. By requiring that operators
shift from venting to flaring, the BLM is
effectively increasing operators’ flared
volume in a given month, which in turn
increases the total volume of gas that the
operators must capture in that month.
Second, directing associated gas to a
flare rather than allowing operators to
vent it improves waste accounting
because under final rule § 3179.9,
operators must measure volumes above
50 Mcf per day that are flared from a
high pressure flare stack or manifold. By
shifting operators from venting to
flaring, § 3179.6 will likely increase the
number of operators that must measure
their flared gas volumes under § 3179.9.
This will, in turn, improve operators’
(and the BLM’s) waste accounting.
Better waste accounting is itself a waste
prevention measure, because it gives the
BLM and operators a better sense of how
much gas is being wasted—and thus
how much could be made available for
productive use and/or sold to offset the
costs of waste prevention equipment.
Third, this requirement constitutes
waste prevention when applied to
operator flaring during activities
regulated under §§ 3179.102, 3179.103,
and 3179.104. Under §§ 3179.102 and
.103, flaring during well completion and
initial production testing that exceeds
20 MMcf/well is treated as avoidably
lost gas subject to royalties under
§ 3179.4(a)(1)(C). The BLM believes that
in many instances, the venting
prohibition in § 3179.6 may result in
operators reaching the 20 MMcf/well
royalty flaring threshold sooner, thereby
providing an additional financial
incentive for operators to reduce waste.
Under § 3179.104, all flaring during
subsequent well tests that exceeds 24
hours is treated as avoidably lost gas
subject to royalties under
§ 3179.4(a)(1)(D).
Fourth, as discussed above, the
requirement to flare rather than vent
associated gas is justified as a safety
measure under the MLA. It is generally
safer to combust methane gas than allow
it to vent uncombusted into the
surrounding air due to concerns over
methane’s explosiveness and the risks to
workers of hypoxia and exposure to
various associated pollutants.142 Fifth,
and as also discussed above, even if the
venting prohibition were purely an air
quality control measure, the BLM does
have the authority to regulate air quality
142 NIOSH–OSHA Hazard Alert entitled, ‘‘Health
and Safety Risks for Workers Involved in Manual
Tank Gauging and Sampling at Oil and Gas
Extraction Sites,’’ February 2016, www.osha.gov.

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and GHG impacts on and from the
public lands, pursuant to FLPMA and
the MLA, as discussed in Section III.C
of this Preamble.
Several commenters stated that
operators should be required to capture
all natural gas from all wells, with no
exceptions, or that if flaring is allowed,
combustion devices should be required
to have a design destruction efficiency
of at least 98%, that enclosed flares
should be required, and that flares
should be required to be equipped with
a continuous pilot light and an autoignition system. As discussed in Section
III.B.2 of this preamble, the BLM does
not believe that it is feasible to eliminate
all venting and flaring, but we have
revised both the flaring requirements
and the circumstances when venting is
permitted in response to comments. The
BLM also is not adding a requirement
for flares to have a design destruction
efficiency of 98%. Many existing flares
have a design combustion efficiency of
95%, rather than 98%.
The BLM has added a requirement in
the final rule that flares must be
equipped with an automatic ignition
system, which will provide the flare
system with an effective method of
ignition in the case of interruption. The
term ‘‘automatic ignition system’’
implies the concept of maintaining an
ignition source without specifying a
particular type of device, and the BLM
believes that operators will utilize
devices that are appropriate for the
circumstance. The BLM does not believe
that requiring a specific device, such as
a continuous pilot, would necessarily
result in reduced waste relative to a
more general requirement for an
automatic ignition system.
Some commenters requested that the
BLM allow venting when flaring is not
economically feasible. The BLM
believes that this change is unnecessary,
would add substantial ambiguity to the
rule, and could significantly weaken the
requirement to flare rather than vent.
Flaring rather than venting gas that is
not being captured is widespread
industry practice, due in large part to
safety concerns. While there are
situations where the quantities of gas
are too small or difficult to allow for
flaring, the rule explicitly allows
venting in lieu of flaring in those
situations. It is not clear to the BLM
what other circumstances would render
flaring ‘‘economically infeasible,’’ or
what specific concerns the commenter
is trying to address.
A commenter seeking to minimize
exceptions to the venting prohibition
asked the BLM to define the term
‘‘technically infeasible.’’ Given the wide
variety of situations that are likely to

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occur on a lease that inform an
operator’s determination of technical
feasibility, the BLM does not believe
that it is appropriate to add further
specificity to this term. If there is a
dispute about the term in a specific
case, the BLM has the final say in
determining whether flaring is, in fact,
technically infeasible.
Section 3179.7
Requirement

Gas Capture

Final rule § 3179.7 houses a modified
version of the flaring requirements that
were in proposed rule s 3179.6. As
discussed in Section III.B.2.a, the final
rule alters how the proposed rule
constrained the quantities of gas lost
through flaring, but achieves similar
flaring reductions by requiring operators
to meet specified monthly capture
targets (subject to shrinking flaring
allowances), rather than setting per well
numeric flaring limits.
Final rule § 3179.7 establishes capture
targets that increase over the first nine
years of rule implementation.
Paragraphs (a) and (b) describe the
capture percentage requirements. The
schedule for the capture targets is
provided in § 3179.7(b)(1)–(4) and is
reproduced in Section III.B.2.a of this
preamble. Paragraph (c) defines
‘‘capture percentage,’’ ‘‘total volume of
gas captured,’’ ‘‘adjusted total volume of
gas produced,’’ and ‘‘relevant area.’’
Under § 3179.7(c)(3), an operator may
choose whether to comply with the
capture targets on each of the operator’s
leases, units or communitized areas, or
on a county-wide or state-wide basis.
Section 3179.7(c)(4) defines when an oil
or gas well is considered ‘‘in
production’’ and therefore subject to the
capture targets in this section. Section
3179.7(d) establishes an equation for
determining the quantity of ‘‘excess
flared gas’’—that is, the volume of flared
gas that causes an operator to fall short
of the applicable capture target in a
given month, and that is therefore
subject to royalties. Section 3179.7(e)
requires operators to prorate the excess
flared gas to each lease, unit, or
communitized area that reported highpressure flaring, for purposes of
calculating royalties.
As discussed in Section III.B.2 of this
preamble, the BLM developed the
capture target approach in final rule
§ 3179.7 after careful consideration of
the many comments received on the
flaring limit approach taken in proposed
rule § 3179.6(b). The key comments
received on § 3179.7 and BLM’s
response to these comments are also
discussed in Section III.B of this
preamble. Additional substantive

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comments received on the proposed
flaring provisions are discussed below.
Several commenters asserted that the
ability to avoid flaring depends on the
capacity of gathering lines, and that
operators must prove production for a
new oil play and initiate larger scale
development before gathering and/or
processing companies are willing to
invest in infrastructure. These
comments informed the revisions to the
flaring revisions made in the final rule.
The BLM also recognizes that currently
the optimal mechanism to capture gas is
through connecting to a pipeline, which
may take time to achieve in some areas
due to lagging infrastructure and
capacity constraints. As a result, the
final rule provides additional time and
flexibility for industry to plan and better
coordinate development of production
wells with development of pipelines to
transport the production. As discussed
in section III.B.2, the final rule provides
an option for operators to comply with
the capture targets on a lease-by-lease,
county-wide, or state-wide basis, and
also phases in the capture targets over
a longer period of time. These changes
will allow sufficient time and flexibility
to enable industry to better align oil
development with gas infrastructure
over time.
On the other hand, given the BLM’s
statutory obligation to reduce waste of
gas, the clear technical capability of
operators to capture gas, the economic
value of the gas, and the environmental
impacts of not capturing it, the BLM has
determined that it is not reasonable to
allow operators to dispose of large
quantities of associated gas from
development oil wells using routine
flaring. The final rule therefore
structures the capture targets in a way
that the BLM estimates will achieve
slightly greater flaring reductions than
the proposed rule, albeit over a longer
timeframe.
Many commenters asserted that onsite capture technologies are not
technically feasible and/or economically
viable. In the proposed rule, we
discussed research indicating that LNG
stripping, CNG, and gas-to-power are
commercially mature technologies that
are portable, scalable, and have been
utilized economically at well sites.143
Moreover, MJ Bradley released a reanalysis of the economic analysis in the
proposal, which suggests that for over
500 of the leases in the BLM data set,
the CNG trucking option would have
total net benefits that exceed total lessee
143 81 FR 6641. See also Carbon Limits.
‘‘Improving Utilization of Associated Gas in US
Tight Oil Fields’’. 2015. Available athttp://
www.catf.us/resources/publications/files/Flaring_
Report.pdf y.

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costs by approximately $56.5 million
over a 10 year period.144 The BLM
agrees with the commenter’s assertion
that these remote-site capture
technologies may not be viable at all
well sites. However, they are viable and
currently used at some sites. The final
rule’s option allowing operators to
average compliance across all of their
wells in a county or State
accommodates this heterogeneity in
site/technology compatibility: Operators
can deploy on-site capture technologies
where it is most cost-effective, and use
the increased capture rates at those sites
to offset continued flaring at other sites.
The BLM also notes that leasing on-site
capture equipment during the earlier
periods of well production, when
associated gas levels and corresponding
potential revenues are highest, can
enhance the cost-effectiveness of the
technologies. Leasing allows operators
to avoid upfront capital costs associated
with purchasing equipment, making it
easier to use such equipment only for
periods in the well’s life when it is most
economic to do so. This strategy also
allows operators to match equipment
size to expected associated gas
production volumes at different stages
of well production. Finally, on-site
capture technology capital costs may
continue to decline as the market
further matures and achieves greater
economies of scale.
Several commenters expressed
concern about delays in approvals of
ROWs for gas pipelines, and asserted
that such delays will prevent operators
from complying with the capture
targets. These comments are addressed
in Section VI.E of this preamble.

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Section 3179.8
Requirement

Alternative Capture

Section 3179.8 (§ 3179.7 in the
proposed rule) describes an alternative
process that is available to an operator
that cannot meet the capture targets
described in final rule § 3179.7. Under
§ 3179.8, an operator that cannot meet
the capture targets may request that the
BLM establish an alternative capture
target if three conditions are met: (1)
The operator has chosen to comply with
the capture target using the lease-bylease, unit-by-unit, or communitized
area-by-communitized areas basis rather
than the averaging approach; (2) the
potentially noncompliant lease was
issued before the effective date of this
final rule; and (3) the operator
demonstrates via Sundry Notice, and
144 M.J. Bradley and Associates. ‘‘Re-analysis of
Proposed BLM Flaring Reduction Rule; Projected
Costs and Benefits’’. September 9, 2016. Pages 13–
14.

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the BLM agrees, that the applicable
capture percentage under final rule
§ 3179.7 ‘‘would impose such costs as to
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease.’’
As discussed in Section V.B.2.b of
this preamble, § 3179.8 was revised in
the final rule to reflect the shift to gas
capture targets in final rule § 3179.7.
Section 3179.8(a) was also revised to
reflect the three conditions discussed
above. Section 3179.8 (b) describes the
information an operator must submit in
the Sundry Notice. The final version of
this paragraph makes minor
modifications relative to the proposed
version, including: Adding the phrase,
‘‘to the extent that the operator is able
to obtain this information,’’ to the
requirements to include pipeline
capacity and the operator’s projections
of the cost associated with installation
and operation of gas capture
infrastructure; adding cost projections
for alternative methods of transportation
that do not require pipelines; specifying
that the cost projections required in
final § 3179.8(b)(5)(i) must be based on
the next 15 years or the life of the lease,
unit, or communitized area, whichever
is less; and dropping the requirement to
provide the depths and names of
producing formations. Section 3179.8(c)
remains similar to the proposed rule
(§ 3179.7(c)), with flaring limits changed
to capture percentages. The final rule
also does not contain the renewable 2year exemption in proposed § 3179.7(d).
The key comments received on this
section and BLM’s response to these
comments are discussed in Section
III.B.2.b of this preamble. Additional
substantive comments received on the
proposed flaring provisions are
discussed below.
Some commenters asserted that the
proposed alternative capture and related
Sundry Notice requirements were overly
burdensome and required submission of
confidential information. These
commenters contended that oil and gas
price and production volume forecasts
and pipeline and gas capture costs are
considered confidential business
information. Commenters also claimed
that operators do not have access to
information on pipeline capacity.
The BLM does not agree that the
Sundry Notice requirements for a
request for an alternative capture
requirement are unduly burdensome,
although the BLM has streamlined the
proposed requirements in the final rule
where it was possible to do so without
losing information that would be
necessary to evaluate a request.
Commenters did not explain how the
BLM would be able to determine

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whether a request met the criteria for
approval absent the required
information. Also, operators routinely
provide information to the BLM that
they consider confidential; if they
indicate on the Sundry Notice that the
information is considered confidential,
the BLM will handle the information in
accordance with applicable regulations
in 43 CFR part 2. In response to
statements that commenters may not
have access to information on pipe
capacity, the BLM revised the final rule
to state that data on pipeline capacity
and the operator’s projections of the cost
associated with installation and
operation of gas capture infrastructure is
required to the extent that the operator
is able to obtain such information.
Some commenters requested that the
BLM clarify what ‘‘significant’’ means
with regard to recoverable oil reserves
in § 3179.8(c), while another
recommended that the criteria should be
based on an economic test that would
grant an alternative limit if the return on
investment would be too low for a
prudent operator to proceed with
compliance. Another commenter stated
that new wells should also be allowed
to apply for alternative limits. Other
commenters asserted that the BLM
should eliminate or substantially
narrow the approval of alternative
limits, with one commenter stating that
the BLM should determine approval of
alternative limits based on a cost-benefit
analysis that includes the consideration
of environmental benefits.
The BLM did not revise the rule based
on these comments, but we are
providing here additional clarification
on the BLM’s interpretation of this
standard. The BLM believes that
requiring the operator to demonstrate
that the applicable capture percentage
under § 3179.7 would ‘‘impose such
costs as to cause the operator to cease
production and abandon significant
recoverable oil reserves’’ is an
appropriate threshold for granting
alternative capture requirements. The
BLM recognizes that the term
‘‘significant’’ is a qualitative rather than
quantitative metric. The BLM
considered development of a
quantitative metric, but determined that
setting a quantitative threshold, such as
number of days of production lost,
might be arbitrary and ineffective.
Moreover, the BLM has a history of
reviewing and effectively evaluating
requests based on similar qualitative
criteria. While we do not expect there to
be a significant change in the review of
these requests from prior practice, as
discussed in the preamble to the
proposed rule, we do expect that
spelling out the requirements and

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qualitative criteria more clearly in
today’s rule will ensure a more
consistent review and approval process.
The BLM notes that the phrase ‘‘cease
production and abandon significant
recoverable oil reserves’’ is not intended
to require an operator to demonstrate
that the lease could never be developed
under any future circumstances. Yet nor
would it be sufficient for an operator to
show that compliance with the capture
targets would cause the operator to shut
in the wells on a lease for a limited
period of time. Rather, the operator
must make a showing that the cost of
complying with the capture
requirements would cause the operator
to shut in the wells on the lease under
current market conditions and for the
reasonably foreseeable future, taking
into account uncertainty regarding the
long-term recoverable potential of the
lease and reservoir. In other words, the
showing should illuminate whether
compliance would cause the operator to
be deprived of the value of the lease, not
simply cause a reduction in profit. For
example, depending on the specific
economic circumstances of the lease, it
may be sufficient for an operator to
show that it would have to shut in the
wells on a lease for a time period on the
order of a year or two. The BLM notes,
however, that it is not uncommon for
operators to shut in and restart
production due to market conditions,
and a showing under this exemption
should demonstrate a more significant
impact that is clearly distinguishable
from such normal fluctuations.
With respect to the request to allow
an alternative capture target to apply to
new wells, the BLM notes that the
alternative is limited to existing leases,
not existing wells. Thus, the alternative
capture target is potentially available
with respect to an existing lease with
new wells. Moreover, the BLM believes
that with the extended phase-in of the
capture targets and the state- and
county-wide averaging option, operators
have ample flexibility to take the
capture targets into account as they
develop new production wells. Indeed,
this rule encourages such planning by
requiring operators to submit waste
minimization plans with their APDs.
Further, the BLM does not believe that
the opportunity to request an alternative
capture target should be extended to
new leases. Operators have broad
flexibility to plan to meet the capture
targets at the time that they bid on new
leases.
Some commenters requested that the
Sundry Notices be processed in a timely
manner, and that the BLM provide a
schedule for applying for and being
granted an alternative capture

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percentage. One commenter suggested
that the BLM should align the phase-in
of the rule with the time it would take
to for the BLM to approve the requests
for alternate capture targets. Given that
the final rule phases in the capture
targets over a longer period of time, the
BLM expects that operators will have
sufficient time to prepare their Sundry
Notice requests for alternative capture
targets if needed. Additionally, the BLM
does not anticipate receiving a large
number of Sundry Notice requests for
alternative capture targets, and therefore
anticipates that it will have adequate
time to review them in a timely manner.
Section 3179.9 Measuring and
Reporting Volumes of Gas Vented and
Flared
This section (which was § 3179.8 in
the proposed rule) requires operators to
estimate (using estimation protocols) or
measure (using a metering device) all
flared and vented gas, whether royaltybearing or royalty-free. This section
further provides that specific
requirements apply when the operator is
flaring 50 Mcf or more of gas per day
from a high pressure flare stack or
manifold, based on estimated volumes
from the previous 12 months, or based
on estimated volumes over the life of
the flare, whichever is shorter.
Beginning one year from the effective
date of the rule, when this volume
threshold is met, the operator must
measure the volume of the flared gas, or
must calculate the volume of the flared
gas based on the results of a regularly
performed GOR test, so as to allow the
BLM to independently verify the
volume, rate, and heating value of the
flared gas. This section also requires
operators to report all volumes vented
or flared under applicable ONRR
reporting requirements.
This section allows operators that are
flaring gas across multiple leases, unit
PAs, communitized areas, or nonFederal or non-Indian leases to measure
or calculate the flared volumes at a
single point. To mitigate environmental
impacts, commingling to a single flare
may be approved even though the
relevant royalty interests may differ.
The BLM recognizes that the additional
costs of requiring individual flaring
measurement and meter facilities for
each lease, unit PA, or communitized
area are not necessarily justified by the
incremental royalty accountability
afforded by the separate meters and
flares. However, to ensure proper
production accountability, the method
of allocating the flared volumes to each
lease, unit PA, or communitized area
must be approved by the BLM where the

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flared volumes exceed the 50 Mcf/day
threshold.
The BLM made the following changes
from the proposed rule: The final rule
clarifies that (1) this section applies to
gas vented and flared from wells,
facilities, and equipment on a lease, unit
PA, or communitized area, rather than
just referencing gas vented and flared
from wells; (2) the 50 Mcf/day threshold
triggering the requirement to measure is
determined by averaging the estimated
volumes from a high pressure flare stack
or manifold over the previous 12
months, or the life of the flare,
whichever is shorter; (3) when the 50
Mcf/day threshold is met, operators
have the choice of measuring or
calculating the volume of the gas, rather
than being required to measure only; (4)
the requirement to measure or calculate
volumes applies beginning one year
from the effective date of the rule; and
(5) under new paragraph § 3179.9(c),
operators may measure or calculate
commingled gas at a single
measurement point at the flare, but they
must use an allocation method
approved by the BLM to allocate the
quantities of flared gas across the leases,
unit PAs, or communitized areas that
can contribute production to a flare that
is above the 50 Mcf/day threshold.
The BLM received a range of
comments on § 3179.9 (§ 3179.8 in the
proposed rule). Some commenters
recommended that the BLM disallow
estimation of flared or vented gas and
requested that gas be measured in all
cases or that the threshold for
measurement be lowered from 50 Mcf/
day. Commenters asserted that requiring
measurement and monitoring rather
than allowing operators to estimate
flared gas volumes will provide the cobenefits of assisting the BLM with
compliance assurance, allowing
accurate determination of when
royalties are due, and further reducing
methane emissions.
Other commenters argued that the
threshold for measurement should be
raised or that the measurement
requirement should be eliminated from
the rule altogether. One commenter
contended that metering simply adds
costs and logistical difficulties without
providing environmental benefit or
reducing waste. Several commenters
asserted that metering technology is not
available that can accurately or reliably
estimate flare gas volumes over the
extreme range of pressures and rates
typically encountered on producing
wells, and that the measurement
equipment and methods in Onshore
Order 5 and its successor regulations are
not applicable to flares. Arguing that
there is no current technology that can

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Federal Register / Vol. 81, No. 223 / Friday, November 18, 2016 / Rules and Regulations
reliably measure low pressure, low
volume, fluctuating gas flow, several
commenters recommended that the
BLM remove the requirement to
measure gas at low-volume flow rates
and allow the operator to continue to
use the estimation requirements and
GOR methodology in NTL–4A. Another
commenter asserted that operators
would need to install meters on any site
where vented and flared gas could
potentially exceed the threshold.
Several commenters requested
clarification on the period over which
the flaring must exceed the 50 Mcf/day
threshold, with one suggesting that the
threshold be based on an average value
over a production month.
Like the proposed rule, the final rule
maintains the 50 Mcf/day threshold for
triggering more specific standards for
determining the volume of flared gas,
however, the BLM has modified the
standards that apply when a flare stack
or manifold exceeds that threshold to
allow either metering or a rigorous GORbased approach. The final rule also
clarifies that exceedance of the 50 Mcf/
day threshold will be determined based
on the average quantity of flaring per
day over the life of the flare or over the
previous 12 months of flaring activity,
whichever is shorter. The BLM agrees
that the rule should specify the
measurement period for exceeding the
threshold, and believes that limiting the
averaging period of 12 months (or the
life of well) provides a good indication
of ongoing, current levels of flaring that
are high enough to warrant
measurement.
Although the BLM received
comments arguing for both higher and
lower thresholds, the BLM ultimately
concluded that a change in the
threshold is not warranted. The 50 Mcf/
day threshold represents a level of
activity of high-pressure flares that can
be measured or calculated with a
reasonable degree of accuracy. In
addition, particularly when measured or
calculated on average over a period of
time at a single flare stack or manifold,
50 Mcf/day is a sufficiently high level
of flaring that it could reasonably be
expected to lead to royalty obligations
on flared volumes considered
‘‘avoidably lost’’ under the final rule.
When an operator exceeds this
threshold, the operator needs to be able
to account accurately for the amount of
flaring that occurs and validate its
compliance with the capture target,
particularly as the ‘‘flaring allowable’’
level decreases and the capture target
increases in future years.
The BLM has modified the standards
that apply to flares that exceed the 50
Mcf/day threshold, however, to allow

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for either metering or a GOR-based
calculation of flare volumes in
circumstances where a GOR-based
approach would allow the BLM to
independently verify the volume, rate,
and heating value of the flared gas. As
noted above, many commenters argued
that metering technology is not available
to measure gas volumes at many flares,
and they asserted that using GOR-based
methods provides sufficient information
to accurately calculate flared gas
volumes. Other commenters argued that
all flared gas volumes should be directly
metered.
The BLM believes that technology
exists to measure flared volumes,
especially on higher-volume flares, and
that meters would not be prohibitively
expensive to install. For example, the
gas measurement requirements in
recently adopted subpart 3175 contain
standards applicable to metering gas at
very-low volume FMPs. These are the
BLM’s least stringent measurement
requirements for gas measurement, and
they allow operators to use alternative
methods for measuring highly
fluctuating gas flows, provided only that
the measurements meet the performance
goals of section 3175.31. While the
specific standards in subpart 3175 are
geared to orifice plate measurement, the
performance goals for very-low volume
FMPs only require that the
measurement be verifiable and they do
not require the operator to achieve any
set level of uncertainty or maintain
measurement free of statisticallysignificant bias. Therefore, the BLM may
approve alternate devices for purposes
of subpart 3175, such as thermal mass
meters, ultrasonic meters, or other
technology that industry develops that
can provide verifiable measurement,
which could also be applicable to
measuring flared volumes under this
provision. In addition, provisions in
newly adopted subparts 3170 and 3175
establish a production measurement
team, which will approve technologies
for gas metering. Technologies approved
by the production measurement team
could also be used to comply with the
requirements of this section.
Nevertheless, the BLM is sensitive to
the performance limitations of many
commonly used meters, and the BLM
believes that a properly designed GORbased approach can also produce
adequately accurate results. A GORbased method for calculating volumes of
flared gas would use a known GOR and
measured volumes of oil production and
sold gas. The GOR itself is determined
based on a test that directly measures in
a controlled manner all of the oil and
gas produced by the well over a given
period of time. Calculating the volumes

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of flared gas based on GOR can be quite
accurate, if the GOR value used is
accurate and the well conditions are
relatively stable. Since the GOR will
vary as well conditions change, the
accuracy of the GOR value for a well can
be enhanced by more frequent GOR
testing, either on a set frequency and/or
in response to changes in the well’s
production. The BLM expects that to
meet the standards of § 3179.9, GOR
tests would need to be performed at
least monthly for most wells.
Commenters also contended that the
rule does not clearly specify the type of
gas that must be estimated or measured,
and they recommended that the rule not
apply to ‘‘unavoidably lost’’ gas
volumes. The BLM does not agree that
measurement should be required only
when the volume of avoidably flared gas
exceeds the threshold. As a first step to
reducing waste through flaring, it is
important for both the operator and the
BLM to have an accurate understanding
of the total quantity of gas that is being
flared. While the BLM agrees that
estimation techniques can provide a
ballpark volume estimate, the BLM
believes that direct measurement
methods authorized under subpart 3175
more consistently and accurately
identify the actual volume of the losses.
Furthermore, the BLM notes that if an
operator is flaring high pressure gas at
a rate of more than 50 Mcf/day, it
becomes more likely that the operator is
failing to meet capture requirements. If
an operator fails to meet capture
requirements, then at least a portion of
the flared gas is deemed avoidably lost,
and therefore royalty bearing.
Several commenters noted that the
rule does not provide methods for
estimating vented or flared volumes.
One commenter asserted that the BLM
must require operators to use estimation
techniques that provide accurate and
reliable estimates of releases, while
others recommended that methods
currently allowed under NTL–4A
should continue to be allowed for
estimating associated gas and royaltyfree volumes.
The BLM does not believe that it is
necessary to specify estimation
methods, as the BLM expects the
industry to continue to use wellunderstood and generally accepted
engineering practices for estimating
quantities of flared gas below the 50
Mcf/day threshold.
Commenters also requested that the
BLM make public the data on volumes
of gas reported by operators as flared or
vented. The BLM agrees that this is
important information for the public,
and the BLM plans to make this
information available, subject to any

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protections for confidential business
information.

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Section 3179.10 Determinations
Regarding Royalty-Free Flaring
This section (which was § 3179.9 in
the proposed rule) provides for a
transition period for operators that are
operating under existing approvals for
royalty-free flaring, as of the effective
date of the rule. Further, this section
clarifies that nothing in this subpart
alters the royalty-bearing status of
flaring that occurred prior to January 17,
2017, nor the BLM’s authority to
determine that status and collect
appropriate back-royalties.
Commenters asserted that the rule
represents a change in what is
considered ‘‘avoidable loss’’ and
therefore cannot be applied to existing
leases. Commenters also requested that
the BLM permanently grandfather
existing approvals for royalty-free
flaring and only apply the rule
requirements to wells drilled after the
effective date of the rule, arguing that 90
days is too little time to design and
construct gas capture infrastructure.
As discussed in Preamble Section
III.C, the BLM’s legal and contractual
authority to update its regulations
governing existing oil and gas leases is
well established. The BLM has the
authority to revise its interpretation of
what constitutes ‘‘avoidably lost’’ oil
and gas and may impose this
interpretation on existing leases. The
BLM revised the rule, however, to
extend the grace period for preexisting
approvals to flare royalty free from the
90 days specified in the proposed rule
to one year after the final rule becomes
effective. After one year, those operators
with preexisting royalty-free flaring
approvals will become subject to all the
provisions of the final rule.
Section 3179.11 Other Waste
Prevention Measures
This section clarifies that nothing in
this subpart alters the BLM’s existing
authority under applicable laws,
regulations, permits, orders, leases, and
unitization or communitization
agreements to limit the volume of
production from a lease, or to delay
action on an APD to minimize the loss
of associated gas. Specifically, if
production from a new well would force
an existing producing well already
connected to the pipeline to go offline,
then notwithstanding the requirements
in 3179.7 and 3179.8, the BLM may
limit the volume of production from the
new well while gas pressures from the
well stabilize. In addition, this section
clarifies that, consistent with existing
authority, the BLM may delay action on

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an APD or approve it with conditions
related to gas capture and production
levels, and can suspend the lease under
43 CFR 3103.4–4 if the lease associated
with the APD is not yet producing.
In the final rule, the BLM revised both
paragraphs § 3179.11(a) and (b) to add
additional specificity regarding the
sources of the BLM’s existing authority.
Specifically, the BLM added to both
paragraphs (a) and (b) language to the
effect that the BLM may exercise its
existing authority ‘‘under applicable
laws and regulations, as well as its
authority under the terms of applicable
permits, orders, leases, and unitization
or communitization agreements.’’
The BLM received a number of
comments on this section. While some
commenters expressed support for
BLM’s authority on this matter, other
commenters expressed concern that the
BLM could delay approval of APDs due
to infrastructure limitations that are out
of the control of the operator (e.g., thirdparty pipeline capacity). One
commenter suggested that the proposed
requirements would result in
curtailment of new production,
potentially causing reservoir damage
during initial production operations.
Another commenter asked the BLM to
(1) clarify that this portion of the rule
applies to Federal minerals only and (2)
explain implementation of the rule for
special cases, such as long reach
horizontal wells that produce from
Federal and non-Federal leases within
the same wellbore.
The BLM did not revise this section
based on comments received. As stated
in the regulatory text, the BLM is
exercising existing authority and this
section does not expand upon that
authority. The intent of this section is to
address operators’ concerns that gas
from their existing wells could be forced
offline by new Federal gas production,
and to clarify that the BLM already has
the authority to remedy such
circumstances when appropriate to
minimize waste of oil and gas on BLMadministered leases. If implementation
of this section could result in the
incidental curtailment of non-Federal
production, the BLM will coordinate on
a case-by-case basis with the relevant
State regulatory authorities pursuant to
Section 3179.12. As noted in Preamble
Section VI.D, the fact that a regulatory
provision aimed at Federal and Indian
production may have incidental impacts
on State or private production does not
impinge on the BLM’s authority to
ensure that operators take reasonable
steps to minimize waste of Federal and
Indian minerals.

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Section 3179.12 Coordination With
State Regulatory Authority
This section addresses certain ‘‘mixed
ownership’’ situations, in which a single
well may produce oil and gas from both
Federal and/or Indian mineral interests
and non-Federal, non-Indian mineral
interests. This section provides that to
the extent any BLM action to enforce a
prohibition, limitation, or order under
this subpart might adversely affect
production of oil or gas from nonFederal and non-Indian mineral
interests, the BLM will 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 interests and from
non-Federal, non-Indian mineral
interests. The BLM did not revise this
section from the proposed rule.
Some commenters asserted that that
the propose rule did not indicate what
constitutes coordination, and separately,
that state-Federal coordination would
not reduce duplicative requirements for
operators. This provision is aimed at
coordinating enforcement of BLM
requirements, not intended to address
issues related to overlapping state and
Federal requirements. The BLM
anticipates that its level of coordination
will vary by state, and may involve
entering into (or revising existing)
memoranda of understanding with the
relevant State parties.
Section 3179.101

Well Drilling

This section requires that gas reaching
the surface as a normal part of drilling
operations be used or disposed of in one
of four specified ways: (1) Captured and
sold; (2) directed to a flare pit or flare
stack; (3) used in the operations on the
lease, unit, or communitized area; or (4)
injected. The final rule specifies that gas
may not be vented except under the
circumstances specified in § 3179.6(b)
or when it is technically infeasible to
use or dispose of the gas in one of the
ways specified above.
This section also states that gas lost as
a result of a loss of well control will be
classified as avoidably lost if the BLM
determines that the loss of well control
was due to operator negligence, in
which case it will be subject to royalties.
Several commenters asserted that the
proposed requirement that all gas that
reaches the surface during drilling be
captured and sold, flared, used on-site,
or injected is not always technically
feasible because such gas can be low

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pressure, low volume, and intermittent.
Commenters also stated that achieving a
no-venting standard is not feasible
particularly when gas reaches the
surface through unplanned gas kicks.
Commenters asserted that in these
situations, venting the gas can
sometimes be the only safe solution.
In response to these comments, in
addition to the exceptions described in
§ 3179.6(b), the final rule states that
operators also do not have to use or
dispose of gas that reaches the surface
in one of the ways specified in
§ 3179.101(a) if it is technically
infeasible to do so. The BLM believes
that a technical infeasibility option is
necessary to address the situations
described by commenters, which we
expect to occur rarely, where the
operator cannot use or dispose of the gas
as specified in § 3179.101(a).
The BLM also received comments
asserting that it lacks the authority to
require that gas reaching the surface
during drilling operations be flared if
not captured, used on the lease, or
injected. Commenters argued that such
a requirement does not fall within the
BLM’s MLA authority because it is not
waste prevention, as the gas is lost
whether it is vented or flared. These
commenters then argued that the only
possible justification for the
requirement was control of GHGs and
other air pollutants, which commenters
assert is exclusively within the EPA’s
domain.
The BLM disagrees with these
comments. Flaring during drilling does
not count toward an operator’s capture
target, so the requirement to flare rather
than vent this gas does not achieve
waste reduction in that way.
Nevertheless, the requirement falls
squarely within the BLM’s authority
because, as discussed in connection
with § 3179.6, a requirement to flare
rather than vent associated gas is a
safety measure under the MLA. It is
generally safer to combust methane gas
than to allow it to vent uncombusted
into the surrounding air due to concerns
over methane’s explosiveness and the
risk of hypoxia and exposure to various
associated pollutants. In addition, also
as discussed in connection with
§ 3179.6, the BLM has the authority to
regulate air quality and GHG impacts on
and from public lands pursuant to
FLPMA and the MLA.
Section 3179.102 Well Completion
and Related Operations
This section addresses gas that
reaches the surface during well
completion, post-completion, and fluid
recovery operations, after a well has
been hydraulically fractured or

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refractured. It requires the gas to be used
or disposed of in one of four specified
ways: (1) Captured and sold; (2) directed
to a flare pit or stack, subject to a
volumetric limitation in section
3179.103; (3) used in the lease
operations; or (4) injected. The final rule
specifies that gas may not be vented
except under the narrow circumstances
specified in proposed § 3179.6(b) or
when it is technically infeasible to use
or dispose of the gas in one of the four
ways specified above. It also provides
that an operator will be deemed to be in
compliance with the gas capture and
disposition requirements of
§ 3179.102(a) if the operator is in
compliance with the requirements for
control of gas from well completions
established under subpart OOOO or
subpart OOOOa, or if the well is not a
‘‘well affected facility’’ under either of
these subparts.
The final rule also allows an
exemption from the requirements of
§ 3179.102(a) if the operator submits a
Sundry Notice to the BLM
demonstrating that compliance with
these requirements would impose such
costs as to cause the operator to cease
production and abandon significant oil
reserves under the lease.
In response to comments described
below, we have made several changes to
the proposed rule requirements.
Specifically, the final rule: (1) Clarifies
that sources subject to, and in
compliance with, subpart OOOO and
subpart OOOOa are deemed to be in
compliance with this section, without
filing a Sundry Notice (as the proposed
rule would have required); (2) limits
coverage of this section to hydraulically
fractured or refractured well
completions; (3) adds text to clarify that
a well that does not meet the definition
of a ‘‘well affected facility’’ under either
subpart OOOO or subpart OOOOa, will
nevertheless be deemed to be in
compliance with this section, since the
NSPS provides that existing wells that
are refractured and follow the well
completion procedures in the NSPS are
not affected facilities; (4) adds an
exemption for technical infeasibility;
and (5) adds an exemption from the
requirements of this section when the
operator can demonstrate that
compliance would cause the operator to
cease production and abandon
significant recoverable oil reserves
under the lease due to the cost of
compliance.
Several commenters asserted that the
requirements for well completions are
duplicative with EPA requirements
contained in 40 CFR part 60 subpart
OOOO and subpart OOOOa. These EPA
rules address emissions from flowback

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83055

operations following completion of new
gas and oil wells using hydraulic
fracturing treatment. Commenters
asserted that the EPA rules effectively
cover all wells, because most new wells
utilize hydraulic fracturing, and existing
wells that undergo ‘‘recompletion’’
hydraulic fracturing will be covered as
well, as they are considered a
‘‘modified’’ source post-recompletion.
Commenters further argued that the
BLM should allow for exemptions for
wells that comply with either 40 CFR
part 60, subpart OOOO or subpart
OOOOa, rather than limiting the
exemption to wells that comply with
subpart OOOOa as the proposed rule
would have done. Commenters asserted
that several issues related to controlling
emissions from well completion
operations have already been worked
out in detail with the EPA, and these
issues would apply to the BLM’s rule as
well. These issues include inadequate
well pressure or gas content during the
well completion to operate surface
equipment, and the need for an
exemption for wells with less than 300
scf of gas per stock tank barrel of oil
produced. Other commenters noted that
the EPA’s well completion requirements
in subpart OOOOa do not cover
conventional wells because of their low
methane and VOC emissions, but that
the proposed BLM rule would apply to
conventional wells. Commenters also
argued that the Sundry Notice
requirement to document EPA
compliance was an additional and
unnecessary burden for sources already
regulated elsewhere.
Although we believe that new wells
will generally be subject to subpart
OOOOa, after considering these
comments, we have added language in
the final rule stating that wells that are
in compliance with either subpart
OOOO or subpart OOOOa are deemed to
be in compliance with the requirements
of this section. We also agree with
commenters that filing a Sundry Notice
to this effect is unnecessary, and we
have not included that proposed
requirement in the final rule. We also
revised the text to limit the coverage of
this section to fractured and refractured
wells. Upon consideration of the
comments, the BLM agrees that the loss
of gas from conventional well
completions is very small and that
regulating conventional well
completions is not a particularly costeffective way to reduce waste. We also
revised the text to clarify that a well that
does not meet the definition of a ‘‘well
affected facility’’ under either subpart
OOOO or subpart OOOOa, and is
exempt from those subparts on that

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ground, is deemed to be in compliance
with this section. This change aligns the
coverage of the BLM requirements with
the coverage of the EPA requirements,
and it ensures that a well that the EPA
exempted from the subpart OOOO and
subpart OOOOa requirements would not
become subject to the BLM
requirements by virtue of that
exemption.
The BLM is including requirements
for well completions in this rulemaking
to satisfy its statutory obligations to
prevent waste of oil and gas on Federal
lands. The well completion
requirements are a key part of a
comprehensive regulatory regime
reducing waste from development of the
public’s oil and gas resources. The BLM
requirements do not require any
additional action from an operator that
is in compliance with subparts OOOO
and OOOOa. Thus, without imposing
any burden on an operator, the BLM
requirements provide a backstop in the
unlikely event that subparts OOOO or
OOOOa are no longer in effect. The
BLM does not in any way question the
validity of the EPA regulations, but we
note that some of the same commenters
that claim the BLM regulations are
unnecessarily duplicative are separately
challenging EPA’s subpart OOOOa in
court.
Commenters also questioned the
technical feasibility of the proposed
requirement that all gas that reaches the
surface during well completion and post
completion, drilling fluid recovery, or
fracturing or refracturing must be
captured and sold, flared, used on-site,
or injected. These commenters
contended that gas releases during these
stages of development, especially
immediately following drilling, may
involve small quantities, or gas with low
BTU or high contaminant
concentrations. As a result, the
commenters stated, the compliance
options in the proposed rule are cost
prohibitive and not technically feasible.
They further argued that capturing low
quantities of gas requires significant
compression capacity to enter a sales
line, that gas that does not meet pipeline
specifications for sales is unlikely to
burn (without makeup gas) or be
appropriate for beneficial use, and that
reinjection of small volumes produced
for a limited time is cost prohibitive.
In response to these comments, the
final rule includes an exemption from
the requirements for handling gas from
a well completion when it is technically
infeasible to use or dispose of the gas
using any of the four identified options.
Commenters also asserted that under the
proposed rule, absent an exemption, if
using any of the four identified

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compliance options was technically
infeasible, the operator would have been
forced to abandon the well. While we do
not believe that the requirements for
well completions are likely to impose
such costs as to cause an operator to
abandon the lease, the final rule also
includes an exemption from
§ 3179.102(a) when the operator can
demonstrate that compliance would
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease due to the cost
of compliance.
The BLM also received comments
asserting that it lacks the authority to
require that gas reaching the surface
during well completions be flared if not
captured, used on the lease, or injected.
Commenters argued that such a
requirement does not fall within the
BLM’s MLA authority because it is not
waste prevention—i.e., the gas is lost
whether it is vented or flared. These
commenters then argued that the only
possible justification for the
requirement was control of GHGs and
other air pollutants, which commenters
assert is exclusively within the EPA’s
domain.
The BLM disagrees with these
comments for several reasons. First, the
requirement in this section to flare
rather than vent constitutes waste
prevention because (a) all flaring
covered by this section and § 3179.103
is subject to a volumetric royalty-free
flaring limit of 20 MMcf/well; and (b)
flared gas from well completions that
exceeds this volumetric limit is treated
as avoidably lost gas subject to royalties
under § 3179.4(a)(1)(B). This royalty
trigger provides an incentive for
operators to stay under the 20 MMcf/
well flaring limit—and thus to limit
their waste. Second, as discussed in
connection with § 3179.6, a requirement
to flare rather than vent associated gas
is a safety measure under the MLA. It is
generally safer to combust methane gas
than to allow it to vent uncombusted
into the surrounding air due to concerns
over methane’s explosiveness and the
risk of hypoxia and exposure to various
associated pollutants. In addition, also
as discussed in connection with
§ 3179.6, the BLM has the authority to
regulate air quality and GHG impacts on
and from public lands pursuant to
FLPMA and the MLA.
Section 3179.103 Initial Production
Testing
This section clarifies when gas may be
flared royalty-free during a well’s initial
production test. It provides that gas may
be flared royalty-free during initial
production testing until the first of the
following events: (1) The operator

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determines that it has obtained adequate
reservoir information for the well; (2) 30
days have elapsed; (3) 20 MMcf of gas
have been flared (as measured in
combination with volumes flared during
well completion under section
3179.102); or (4) the beginning of well
production. Under any of these
scenarios, royalty-free flaring allowed
by this section ends when production
begins.
Paragraph (b) of this section allows
the BLM to approve royalty-free flaring
for up to an additional 60 days, if there
are well or equipment problems or a
need for additional testing to develop
adequate reservoir information.
Paragraph (d) allows a 90-day period for
royalty-free flaring during dewatering
and initial evaluation of an exploratory
coalbed methane well, and the BLM
may approve up to two extensions of 90
days each. This approach recognizes
that it generally takes substantially more
than 30 days to dewater a coalbed
methane well, but the time required can
vary considerably between different
coalbed methane resources. The
operator is required to submit a Sundry
Notice to BLM if it wishes to request a
longer test period under paragraph (b) or
(d) of this section.
In response to comments described
below, the final rule includes a new
provision in paragraph (c) of this section
that allows the BLM to increase the 20
MMcf royalty-free flaring limit by up to
an additional 30 MMcf of gas for
exploratory wells in remote locations
where additional testing is needed in
advance of development of pipeline
infrastructure. The operator is required
submit a Sundry Notice to BLM if it
wishes to request this higher limit.
Under any of these circumstances,
notwithstanding an extension of the test
period, the well will still be subject to
the royalty-free flaring limit of 20 MMcf
limit or, upon approval through a
Sundry Notice, the higher limit
specified in paragraph (c) of this
section. Volumes vented or flared under
this section must be reported to ONRR
as directed in § 3179.9 of this subpart.
Several commenters argued that the
proposed royalty-free flaring limit of 20
MMcf was too low, and that higher
limits are needed due to higher
production rates being achieved through
advancements in hydraulic fracturing.
They further requested that the rule
state that the duration and maximum
gas volumes for initial production
testing do not include the duration of
flowback operations and gas volumes
produced during those operations. In
response to these comments, the BLM
added new paragraph (c) of this section
(discussed above), which allows the

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BLM to increase the 20 MMcf royaltyfree flaring limit by up to an additional
30 MMcf of gas for exploratory wells in
remote locations where additional
testing is needed in advance of the
development of pipeline infrastructure.
While the BLM believes that for
established fields, adequate testing to
determine a well’s production capacity
can be conducted with no more than 20
MMcf of flared gas (including flaring
from flowback operations), we recognize
that a higher amount of flaring may be
necessary for exploratory wells that are
located in remote areas where no
existing infrastructure exists. To the
extent that an operator chooses to
conduct additional testing beyond the
royalty-free limits established in this
section, the operator is free to do so, but
the operator is responsible for paying
royalties on the flared gas, rather than
being able to shift the associated royalty
losses to the public.

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Section 3179.104 Subsequent Well
Tests
The requirement in this section is
essentially the same as NTL–4A’s
requirement regarding subsequent well
tests. This section limits to 24 hours any
royalty-free flaring during production
tests conducted after the initial
production test, unless the BLM
approves or requires a longer test
period. The operator must submit via
Sundry Notice its request for a longer
test period. Volumes vented or flared
under this section must be reported to
ONRR as directed in proposed § 3179.9
of this subpart. The BLM received few
comments on this provision and made
no substantive changes to this provision
from the proposed to final rule.
Section 3179.105 Emergencies
This section allows operators to flare
(or in some cases vent) royalty-free
during an emergency, which is a
temporary, infrequent, and unavoidable
situation in which the loss of gas is
uncontrollable or necessary to avoid
immediate and substantial adverse
impacts to safety, public health, or the
environment. Paragraph (a) further
limits royalty-free emergency venting or
flaring to a maximum of 24 hours per
incident, unless the BLM agrees that the
emergency conditions necessitate
flaring—and possibly venting—for a
longer period. In addition, paragraph (b)
clarifies situations that do not constitute
an emergency for purposes of royalty
assessment, including: More than three
failures of the same equipment within
any 365-day period; failures from
improperly sized, installed, or
maintained equipment; failure to limit
production when the production rate

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exceeds the capacity of related
equipment or other infrastructure;
scheduled maintenance; a situation
caused by operator negligence; and
when a lease, unit, or communitized
area has already experienced three or
more emergencies within the past 30
days, except when the BLM determines
such emergencies were unanticipated
and beyond the operator’s control.
Volumes vented or flared under this
proposed section must be reported to
ONRR as directed in § 3179.9 of this
subpart.
Based on a number of comments
requesting additional clarification, the
BLM has added a definition of
‘‘emergency’’ to the final text.
Additionally, in response to comments
stating that certain emergency situations
may necessitate flaring beyond 24
hours, the final rule allows operators to
flare or vent royalty-free beyond the 24hour limit, but only when necessary and
with BLM approval. While the BLM
asserts that in most cases, 24 hours is a
sufficient timeframe to address an
emergency and/or make an appropriate
business decision, we acknowledge that
venting or flaring beyond 24 hours
might be necessary in a limited number
of cases, such as a natural disaster that
prevents access to the site.
Some commenters asserted that the
BLM was being too strict in limiting
royalty-free flaring in emergencies to 3
emergencies in a 30-day period. BLM
believes that after multiple incidents in
a short timeframe, operators should
identify and correct any maintenance or
operational issues, and that repetitive,
systemic events do not constitute an
emergency situation. Commenters also
recommended that the BLM remove the
provisions listing improper installation
and scheduled maintenance as events
that do not constitute emergencies. The
BLM did not revise the rule based on
these comments, as scheduled
maintenance is not an unanticipated
disruption and improper installation
can be avoided through good work
practices.
The BLM notes that the provisions on
downhole well maintenance in
§ 3179.204 cover well maintenance
activities.
Section 3179.201 Equipment
Requirements for Pneumatic Controllers
This section addresses gas losses from
pneumatic controllers. Paragraph (a)
establishes that this section applies to
pneumatic controllers that use natural
gas produced from a Federal or Indian
lease, or from a unit or communitized
area that includes a Federal or Indian
lease, if the controllers (1) have a
continuous bleed rate greater than 6 scf/

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hour (‘‘high-bleed’’ controllers); and (2)
are not covered by EPA regulations that
prohibit the new use of high-bleed
pneumatic controllers (40 CFR 60,
subpart OOOO or subpart OOOOa), but
would be subject to those regulations if
the controllers were new, modified, or
reconstructed sources.
Paragraph (b) of this section requires
pneumatic controllers subject to the
requirement to be replaced with
controllers (including, but not limited
to, continuous or intermittent
pneumatic controllers) having a bleed
rate of no more than 6 scf/hour, subject
to the exceptions described below.
Paragraph (c) is discussed below, in
connection with the exceptions. Under
paragraph (d), operators are required to
replace such 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 (e), operators are
also required to ensure that pneumatic
controllers are functioning within the
manufacturers’ specifications.
This section provides several
exceptions to the replacement
requirement in paragraph (b). First, an
operator is not required to replace a
controller if a high-bleed controller is
necessary to perform the needed
function. For example, replacement
might not be required if a low-bleed
controller would not provide a timely
response, which would lead to greater
waste or create a safety hazard. To avail
themselves of this exception, operators
must submit a Sundry Notice to the
BLM that describes the functional needs
requiring the use of higher-bleed
controllers. Second, replacement is not
required if the controller was routed to
a flare device or low-pressure combustor
as of the effective date of this rule, and
continues to be so-routed. Third, an
operator is not required to replace its
pneumatic controller if it chooses to
route the pneumatic controller exhaust
to processing equipment for capture and
sale. Fourth, an operator may be
exempted from the replacement
requirement if it demonstrates through a
Sundry Notice (described in paragraph
(c)), 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.
In response to comments and to
further clarify the section, the BLM
made the following four changes to the
proposed rule requirements: (1)
Clarified that a pneumatic controller is
subject to this section if it is not subject

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to 40 CFR part 60, subparts OOOO or
OOOOa, but would be subject to either
of those subparts if it were a new,
modified, or reconstructed source; (2)
clarified that the operator may replace a
high-bleed pneumatic controller with a
continuous pneumatic controller, an
intermittent pneumatic controller, or a
non-pneumatic device, as long as the
replacement has a bleed rate no greater
than 6 scf per hour; (3) clarified that an
operator may be exempted from
replacement if it was routing the
controller exhaust to a flare or a lowpressure combustor device at the time
the rule was effective, so long as the
operator continues to do so; (4) allowed
an operator to be exempted from
replacement if it routes the controller
exhaust to processing equipment; and
(5) included in paragraph (c) the
information that must be included in
the Sundry Notice to demonstrate that
the costs of replacing a pneumatic
controller would cause the operator to
cease production and abandon
significant recoverable oil reserves.
Several commenters requested that
the final rule clarify perceived
conflicting regulatory coverage between
the proposed rule and the EPA’s
subparts OOOO and OOOOa. Based on
these comments, we revised
§ 3179.201(a)(2) to further qualify that a
pneumatic controller is subject to this
section if it ‘‘[i]s not subject to any of
the requirements of 40 CFR part 60,
subpart OOOO or subpart OOOOa, but
would be subject to one of those
subparts if it were a new, modified, or
reconstructed source.’’ This change
ensures that the BLM requirements do
not inadvertently apply to existing
equipment that would not be covered by
the EPA requirements. We believe this
change properly conveys our original
intent to cover the same types of
pneumatic controllers that EPA rules
cover.
Some commenters stated that
pneumatic controller exhaust should be
allowed to be routed to processing
equipment, such as a vapor recovery
unit, on-site fuel line, or a control
device (in addition to a flare), noting
that Wyoming’s recent regulation for
existing pneumatic controllers in the
Upper Green River Basin allow
operators this flexibility. The BLM
agrees with these comments and as
stated previously, revised the rule to
state that operators may route the pump
to processing equipment. However, the
final rule clarifies that with respect to
routing pneumatic controller exhaust to
a flare or low-pressure combustor, an
operator may only be exempted from
replacement of the controller if it is
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manner as of the effective date of the
rule, and continues to do so. The BLM
believes that given the low cost and
high return on pneumatic controller
replacement, spending capital to route
controller exhaust to a flare or lowpressure combustor is unlikely to make
sense from an economic, practical and
waste prevention perspective.
Some commenters stated that the
BLM should require the use of zerobleed devices on leases where on-site
electrical grid power is used, or that the
BLM should require bleed gas to be
routed to a flare or other control device.
The final rule does not require the use
of zero-bleed pneumatic controllers.
Many sites using pneumatic controllers
are not connected to the electric grid,
and the BLM believes that requiring
operators to route gas from pneumatic
controllers would impose considerable
costs on them and involve technical
complications which could impact the
cost effectiveness of the replacement
requirement. The BLM did clarify in the
final rule that operators using
pneumatic controllers that have a bleed
rate greater than 6 scf per hour have the
option to route the exhaust to
processing equipment rather than
replace the controller.
Many commenters stated that one
year is insufficient to replace high-bleed
pneumatic controllers and requested
that requirements be extended to two or
three years. The BLM believes that one
year is a sufficient time period for
operators to replace high-bleed
pneumatic controllers, given the
relatively low cost and rapid pay-back
period of these replacements, as
discussed in section V. Discussion of
the Proposed Rule of the preamble to
the proposed rule. In addition, as
included in the proposed rule, if the
well or facility that the pneumatic
controller serves has an estimated
remaining productive life of three years
or less from the effective date of the
rule, the operator has three years from
the effective date of the rule to replace
the pneumatic controller, provided that
the operator notifies the BLM through a
Sundry Notice.
Several commenters argued that
operators should not have to submit a
Sundry Notice and wait for BLM
approval, if they meet one of the
exemptions to the requirements. These
commenters also asserted that the
requirement for submission of a Sundry
Notice (and hence, they assumed, BLM
approval) set a higher standard for
retaining a high-bleed controller based
on functional need than the
requirements in 40 CFR part 60, subpart
OOOOa, under which they claimed EPA
only requires recordkeeping to

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document why a high bleed pneumatic
controller is needed.
As provided in the proposed rule,
operators seeking exemptions based on
a functional need for the equipment
need only notify the BLM of that need
and do not have to get the BLM’s
approval. Further, if the exhaust from
the pneumatic controller was already
being routed to a flare or other control
device on the effective date of the rule,
or if the operator chooses to route the
exhaust to processing equipment, no
notice is required. The BLM only
requires a Sundry Notice and approval
for exemptions based on the cost of
replacing the equipment.
The BLM also received comments
asserting that it lacks the authority to
require operators who opt not to install
low-bleed pneumatic controllers to
route their existing pneumatic
controllers to a flare device (rather than
venting). Commenters argued that such
a requirement does not fall within the
BLM’s MLA authority because it is not
waste prevention—i.e., the gas is lost
whether it is vented or flared. These
commenters then argued that the only
possible justification for the
requirement was control of GHGs and
other air pollutants, which commenters
assert is exclusively within the EPA’s
domain.
The BLM disagrees with these
comments. The final rule does not
require flaring in lieu of venting as a
means of compliance with this section.
The primary means of compliance is
replacement with a low-bleed
pneumatic controller, which prevents
waste by reducing the amount of gas
diverted to the pneumatic controllers—
which, in turn, makes more gas
available for capture. An operator is
exempted from this requirement if a
high-bleed pneumatic controller is
required based on functional needs, if
the operator directs its controller
exhaust to processing equipment for
capture, or if the operator is already
directing the exhaust from the controller
to a flare (or low-pressure combustor).
The rule therefore imposes no new or
additional flaring requirements.
Section 3179.202 Requirements for
Pneumatic Diaphragm Pumps
This section establishes requirements
for operators with pneumatic diaphragm
pumps that use natural gas produced
from a Federal or Indian lease, or from
a unit or communitized area that
includes a Federal or Indian lease. It
applies to such pumps if they are not
covered under EPA regulations at 40
CFR part 60, subpart OOOOa, but would
be subject to that subpart if they were
a new, modified, or reconstructed

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source. It does not apply to pneumatic
diaphragm pumps that vent exhaust gas
to the atmosphere or that operated fewer
than 90 days in the prior calendar year
(as documented in a Sundry Notice).
For covered pneumatic pumps, this
section requires that the operator either
replace the pump with a zero-emissions
pump or route the pump exhaust to
processing equipment for capture and
sale. Alternatively, an operator may
route the exhaust to a flare or low
pressure combustion device if the
operator makes a determination (and
notifies the BLM through a Sundry
Notice) that replacing the pneumatic
diaphragm pump with a zero-emissions
pump or capturing the pump exhaust is
not viable because (1) a pneumatic
pump is necessary to perform the
function required, and (2) capturing the
exhaust is technically infeasible or
unduly costly. If an operator makes this
determination and has no flare or lowpressure combustor on-site, or routing to
such a device would be technically
infeasible, the operator is not required
to route the exhaust to a flare or lowpressure combustion device. Further, an
operator that is required to replace a
pump or route the exhaust gas from a
pump either for capture or to a flare or
combustion device may be exempt from
the requirement if the operator
demonstrates through a Sundry Notice,
and the BLM concurs, that the cost
would impose such costs as to cause the
operator to cease production and
abandon significant recoverable oil
reserves under the lease.
Operators must comply with these
requirements no later than one year after
the effective date of the rule. In
addition, similar to the requirements for
pneumatic controllers and based on the
same rationale, this section provides
that if the estimated remaining
productive life of the well or facility is
three years or less, the operator is
allowed to notify BLM through a Sundry
Notice and replace the pneumatic pump
no later than three years from the
effective date of this section, rather than
within one year. The section also
requires that pneumatic pumps function
within manufacturers’ specifications.
The final rule makes five changes to
the proposed rule requirements. First, it
restructures the requirements as
discussed above to require that
operators either replace pneumatic
diaphragm pumps with zero emission
pumps or capture the exhaust for sale.
As explained above, the operator may
route the exhaust to a flare or low
pressure combustor device if it makes a
determination that replacing the pump
with a zero-emissions pump is not
viable because (a) a pneumatic pump is

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necessary to perform the function
required, and (b) capturing the
pneumatic pump exhaust is technically
infeasible or unduly costly. If an
operator makes this determination and
has no flare or low pressure combustor
on-site (or flaring to such a device
would be technically infeasible), the
operator is not required to route the
exhaust to a flare or low pressure
combustion device. Second, in response
to comments and as discussed below,
the final rule removes chemical
injection pumps from inclusion in this
section. Third, it adds paragraph (b)
stating that an operator is not required
to replace a pump if the pump does not
vent exhaust gas to the atmosphere (e.g.,
already is routed to a flare or to capture
equipment) or if the operator submits a
Sundry Notice to the BLM documenting
that the pump(s) operated fewer than 90
individual days in the prior calendar
year. Fourth, the final rule clarifies that
a pneumatic diaphragm pump is subject
to this section if it is not subject to any
of the requirements of 40 CFR part 60,
subpart OOOOa, but would be subject to
that subpart if it were a new, modified,
or reconstructed source. Fifth, it adds
paragraph (d), which includes
information that must be included in
the Sundry Notice specified in
§ 3179.202(f).
Some commenters suggested that the
BLM require the use of zero-bleed
pumps in all cases except where
technically infeasible, while other
commenters stated that routing pump
exhaust to a flare offers no product
recovery potential and does not
minimize loss or waste. The BLM agrees
that the installation of zero-bleed pumps
is technically feasible in many cases. In
response to these comments, and to
require operators to employ waste
minimization practices when feasible,
the final rule is restructured to require
operators, when feasible, to install zerobleed pumps or route the pump exhaust
to process equipment for capture and
sale. However, in making this revision,
the BLM does not intend to require
operators to replace pumps that are
already routed to flare or capture
equipment (i.e., pumps that do not
currently vent exhaust gas to the
atmosphere), and we have added
clarifying language to avoid this result.
As discussed below, the compliance
mechanisms in this section are
structured to encourage the prevention
of waste.
Some commenters stated that
chemical injection and temporary use
pumps should be exempt because they
have low aggregate emissions and
operate intermittently. The BLM agrees
that chemical injection pumps release

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83059

substantially lower quantities of gas
than diaphragm pumps. The BLM also
recognizes that some diaphragm pumps
are used very intermittently or only for
a short portions of the year, and that low
usages result in low quantities of lost
gas. In the final rule, the BLM has
specified that the rule does not apply to
chemical injection pumps or to
diaphragm pumps that operated fewer
than 90 individual days in the prior
calendar year. This change also aligns
the requirements of this section with the
requirements for pneumatic pumps
under 40 CFR part 60 subpart OOOOa.
Several commenters requested that
the final rule clarify perceived
conflicting regulatory coverage between
the proposed rule and 40 CFR part 60
subpart OOOOa. In addition to the
change to chemical injection pumps, we
revised § 3179.202(a)(2) to further
qualify that a pneumatic diaphragm
pump is subject to this section if it ‘‘[i]s
not subject to any of the requirements of
40 CFR part 60, subpart OOOOa, but
would be subject to that subpart if it
were a new or modified source.’’ This
change ensures that the BLM
requirements do not inadvertently apply
to existing equipment that would have
been exempted under the EPA
requirements. We believe this change
properly conveys our original intent to
cover the same types of pneumatic
pumps that EPA rules cover.
Similar to comments received on
pneumatic controllers, some
commenters stated that pneumatic
pumps should be allowed to be routed
to processing equipment, such as a
vapor recovery unit, on-site fuel line, or
a control device (in addition to a flare).
The BLM agrees with these comments
and revised the rule to state that
operators may route the pneumatic
pump exhaust to processing equipment
for capture and sale, or, under certain
conditions described above, to either a
low-pressure combustor device or a
flare.
Several commenters stated that 1 year
is insufficient to replace covered
pneumatic pumps and requested that
the replacement requirements be
extended to 3 years. The BLM believes
that one year is a sufficient time period
for operators to replace pneumatic
diaphragm pumps, or route them to a
flare that is already installed on-site,
given the relatively low cost and rapid
pay-back period of these replacements,
as discussed in the preamble to the
proposed rule, and the relatively low
cost of connecting a pump to a preexisting on-site flare. Moreover, because
the BLM is not including chemical
injection pumps in this final rule,
operators will need to address far fewer

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pneumatic pumps than the proposed
rule would have required. In addition,
as included in the proposed rule, if a
well or facility that the pneumatic pump
serves has an estimated remaining
productive life of three years or less
from the effective date of the rule, the
operator has three years from the
effective date of the rule to complete the
replacement, provided that notification
is filed through a Sundry Notice.
The BLM also received comments
asserting that it lacks the authority to
require operators who opt not to install
zero-emission pneumatic pumps to
route their existing pneumatic pumps to
a flare device (rather than venting).
Commenters argued that such a
requirement does not fall within the
BLM’s MLA authority because it is not
waste prevention—i.e., the gas is lost
whether it is vented or flared. These
commenters then argued that the only
possible justification for the
requirement was control of GHGs and
other air pollutants, which commenters
assert is exclusively within the EPA’s
domain.
The BLM disagrees with these
comments for several reasons. First, the
requirement in this section to flare
rather than vent associated gas
constitutes waste prevention. Requiring
operators to (at minimum) direct
associated gas that bleeds from their
pneumatic pumps to a flare device
eliminates the lowest cost method of
handling such gas (that is, venting).
This, in turn, provides a greater
incentive for operators to upgrade to a
zero-emission pneumatic pump or
capture pump exhaust gas. Upgrading to
a zero-emission pneumatic pump
prevents waste by reducing the amount
of gas diverted to the pneumatic
pumps—which, in turn, directs more
gas to either a capture line or the highpressure flare. If an operator chooses to
capture, upgrading the pneumatic pump
will directly prevent waste by causing
more gas to be sold.
Second, as discussed in connection
with § 3179.6, a requirement to flare
rather than vent associated gas is a
safety measure under the MLA. It is
generally safer to combust methane gas
than to allow it to vent uncombusted
into the surrounding air due to concerns
over methane’s explosiveness and the
risk of hypoxia and exposure to various
associated pollutants. In addition, also
as discussed in connection with
§ 3179.6, the BLM has the authority to
regulate air quality and GHG impacts on
and from public lands pursuant to
FLPMA and the MLA.
Some commenters raised concerns
about differences between the proposed
BLM and EPA requirements for

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pneumatic pumps, asserting that the
BLM proposed rules are different and
more stringent. First, they asserted that
the EPA rule limits ‘‘affected facilities’’
to sites with a control device already onsite, while the proposed BLM
requirements would apply to pneumatic
pumps regardless of whether a control
device is present. Second, commenters
asserted that the EPA rule only requires
operators to route pump emissions to a
control device if one already exists on
site, while the BLM proposed rule may
require replacement with a zero
emission pump in such a circumstance.
Some of these concerns were
addressed by the EPA’s final subpart
OOOOa regulations, while other
differences are appropriate given the
different authorizing statutes and
primary foci of the two sets of
regulations. As an initial matter, the
BLM requirements apply only to pumps
that are not subject to subparts OOOO
or OOOOa (but would be if the pump
was new, modified, or reconstructed), so
no pump will be subject to both
regulations.
With regard to the first issue
described above, the final BLM and EPA
rules apply to the same types of
pneumatic pumps. In its final rule, EPA
noted that there was some confusion
regarding the proposed definition of
affected facility, and stated that it had
modified the regulatory text to clarify
that ‘‘all natural gas-driven diaphragm
pumps at natural gas processing plants
or well sites are affected facilities,
except for pumps at well sites that
operate less than 90 days per calendar
year.’’ 145 The final subpart OOOOa text
requires operators to maintain records
on the control status of all pneumatic
pump affected facilities and to include
them all in the operators’ annual
reports. The final BLM rule aligns with
the scope and requirements of the final
EPA rule in these respects.
With regard to the second issue, the
BLM final rule does apply somewhat
different requirements to pumps
covered by the BLM rule as compared
to pumps covered by the EPA rule, due
to differences between the two agencies’
legal authorities. The legal authority for
subpart OOOOa is section 111 of the
Clean Air Act, which requires the EPA
to set standards of performance for new
sources and requires a ‘‘standard of
performance’’ to be based on the best
system of emission reduction (BSER)
‘‘adequately demonstrated.’’ 146 As
noted in the proposed subpart OOOOa
preamble, the EPA did not require zero
emissions pumps at facilities other than
145 81
146 81

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gas processing plants because the
availability of consistent, reliable
electrical power at all affected facilities
could not be reasonably assumed.147
The BLM, however, has flexibility to
require waste reduction measures at any
site where such measures would work,
without specifically defining such sites,
even if the measures may not be
available at all sites. Zero emission
pumps are feasible where solar power is
adequate to power the pump for its
intended function and at sites where
other sources of electric power are
available. Where they are feasible, our
analysis indicates that the cost of
replacing a gas-driven pneumatic pump
with a zero emission pump is modest
and would be at least partially offset by
the value of the saved gas.
Additionally, the BLM final rule
establishes a preference for operators
who do not replace their pumps with a
zero-emissions pump to route exhaust
gas to capture in lieu of routing to a
flare. This emphasis on either
replacement or capture is a function of
the BLM’s waste prevention focus.
Thus, unlike subpart OOOOa, the final
BLM rule requires operators with a gasdriven pneumatic pump that is
currently venting to the atmosphere to
replace it with a zero emission pump, if
a zero-emission pump would work at
that site to perform the function
required, or route the exhaust gas to
capture. If a zero-emission pump is not
viable at that site and routing the
exhaust gas to capture is technically
infeasible or unduly costly, however,
then the operator must comply with a
requirement that tracks the requirement
under subpart OOOOa—the operator
must route the exhaust gas from the
pneumatic pump to a flare, if there is
already a flare on-site. While the BLM
rule establishes an additional
requirement on operators, it does not
conflict in any way with the EPA rule
or increase an operator’s burden to
comply with both rules. Any pump that
is already routed to a flare in
compliance with the EPA rule will also
be in compliance with the BLM rule.
For pumps without a flare on-site, the
EPA rule requires no further action,
while the BLM rule requires
replacement or routing to capture,
absent the listed conditions.
The third potential difference that
commenters highlighted between the
BLM and EPA requirements for
pneumatic pumps is the level of
documentation required to show that
routing to a flare is technically
infeasible. To clarify a possible
misunderstanding by the commenters, a
147 80

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requirement to notify the BLM through
a Sundry Notice, as specified in this
section, is not a requirement to obtain
approval from the BLM. Sundry Notices
may be used simply for notification
purposes, or to obtain approval from the
BLM for an action. The final rule
specifies the purpose of each
requirement to file a Sundry Notice.
Here, the BLM final rule requires an
operator to notify the BLM through a
Sundry Notice if the operator is not
replacing the pump for one of the
reasons specified. The operator must
also notify the BLM if the operator is not
routing the pump to a flare because
there is no flare on site or routing to a
flare would be technically infeasible.
Subpart OOOOa establishes
requirements for an engineering
evaluation of whether routing to a flare
would be technically infeasible, requires
the evaluation and determination of
technical infeasibility to be certified by
a qualified professional engineer, and
requires this information to be included
in the operator’s annual report. Thus,
while the specific documentation
requirements for pumps covered by the
BLM requirements differ from those
established by the EPA, both rules
require the operator, under specified
circumstances, to either route the pump
exhaust to a flare or notify the
respective agency that the pump meets
the criteria for an exemption. The BLM
notification requirements are less
specific than the EPA requirements,
which the BLM believes will make
compliance less burdensome for an
operator.
Section 3179.203 Storage Vessels
This section addresses gas vented
from crude oil, condensate, intermediate
hydrocarbon liquid, or produced water
storage vessels that contain production
from a Federal or Indian lease, or from
a unit or communitized area that
includes a Federal or Indian lease, and
are not subject to 40 CFR part 60,
subparts OOOO or OOOOa, but would
be if they were new, modified, or
reconstructed sources. If such storage
vessels have the potential for VOC
emissions equal to or greater than 6 tpy,
the final rule requires operators to route
all gas vapor from the vessels to a sales
line. Alternatively, the operator may
route the vapor to a combustion device
if it determines that routing the vapor to
a sales line is technically infeasible or
unduly costly. The operator also may
submit a Sundry Notice to the BLM that
demonstrates that compliance with the
above options would cause the operator
to cease production and abandon
significant recoverable oil reserves
under the lease due to the cost of

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compliance. Operators must meet this
requirement no later than one year after
the rule becomes effective, or three
years after the rule becomes effective if
the operator needs to replace the storage
vessel in order to comply.
Operators must determine the rate of
VOC 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 determination is
based on the maximum average daily
throughput for a 30-day period of
production, and may take into account
any legally and practically enforceable
limits in an operating permit or other
requirements applicable to the storage
vessel. This section no longer applies to
a storage vessel whose total
uncontrolled VOC emissions rate
declines to 4 tpy in the absence of
controls for 12 consecutive months.
In response to comments, the BLM
has made the following changes to the
requirements in the proposed rule: (1)
Clarified the exemption for sources
subject to 40 CFR part 60, subparts
OOOO or OOOOa; (2) extended the
initial compliance period from 6 months
to 1 year; (3) added a 3-year initial
compliance period for operators that
must replace storage vessels to comply
with the requirements; (4) required gas
to be routed to a sales line when that
option is neither technically infeasible
nor unduly costly, as determined by the
operator; (5) added a requirement that
operators must determine whether the
storage vessel has the potential for VOC
emissions equal to or greater than 6 tpy
based on the maximum average daily
throughput for a 30-day period of
production, which may take into
account legally and practically
enforceable limits applicable to the
storage vessel; (6) added a requirement
that storage vessels subject to the final
rule must be adequately sized to
accommodate the operator’s production
levels and equipped to meet any
applicable regulatory requirements for
tank vapors; and (7) added a
requirement that storage vessels subject
to the final rule may only vent through
properly functioning pressure relief
devices. Each change is discussed below
along with a summary of the relevant
comments and responses.
Several commenters expressed
concerns about differences between the
types of new storage vessels that are
subject to subparts OOOO or OOOOa
and the types of existing storage vessels
that would have been subject to the
proposed rule. The BLM agrees that
applying the requirements of this
section, as proposed, to storage vessels
‘‘not subject to 40 CFR part 60, subparts

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83061

OOOO or OOOOa’’ could encompass
storage vessels that neither the EPA nor
the BLM intended to cover. In the final
rule, § 3179.203(a)(2) covers a storage
vessel if it ‘‘[i]s not subject to any of the
requirements of 40 CFR part 60,
subparts OOOO or OOOOa, but would
be subject to that subpart if it were a
new, modified, or reconstructed
source.’’
Several commenters argued that the
proposed initial period of 6 months to
comply with the emission reduction
provisions was too short. Commenters
stated that it would take longer than 6
months to complete engineering studies
of existing storage vessels; design, order
and construct the control device; and
then install the control device.
Commenters recommended various time
periods ranging from 1 to 3 years. We
believe a 1-year initial compliance
period is adequate to perform the tasks
necessary to install a control device, and
we have modified § 3179.203(c)
accordingly.
Commenters also stated that in some
cases they would likely have to replace
an existing tank in order to meet the
emission limitations. In such cases,
commenters stated that even more time
would be needed to obtain capital
funding approval and purchase the new
storage vessel. In response, we further
amended § 3179.203(c) to provide a 3year initial compliance period when the
operator must replace a storage vessel in
order to comply with the rule
requirements.
In the proposed rule, § 3179.203(c)
allowed the operator to choose between
routing emissions from storage vessels
subject to the rule to a combustion
control device, a continuous flare, or a
sales line. Some commenters opposed
these provisions because they believe
BLM should focus on preventing loss of
natural resources. The BLM agrees that
this rule should focus on gas capture
and use whenever possible, and in the
final rule, § 3179.203(c) first requires the
operator to route tank vapor gas from a
storage vessel to a sales line. If the
operator determines that routing the
emissions to the sales line is technically
infeasible or unduly costly, the operator
may route the gas to a combustion
device.
We also received numerous comments
requesting that we align the final rule as
much as possible with the requirements
finalized by the EPA in subparts OOOO
and OOOOa. As stated in the preamble
to the proposed rule, the BLM and the
EPA understand that aligning our
requirements to the extent possible,
provides common standards that ease
implementation and reduce confusion
for both the regulated industry and

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regulatory agencies.148 Several small
changes in the final rule help clarify the
rule and better align it with the final
requirements in subparts OOOO and
OOOOa. In § 3179.203(b), the rule
provides additional guidance to
operators on how to make the threshold
determination that a storage vessel has
the potential for VOC emissions equal to
or greater than 6 tpy. Changes to the
definition of ‘‘storage vessel’’ in § 3179.3
also synchronize the coverage between
the two sets of rules, such that these
provisions cover the same types of
storage vessels that would be covered by
subparts OOOO or OOOOa if they were
new, modified, or reconstructed.
One commenter suggested that the
BLM make it clear that venting from
access points or pressure relief devices
during normal operation is prohibited.
The commenter stated that to account
for those instances where venting may
be necessary, the BLM could adopt the
approach taken by Colorado by
specifying those instances where
venting is reasonably required, such as
for ‘‘maintenance, gauging or safety of
personnel and equipment.’’ The
commenter also recommended that the
BLM add a requirement that operators
certify that their storage tank facilities
are adequately sized in order to capture,
convey, and control emissions. They
stated that this is required in Colorado
and is a direct response to the Air
Pollution Control Division and EPA
investigations that revealed significant
leaks and venting from controlled
facilities.
In response to this comment, final
rule § 3179.203(f) provides that storage
vessels subject to this section must be
adequately sized to accommodate
production levels and equipped to meet
any applicable regulatory requirements
for emissions. Also, § 3179.203(g)
requires that storage vessels subject to
this section may only vent through
properly functioning pressure relief
devices. We believe both of these
provisions embody good engineering
practices and should be common
practice when operating a storage
vessel.
The BLM also received comments
asserting that it lacks the authority to
require operators who opt not to capture
tank vapor gas to route such gas to a
flare device (rather than venting).
Commenters argued that such a
requirement does not fall within the
BLM’s MLA authority because it is not
waste prevention—i.e., the gas is lost
whether it is vented or flared. These
commenters then argued that the only
possible justification for the
148 See,

e.g., 81 FR 6647.

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requirement was control of GHGs and
other air pollutants, which commenters
assert is exclusively within the EPA’s
domain.
The BLM disagrees with these
comments for several reasons. First, the
requirement in this section to flare
rather than vent tank vapor gas
constitutes waste prevention. Requiring
operators to (at minimum) direct tank
vapor gas to a flare device eliminates the
lowest cost method of handling such gas
(i.e., venting), and thereby provides a
higher baseline for operators to calculate
whether it would be economical to
install a VRU to capture the tank vapor
gas for sale. The BLM anticipates that
this higher baseline may encourage
more operators to install VRUs.
Second, as discussed in connection
with § 3179.6, a requirement to flare
rather than vent associated gas is a
safety measure under the MLA. It is
generally safer to combust methane gas
than to allow it to vent uncombusted
into the surrounding air due to concerns
over methane’s explosiveness and the
risk of exposure to various associated
pollutants. In addition, also as
discussed in connection with § 3179.6,
the BLM has the authority to regulate air
quality and GHG impacts on and from
public lands pursuant to FLPMA and
the MLA.
Some commenters requested that the
BLM require storage vessel vapors to be
combusted at an efficiency of 98%.
Storage vessel vapors can be combusted
at an efficiency of 98% using an
enclosed combustor. However, the BLM
has determined that requiring the
operator to install an enclosed
combustor on a location with an
existing flaring system would be
relatively costly compared to the benefit
of modestly higher combustion
efficiency applied to a comparatively
small volume of vapor coming from
storage vessels flares. The BLM believes
that in those instances where storage
vessel vapors must be controlled on a
site that does not have an existing flare
system, the operator will likely elect to
install an enclosed combustor rather
than a flare, because it will more
effectively combust the lower volumes
of vapor associated with storage vessels.
Section 3179.204 Downhole Well
Maintenance and Liquids Unloading
This section establishes requirements
for venting and flaring during downhole
well maintenance and liquids
unloading. It requires the operator to
use practices for such operations that
minimize vented gas and the need for
well venting, unless the practices are
necessary for safety. The rule also
requires that for wells equipped with a

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plunger lift system or an automated well
control system, the operator must
optimize the operation of the system to
minimize gas losses.
For all wells, before the operator
manually purges a well for the first time
after the effective date of this section,
the operator must document in a Sundry
Notice that other methods for liquids
unloading are technically infeasible or
unduly costly. In addition, during any
liquids unloading by manual well
purging, the person conducting the well
purging is required to be present on-site
to minimize to the maximum extent
practicable any venting to the
atmosphere. This section also requires
the operator to maintain records of the
cause, date, time, duration and
estimated volume of each venting event
associated with manual well purging,
and to make those records available to
the BLM upon request.
The operator must notify the BLM by
Sundry Notice within 30 days after the
first liquids unloading by manual or
automated well purging after the
effective date of the rule. Additionally,
operators must notify the BLM by
Sundry Notice within 30 days after the
following conditions are met: (1) The
cumulative duration of manual well
purging events for a well exceeds 24
hours during any production month; or
(2) the estimated volume of gas vented
in the process of conducting liquids
unloading by manual well purging for a
well exceeds 75 Mcf during any
production month. The final rule also
defines ‘‘well purging’’ for purposes of
this section and requires operators to
report to ONRR gas volumes vented
during manual and automated
downhole maintenance and liquids
unloading, including through the
operation of plunger lifts.
In response to comments on the
proposed rule, we removed the
proposed prohibition on well purging
for wells drilled after the effective date
of this section, as discussed in above in
section III.D.3., and made several
smaller changes in the final rule: (1)
Removing the proposed requirement to
flare unrecovered gas during downhole
well maintenance and liquids unloading
operations; (2) clarifying recordkeeping
and reporting requirements and
increased the length of time operators
have to submit reports; and (3) revising
the definition of ‘‘well purging.’’
The BLM is aware, and many
commenters observed, that flares are not
always feasible control options for
downhole well maintenance and liquids
unloading activities, and we recognize
that there may be difficulties separating
liquids from the purged gases. For these
reasons, we proposed the use of flares

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where other recovery or gas loss
reduction technologies cannot be used,
and only then when flaring is not
technically infeasible or unduly costly
(see proposed § 3179.204(a)). Although
we attempted in the proposed rule to
narrow the use of flares to situations in
which they are more likely to be
feasible, and provided an option for
operators to document those situations
where flaring is infeasible, commenters
raised several concerns related to safety,
cost and feasibility. Upon further review
of the information provided by the
commenters, we believe there is
uncertainty in the ability of operators to
be able to consistently and safely
operate a flare during these operations.
For these reasons, we did not finalize
the proposed flaring requirement.
Instead, the final rule requires operators
to minimize vented gas during
downhole well maintenance and liquids
unloading operations, and it specifies
best management practices that
operators must follow. For wells
equipped with a plunger lift system or
an automated well control system, these
practices include optimizing the
operation of the system to minimize gas
losses.
Proposed § 3179.204(a) would have
required the operator to use best
practices to maximize the recovery of
gas from downhole well maintenance
and liquids unloading operations.
Commenters expressed concern that the
word ‘‘maximize’’ could be construed to
imply that the operator must use the
technology that provides the absolute
highest amount of gas recovery,
regardless of other concerns. This is not
our intent, as evidenced by our
discussion of the proposed requirements
in the preamble to the proposed rule.
For example, we discuss that some
technologies are less costly than others,
and that some technologies make more
sense to install early in the life of a well
rather than later. We also state that we
expect most new wells to use plunger
lifts, and that the proposed rule would
not require (though it would encourage)
the use of automated systems.149 We
expect the operator to make an informed
and reasoned decision on which
technology makes the most sense for
each well based on the conditions and
economics of the well. To further clarify
this, rather than requiring operators to
maximize recovery of gas, the final rule
requires operators to minimize vented
gas and the need for well venting
associated with downhole well
maintenance and liquids unloading
operations.

Several commenters objected to the
extent and content of the proposed
recordkeeping requirements, but did not
identify changes that could be made
without compromising the information
needed for effective implementation of
the rule. The BLM believes the
recordkeeping and reporting
requirements are essential to verify
compliance and to more accurately
assess the amount of gas lost through
liquids unloading events, including for
the purposes of royalty calculations. In
response to commenters’ concerns,
however, the final rule extends the time
to submit a Sundry Notice of large
quantity liquids unloading events from
14 days to 30 days, to allow operators
more time to gather information.
Similarly, we have extended the time to
submit a Sundry Notice after the first
liquids unloading event from 10 days to
30 days.
Some commenters contended that
recordkeeping and reporting
requirements related to each well
purging event are unnecessary, but the
BLM does not agree. Large quantities of
gas are lost through well purging that
cannot be used to supply the country’s
energy needs and provide no royalty
revenues to taxpayers. Building a
historical record of the amount of gas
lost is key to determining proper
management of these events in the
future. For example, more accurate
knowledge of the amount of gas lost to
well purging events will allow operators
to make better-informed decisions on
the financial viability of each liquids
unloading technology. Also, the BLM
will be able to better estimate the cost
of lost royalties associated with vented
gas from well purging activities. We
believe these important benefits justify
the expenditures related to obtaining
and reporting the required records.
A number of commenters asserted
that BLM should withdraw the
proposed downhole well maintenance
and liquids unloading provisions of the
rule because of the complexity of the
issue. They argued that the BLM does
not understand the impacts of the
proposed requirements. In particular,
they noted EPA’s decision not to
regulate liquids unloading.
The BLM has engaged numerous
stakeholders throughout the rulemaking
process to better inform its final rule
decisions, and has coordinated closely
with the EPA in sharing technical
information and expertise.150 This is an
area where differences between the two
agencies’ approaches stem in large part
from their different statutory authorities.
As noted above in connection with

§ 3179.202, the legal authority for 40
CFR part 60 subpart OOOOa is section
111of the Clean Air Act, which requires
the EPA to set a standard of
performance for new sources and
defines a ‘‘standard of performance’’ as
to be based on the best system of
emission reduction (BSER) ‘‘adequately
demonstrated.’’ 151
In explaining its decision not to
regulate liquids unloading at this time,
the EPA stated that although it had
received valuable information from the
public on technologies to reduce
emissions, ‘‘the information was not
sufficient to finalize a national standard
representing BSER for liquids
unloading.’’ 152 The BLM, however, has
the flexibility to require a suite of best
management practices to achieve waste
reduction, as we have done here, rather
than being required to identify the best
system of emission reduction under the
specific criteria in section 111 of the
Clean Air Act.
Section 3179.301 Operator
Responsibility
This section establishes that the
LDAR requirements in §§ 3179.301
through 3179.305 of this subpart apply
to oil or natural gas wells and all
equipment associated with the well sites
that produce, process, compress, treat,
store, or measure natural gas from a
Federal or Indian lease, or from a unit
or communitized area, where the site is
upstream of or contains the approved
point of royalty measurement. These
sections also apply to a site and all
equipment operated by the operator and
associated with a site that is used to
store, measure, or dispose of produced
water that is located on a Federal or
Indian lease. The sections obligate
operators to inspect all equipment that
is used to produce, compress, treat,
store, or measure natural gas or to store,
measure or dispose of produced water
for gas leaks from leak components,
with the exception of wells and well
equipment that have been
depressurized, and sites that contain
only a well head and no other
equipment. The first inspection must
occur within one year of the effective
date of the rule for sites that have begun
production prior to the effective date.
For production sites that begin
production after the effective date, the
first inspection must occur within 60
days of beginning production. For sites
that were out of service and brought
back into service, the first inspection
must occur within 60 days of the date
the site is brought back into service and
151 42

149 81

FR 6655–6656.

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re-pressurized. These sections do not
apply to a site that contains a wellhead
or wellheads and no other equipment,
nor to a well or well equipment that has
been depressurized.
Operators are required to conduct the
inspections during production
operations, and to fix any leaks found.
Subsequent inspections must be
conducted according to the schedule in
§ 3179.303. Operators may satisfy the
requirements of §§ 3179.301 through
3179.305 for all of their equipment on
a given lease by complying with the
fugitive emissions requirements
established under 40 CFR part 60,
subpart OOOOa with respect to all
equipment covered by the BLM leak
detection requirements. This includes
equipment such as covers and closed
vent systems, and thief hatches and
other openings on controlled storage
vessels, which if new, modified or
reconstructed, are subject to 40 CFR
60.5411a or 60.5395a under OOOOa and
not the fugitive emissions requirements
under OOOOa. Specifically, the
operator must treat each of its sites and
equipment as if it were a collection of
fugitive emissions components as
defined in 40 CFR part 60 subpart
OOOOa; comply with the requirements
of 40 CFR part 60 subpart, OOOOa that
apply to affected facility fugitive
emissions components at a well site or
compressor station, as applicable, under
40 CFR part 60, subpart OOOOa; and
notify the BLM through a Sundry Notice
of such compliance.
Several changes were made to this
section in response to comments and to
provide additional clarity. As discussed
in Section V.B.2., § 3179.301(a) clarifies
the specific sites and equipment subject
to the leak inspection requirements,
which apply to all equipment handling
Federal or Indian gas, upstream of and
including the site where the royalty
measurement point is located—whether
the equipment is on or off the lease and
regardless of the ownership of the
equipment. This section also specifies
that the leak detection requirements
apply to equipment handling produced
water only if the equipment is operated
by the operator and located on the
Federal or Indian lease. The BLM added
a provision to § 3179.301(b) stating that
the LDAR requirements do not apply to
a well or well equipment that has been
depressurized, nor to a site that contains
a wellhead or wellheads and no other
equipment. In § 3179.301(c), the BLM
clarified that the operator must inspect
for gas leaks from leak components. In
conjunction with this change, we added
definitions for ‘‘leak’’ and ‘‘leak
component’’ in § 3179.3. We also moved
the definition of ‘‘site’’ from

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§ 3179.303(a) to § 3179.301(e) and
revised the definition for clarity.
Additionally, the BLM moved the
requirement in proposed § 3179.303(c)
that exempts leak components that are
not accessible from the inspection and
monitoring requirements to paragraph
(d) of this section; added paragraph (f)
to specify when the first inspection
must take place; and replaced proposed
paragraph (e) with new paragraph (j) to
provide an exemption for sites and
equipment that are in compliance with
the fugitive emission requirements
under 40 CFR part 60, subpart OOOOa.
This section of the preamble discusses
additional comments on the LDAR
provisions in § 3179.301, beyond the
comments discussed in Section IV.A.d.
The BLM made changes to clarify the
scope of LDAR coverage in the final rule
in response to commenters who asserted
that the proposed rule was not entirely
clear on the scope of coverage. The final
rule now explicitly describes the ‘‘sites’’
to which the LDAR provisions apply
and no longer makes use of the term
‘‘facilities.’’ The proposed rule covered
‘‘facilities,’’ as well as compressors that
were on lease and operated by the
operator, regardless of whether they
handled Federal or Indian product.
‘‘Facility’’ is defined in section 3170.3
to include a site and associated
equipment used to process, treat, store,
or measure production from a Federal or
Indian lease, unit or communitized area,
as well a site and associated equipment
used to store, measure, or dispose of
produced water. With respect to
produced water, the definition of
‘‘facility’’ only includes sites on a
Federal or Indian lease, unit or
communitized area, but the definition is
not similarly limited with respect to
sites associated with Federal or Indian
production. Using the term ‘‘facilities’’
to define the coverage of the LDAR
program would create a distinction
between equipment upstream and
downstream of the approved point of
royalties measurement on an otherwise
covered site. In addition, the BLM has
not retained in the final rule the
proposed coverage for compressors that
do not handle Federal or Indian
product. Given the potential for
confusion here, we believe that it is
clearer to simply specify the sites and
equipment subject to the LDAR
requirements in the final rule, rather
than use the term ‘‘facilities.’’
With respect to the LDAR
requirements in this rule, the BLM
believes it is reasonable and appropriate
to apply the requirements to all
equipment at a site that is subject to
these requirements. Once an operator is
already on-site, inspecting additional

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equipment adds little cost and burden,
particularly if the operator is using
optical gas imaging technology, and
inspecting such equipment offers the
same potential additional benefits as
any other inspection. Thus, the BLM
believes that requiring inspection of all
of the equipment at a given site will
make the rule more cost-effective in
avoiding waste, as compared to
exempting inspection of some
equipment at a site that is already being
inspected. Moreover, the BLM believes
that applying the LDAR requirements to
most but not all of the equipment at a
single site would heighten the potential
for inspection errors and confusion, and
make administration and tracking of the
results more difficult.
Commenters also urged the BLM to
exclude from the LDAR requirements
the following additional types of sites or
equipment, beyond those discussed in
Section IV.A.d,: Wells that are shut-in at
the time of an LDAR inspection; sites
where there is only a small amount of
mineral interest from or allocated to a
Federal or Indian lease, unit, or
communitization agreement; equipment
operated by an entity other than the
operator; sites with a legally and
practically enforceable leak detection
and repair requirement in an operating
permit, or other enforceable requirement
established under a Federal, State, local
or tribal authority; and sites located on
the North Slope of Alaska.
With respect to wells that are shut-in
at the time an inspection occurs,
coverage under LDAR depends on
whether the shut-in is temporary, or the
well or well equipment has been
depressurized. Leaks will only be
detectable when a well is operating, so
the rule provides that leak inspections
must occur during production
operations. The BLM agrees that a well
that has been depressurized is no longer
in operation and should not leak, and
the BLM has excluded such wells from
the LDAR requirements. Depressurized
wells that are brought back into service
do not need to be inspected until 60
days after the date that the well is repressurized. A well that is temporarily
shut-in but not depressurized, however,
may have significant leaks when it is
brought back into production.
Exempting such a well from any
inspection obligations might provide an
incentive for operators to schedule
inspections during shut-ins to reduce
the number of sites that would need to
be inspected.
With respect to leases where the
Federal or Indian mineral interest is a
minority interest, the BLM has the
authority and an obligation to minimize
the waste of Federal and Indian mineral

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resources. The waste of Federal and
Indian resources is of no less concern to
the BLM when the Federal or Indian
interest is a minority interest. Even a
small percentage interest could still
represent a significant volume of
Federal or Indian resources, depending
on the reservoir. Also, as a policy
matter, the BLM believes that the LDAR
requirements of this rule are costeffective and provide net public
benefits. Thus, the BLM does not
believe that it is appropriate to
arbitrarily limit the benefits of this rule
based on the proportion of the Federal
or Indian mineral interest at issue in the
lease, unit, or communitized area. In the
final rule, the BLM has clarified that
where a site is upstream of or contains
the royalty measurement point, the
LDAR provisions cover the site and all
equipment associated with it that
handles Federal or Indian gas.
Similarly, neither legal nor policy
considerations support exempting
equipment operated by an entity other
than the site operator. The operator is
responsible for ensuring that operations
conducted pursuant to a Federal or
Indian lease are in compliance with the
lease terms and applicable
regulations.153 Exempting equipment
that is operated by an entity other than
the operator could create an incentive
for operators to establish contractual
arrangements that avoid the LDAR
requirements. The BLM believes that
through cooperation with contractors
that own or operate equipment on the
lease, the operator has the practical
means of ensuring compliance with the
LDAR requirements on lease, regardless
of who owns the equipment.
The BLM recognizes that some
equipment at the site containing the
facility measurement point, such as
storage vessels or compressors, may be
downstream of the measurement point
and may be in control of the purchaser
rather than the operator.154
Nevertheless, as discussed previously,
the BLM believes that it is appropriate
to require the operator to conduct LDAR
on all equipment located at the site.
Once the operator is inspecting a given
site, particularly when using optical gas
imaging, it will add minimal time and
cost to inspect additional co-located
equipment. It should be noted that,
153 See Luff Exploration Co., 115 IBLA 134 (1990)
(upholding enforcement action against operator
based on noncompliant equipment owned and
operated by purchaser).
154 The BLM’s jurisdiction over Federal and
Indian oil and gas production does not cease at the
point of royalty measurement. See Wexpro
Company, 174 IBLA 57 (2008) (requiring BLM to
consider whether use of gas in operations
downstream of the royalty measurement point
constituted royalty-free ‘‘beneficial use’’).

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although a facility measurement point
may be located on lands not covered by
a Federal or Indian lease, unit, or
communitization agreement (as might
be the case when off-lease measurement
occurs pursuant to applicable
regulations in 43 CFR subpart 3173), the
LDAR requirements of this rule do not
apply to sites that are not located on a
Federal or Indian lease, unit or
communitized area.
In addition, the BLM disagrees with
the suggestion to create a blanket
exemption from the LDAR requirements
for sites with another legally and
practically enforceable leak detection
and repair requirement in an operating
permit or other enforceable Federal,
State, local or tribal requirement. The
final rule already contains provisions to
address overlapping EPA or State
requirements, as discussed in sections
III.B.3 VI.A. of this preamble. An
operator with a specific program
contained in its operating permit could,
under section 3179.303(b) request
approval of that program as an
alternative to the BLM requirements,
provided the permit program is at least
equally effective at detecting and
reducing losses from leaks as the BLM
requirements. By contrast, exempting
any site with existing enforceable LDAR
requirements provides no assurance that
those requirements will produce results
equivalent to the BLM requirement.
The BLM also declines to exclude
automatically from the LDAR
requirements sites that are located on
the North Slope of Alaska. The BLM
notes that one operator has argued that
conditions on the North Slope make it
impossible to meet all of the LDAR
requirements, and that the operator has
in place alternative practices,
equipment, and techniques that reduce
the likelihood of leaks and facilitate
prompt detection of any that might
occur. The final provision allowing the
BLM to approve an operator’s
alternative instrument-based leak
detection program is designed to
address just this sort of situation.
Certain operators requested that
facilities subject to the EPA subpart
OOOOa fugitive emissions requirement
be exempt from the BLM LDAR
requirements. After review of these
comments, the BLM agrees that those
facilities should not have to comply
with both the EPA subpart OOOOa
program and a separate BLM LDAR
program, and the final rule provides that
an operator in compliance with the
requirements of subpart OOOOa will be
deemed in compliance with the BLM
LDAR requirements as well. In addition,
even though the BLM and the EPA have
largely aligned their leak detection

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requirements, an operator might prefer
to comply with the OOOOa
requirements for all of its facilities on a
lease, including existing facilities that
are not covered by subpart OOOOa,
rather than complying with subpart
OOOOa for new, modified and
reconstructed facilities and the BLM
LDAR requirements for existing
facilities. Thus, the final rule provides
that an operator may satisfy the BLM
LDAR requirements by complying with
the subpart OOOOa fugitive emission
requirements for all sites and equipment
on a given lease.
However, by providing that
compliance with subpart OOOOa is
deemed compliance with the BLM
requirements, rather than simply
exempting all facilities subject to
subpart OOOOa, the BLM maintains
enforcement authority if an operator is
subject to both subpart OOOOa and the
BLM requirements, but complies with
neither. Under this approach, a BLM
inspector in the field could review
information to confirm that the operator
is in fact in compliance with one set of
leak detection requirements.
Section 3179.302 Approved
Instruments and Methods
This section prescribes the types of
instruments that an operator must use to
inspect for leaks. Specifically, operators
must use: (1) An optical gas imaging
device such as an infrared camera; (2) a
portable analyzer capable of detecting
leaks in compliance with Method 21 of
40 CR part 60, appendix A–7; or (3) a
leak detection device not listed in this
section that has been approved by BLM.
The persons using the above devices
must be adequately trained in their use.
Anyone may request approval of an
alternative monitoring device and
protocol by submitting a Sundry Notice
with the information specified in
paragraph (c) of this section, subject to
the approval of the BLM as specified in
paragraph (d).
In the final rule, the BLM amended
paragraph (a) of this section by
removing reference to monitoring
methods since this paragraph specifies
monitoring equipment, not methods. In
paragraph (a)(2), we added a provision
that portable analyzers must be operated
in compliance with Method 21 rather
than manufacturers specifications. We
removed from paragraph (a) the
proposed option of using a
comprehensive program approved by
the BLM under § 3179.303(b).
The BLM also added a provision at
paragraph (b) that the person operating
the leak detection device must be
adequately trained in the proper use of
the device. We added an option at

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paragraph (c) where any person may
request approval of an alternative
monitoring device and protocol by
submitting a Sundry Notice with the
information specified in paragraph (c).
The request will be subject to the
approval of the BLM as specified in
newly added paragraph (d), which
includes the requirement that it must be
demonstrated that the alternative leak
detection device and associated protocol
will achieve equal or greater reduction
of gas lost through leaks compared to
the approach specified in
§ 3179.302(a)(1). Paragraph (d) also
establishes that the BLM will provide
public notice of the submission of an
alternative device or monitoring
protocol for approval, and will post on
the BLM Web site a list of each
approved alternative monitoring device
and protocol and limitations on its use.
The final rule also notes that the BLM
may approve an alternative device and
monitoring protocol for use in all or
most applications, or instead just for use
on a pilot or demonstration basis.
Please see Section III.A.d for a
discussion of major comments received
on this section of the proposed rule.

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Section 3179.303 Leak Detection
Inspection Requirements for Natural Gas
Wellhead Equipment and Other
Equipment
This section requires operators to
conduct initial site inspections within
specified timeframes after the effective
date of the rule. The section requires the
operator initially to conduct site
inspections twice a year, with
consecutive semiannual inspections
conducted at least four months apart;
and to conduct compressor station
inspections quarterly, with consecutive
quarterly inspections conducted at least
60 days apart. The inspection
frequencies are fixed.
Paragraph (b) of this section
authorizes the BLM to approve an
alternative instrument-based leak
detection program if the BLM finds that
the alternative would achieve equal or
greater reduction of gas lost through
leaks compared with the approach
specified in §§ 3179.302(a)(1) and
3179.303(a). The operator must submit
the request through a Sundry Notice.
The operator also has the option to
request approval of a leak detection
program that does not meet the criterion
specified in § 3179.303(b) when it can
be demonstrated that compliance with
the requirements of §§ 3179.301 through
3179.305 would cause the operator to
cease production and abandon
significant recoverable oil or gas
reserves under the lease.

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In the final rule, the BLM clarified in
paragraph (a) of this section that the
operator must inspect leak components
at the site, and that the inspection must
be conducted using a leak detection
device listed under § 3179.302. The
BLM is maintaining a semiannual
inspection frequency for each site, and
added provisions for quarterly
inspections of compressor stations. In
the final rule, these inspection
frequencies are fixed, and the BLM did
not finalize the proposed table of
variable, performance-based inspection
frequencies.
Paragraph (b) of this section allows for
BLM approval of an alternative program,
if an operator submits an approval
request via a Sundry Notice. It is the
BLM’s intent that those approvals be
made at the State office level for
intrastate programs, and at the national
or Washington office level for interstate
programs. Final § 3179.303(b) differs
slightly from the proposed version of
this provision. First, the final rule
specifies that the approval applies to an
‘‘alternative instrument-based leak
detection program’’ instead of the
proposed ‘‘alternative leak detection
device, program, or method.’’ Next, the
rule specifies that the approval is in lieu
of complying with paragraph (a) of this
section, and that the alternative must
achieve equal or greater reduction of gas
lost through leaks compared with the
approach specified in §§ 3179.302(a)(1)
and 3179.303(a). The BLM also added
details of what the Sundry Notice must
include at § 3179.303(b)(1)–(5), and
added paragraph (e) stating that
approved alternative LDAR programs
will be posted online.
Additionally, the BLM added a
provision at paragraph (c) of this section
to provide the operator with the option
to request approval of a leak detection
program that does not meet the criterion
specified in § 3179.303(b) when it can
be demonstrated that compliance with
the requirements of §§ 3179.301 through
3179.305 would cause the operator to
cease production and abandon
significant recoverable oil or gas
reserves under the lease. The BLM also
added paragraph (d) setting forth the
requirements for the Sundry Notice to
support a demonstration under
paragraph (c).
Please see Section III.A.d for a
discussion of major comments received
on this section of the proposed rule.
Section 3179.304 Repairing Leaks
This section requires operators to
repair any leak as soon as practicable
and no later than 30 calendar days after
discovery of the leak, unless there is
good cause for repair to take longer. The

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rule requires the operator to notify the
BLM by Sundry Notice if there is good
cause to delay the repairs beyond 30
days, and to complete the repair at the
earliest opportunity, but in no case
longer than 2 years after discovery. The
rule also requires the operator to
conduct a follow-up inspection, using
an authorized method, to verify the
effectiveness of the repair within 30
calendar days after the repair, and to
make additional repairs within 15
calendar days if the previous repair was
not effective. This repair and follow-up
process must be followed until the
repair is effective. The BLM does not
consider an inspection to verify the
effectiveness of a repair to be a periodic
inspection under § 3179.303.
In the final rule, the BLM increased
the time period for completing repairs
from the proposed 15 days to 30 days.
Operators also have 30 days, as opposed
to the proposed 15 days, to verify the
effectiveness of the repair through a
follow-up inspection. While the
proposed rule would have required that
the follow-up inspection be carried out
using the method originally used to
detect the leak, the final rule specifies
that any of the instruments specified or
approved under § 3179.302(a) or the
soap bubble test under EPA’s Method
21, section 8.3.3, may be used.
In paragraph (a) of this section in the
proposed rule, the BLM specified that
the operator must repair any leak ‘‘not
associated with normal equipment
operations.’’ In the final rule, we specify
that ‘‘any leak’’ must be repaired as soon
as practicable, but within 30 days after
discovery. In conjunction with this
change, we have added to § 3179.3 a
definition of ‘‘leak’’ that excludes
releases due to normal operation of
equipment that is intended to vent.
The proposed rule, as well as the final
rule, allows the owner to delay repair if
a good cause exists. Although ‘‘good
cause’’ was not defined in the proposed
rule, we have added a definition in
paragraph (a) of the final rule. Also, the
final rule allows the operator up to two
years to repair a leak if good cause for
delay exists, although the operator must
submit a Sundry Notice and repair the
leak sooner than 2 years if the
opportunity arises. Previously, we had
proposed that the operator repair the
leak within 15 days after the cause for
the delay ceases to exist.
Please see Section III.A.d for a
discussion of major comments received
on this section of the proposed rule.

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Section 3179.305 Leak Detection
Inspection, Recordkeeping and
Reporting
This section requires 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 must be
made available to the BLM upon
request. AVO inspections only have to
be documented if they find a leak
requiring repair. Paragraph (b) of the
section also requires operators to submit
to the BLM, by March 31 of each
calendar year, an annual summary
report on the previous year’s LDAR
inspection activities. The BLM plans to
make these reports available to the
public, subject to any protections for
confidential business information.
The final rule amends the records that
must be maintained. The BLM did not
finalize the proposed recordkeeping
requirements regarding the equipment
or facility inspected, descriptions of
each leak, and the date of each leak
repair attempt. We clarified, however,
that AVO checks need only be
documented if they find a leak requiring
repair.
Please see Section III.A.d for a
discussion of major comments received
on this section of the proposed rule.

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Section 3179.401 State or Tribal
Requests for Variances From the
Requirements of This Subpart
This section creates a variance
procedure under which the BLM State
Director may grant a State or tribe’s
request to have a State, local or tribal
regulation apply in place of a provision
or provisions of this subpart. The
variance request must: (1) Identify the
specific provisions of the BLM
requirements for which the variance is
requested; (2) identify the specific State,
local or tribal regulation that would
substitute for the BLM requirements; (3)
explain why the variance is needed; and
(4) demonstrate how the State, local or
tribal regulation will satisfy the
purposes of the relevant BLM
provisions. The BLM State Director will
review a State or tribal variance request.
To approve a request, the BLM State
Director will determine that the State,
local or tribal regulation: (1) Would
perform at least equally well in terms of
avoiding waste of oil and gas, reducing
environmental impacts from venting
and/or flaring of gas, and ensuring the
safe and responsible production of oil
and gas, compared to the particular
provision(s) from which the State or
tribe is requesting the variance, and (2)
would be consistent with the terms of

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the affected Federal or Indian leases and
applicable statutes.
This section also clarifies that a
variance granted under this proposed
section does not constitute a variance
from provisions of regulations, laws, or
orders other than subpart 3179, and it
reserves the BLM’s authority to rescind
a variance or modify any condition of
approval in a variance. Additionally,
this section requires States or tribes
with approved variances to notify the
BLM in writing of any substantive
amendments, revisions, or other
changes to the applicable State, local or
tribal regulation(s) or rule(s). This
section further specifies that if the BLM
approves a variance for State, local or
tribal regulation(s) or rule(s), the
variance can be enforced by the BLM as
if the regulation(s) or rule(s) were
provided for in this Subpart.
In response to comments received, the
BLM made the following changes to the
proposed rule requirements: (1) Revised
paragraph (a)(1) to change a reference to
granting a variance from ‘‘any
individual provision of this subpart’’ to
‘‘any provisions of this subpart’’; (2)
revised paragraphs (a)(2)(iv) and (b) to
state that the State, local or tribal
regulations or rules would ‘‘perform at
least equally well in terms of reducing
waste of oil and gas, reducing
environmental impacts from venting
and/or flaring of gas, and ensuring the
safe and responsible production of oil
and gas, compared to the particular
provision(s) from which the State or
tribe is requesting the variance’’; (3)
added text to allow variances for
requirements and regulations of local
governments, in addition to State and
tribal requirements (though the variance
request must still come from the State
or tribe, not from a locality); (4) added
new paragraph (e) that requires the State
or tribe that requested the variance to
notify the BLM of substantive
amendments, revisions, or other
changes to the applicable State, local or
tribal regulation(s) or rule(s); and (5)
added new paragraph (f) that clarifies
that if the BLM approves a variance for
State, local or tribal regulation(s) or
rule(s), the variance can be enforced by
the BLM as if the regulation(s) or rule(s)
were provided for in this Subpart.
Paragraph (f) also clarifies that a State’s
or tribe’s enforcement of its own
regulations would not be affected by the
BLM’s approval of a variance.
Major comments received on
variances are discussed in Section
III.E.3 of this preamble; additional
comments on variances are discussed
below.
Some commenters requested that
additional entities be allowed to apply

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for variances, such as local air
authorities, multiple State agencies, or
operators. Commenters asserted that
allowing only States or tribes to request
variances causes uncertainty for
operators, and that if a State declined to
put forth a variance request, companies
would bear the cost and burden of
complying with multiple regulatory
regimes. As stated above, the BLM has
modified the rule to allow local
requirements, in addition to State and
tribal requirements, to substitute for
BLM requirements. Regarding the
comment that multiple State agencies
may need to request a variance, the final
rule does not preclude different State or
tribal agencies from requesting
variances from different provisions of
the rule. The BLM has not modified the
final rule to allow localities or
operators, in addition to States and
tribes, to request a variance to be able
to comply with State, local or tribal
requirements in lieu of the BLM
requirements. Specifically with respect
to local requirements, the BLM believes
that it is important to ensure that the
State supports a variance request, and
thus that the State prefers the BLM to
enforce the State’s or locality’s
requirements rather than federal
requirements. Additionally, we believe
that a State has the best understanding
of its own regulatory requirements and
how those compare to the requirements
of this rule.
Several commenters asserted that the
variance application and approval
processes were unclear and/or overly
burdensome. These commenters
expressed various concerns, including:
(1) Lack of a clear and comprehensive
description of the information needed to
request a variance; (2) lack of timelines
for review and approval; (3) lack of
criteria by which the BLM would
evaluate variance requests; and (4) lack
of provisions stating how the BLM will
address future modifications to either
this rule or State regulations once
variances are approved. Commenters
were also concerned about the BLM’s
ability to review variance requests in a
timely manner. To address these
concerns, comments suggested
clarifying the regulatory text as well as
developing formal implementation
guidance in consultation with the States
prior to the effective date of the rule.
In response to these comments, as
discussed in Section III.E.2 of this
preamble, the final rule provides three
specific criteria for evaluating whether
it is appropriate to apply the State, local
or tribal requirements in lieu of this
rule. In addition, the final rule added
new paragraph (e) that requires the State
or tribe that requested the variance to

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notify the BLM of substantive
amendments, revisions, or other
changes to the applicable State, local or
tribal regulation(s) or rule(s). This
requirement will ensure that the BLM is
aware of changes to State, local or tribal
regulations that may impact whether the
State, local or tribal regulation or
requirement continues to meet the
variance criteria established in the final
rule. Regarding the comments arguing
for a timeline for submittal and
processing of the variances, the BLM is
confident that it will be able to process
these requests in a timely manner that
will allow sufficient time for operators
to have a clear understanding of their
compliance requirements.
Some commenters also expressed
concern with the proposed BLM State
Director review of the variance requests.
These commenters asserted that
delegating the approval process to the
BLM State Director could result in
uneven treatment among States. The
BLM agrees that achieving consistent
implementation of the regulations is an
important goal, and this is one reason
why the BLM does not believe that
decisions on variance requests should
be made below the BLM State Director
level. Further, the BLM believes that
BLM State Directors are in a good
position to evaluate how State, local or
tribal rules or requirements compare to
the requirements of this rule, given their
familiarity with the regulatory regimes
that apply in the relevant State or States.
In addition, once the rule is in effect,
the BLM would have the opportunity to
issue guidance to enhance coordination
among State Directors in evaluating
variances, as well as with the BLM
Washington office, to help ensure
consistency across the BLM State
Offices. Finally, the more specific
criteria in the final rule for evaluating a
variance request will enhance
consistency across States.
Some commenters also opposed the
proposed provision in § 3179.401(d)
stating that the ‘‘BLM reserves the right
to rescind a variance or modify any
condition of approval.’’ These
commenters asserted that such a
proposal undermines certainty for
operators and discourages States and
tribes from seeking a variance. Other
commenters requested that the BLM
include an appeals process for revoked
or denied variances, stating that if a
variance were requested and denied,
States would have no administrative
means by which to address the BLM
decision without going to court.
The BLM believes that maintaining
BLM authority to rescind a variance or
modify any condition of approval is
necessary to guard against situations in

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which a variance leads to unintended or
unforeseen consequences that run
counter to the BLM’s determination that
the State, local, or tribal regulation
performs at least as well as the BLM
rule. The BLM expects that such
situations will arise infrequently, but
the BLM nevertheless believes it is
important to include a mechanism for
addressing such situations as they
occur. After considering the comments,
the BLM determined that consideration
of waste reduction, environmental, and
safety interests outweighs commenters’
concerns. As a result, the final rule
maintains the BLM’s discretion to
rescind a variance or modify any
condition of approval. Regarding the
comments requesting that the BLM
include an appeals process for revoked
or denied variances, the BLM did not
provide for administrative appeals on
similar variance decisions under the
hydraulic fracturing rule, and the BLM
is maintaining this practice in this final
rule. Applying this approach also helps
to avoid a protracted appeals process
with respect to State and tribal
variances.
VIII. Analysis of Impacts
A. Description of the Regulated Entities
1. Potentially Affected Entities
Entities that will be directly affected
by the rule 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.155 We believe that these 1,828
entities will be most affected by the
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’’
According to 2014 data from the U.S.
Census Bureau, there were 6,532 entities
directly involved in extraction of oil and
gas in the United States, 2,121 entities
involved in the drilling of wells, and
8,577 entities providing other support
155 The actual number is expected to be slightly
lower due to duplicate entries.

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functions.156 Therefore, the
approximately 17,000 entities associated
with developing, and producing of
domestic oil and gas 157 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.158 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 1,250 employees. For entities
drilling oil and gas wells, the threshold
is 1,000 employees. For entities
involved in support activities, the
standard is annual receipts of less than
$38.5 million Table 9–3a in the RIA
displays the number of establishments
in the oil and gas sector using a 1,000
employee cutoff. This table shows that
over 99% of the establishments
involved in oil and gas extraction and
the drilling of oil and gas wells are
classified as small.
To estimate a percentage of small
firms involved in oil and gas support
activities, we reference Table 9–3d 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 firms
providing oil and gas support activities
in 2007, about 97 percent had annual
receipts of less than $35 million and are
classified as small.159
B. Impacts of the Requirements
1. Overall Costs of the Rule
Overall, the BLM estimates that this
rule will pose costs of about $114–279
million per year (with capital costs
annualized using a 7% discount rate) or
$110–275 million per year (with capital
costs annualized using a 3% discount
rate).160 These costs include engineering
compliance costs and the social cost of
minor additions of carbon dioxide to the
156 RIA

at 122.
Census Bureau data does not readily
differentiate between the number of firms involved
in oil development and production activities versus
gas development and production.
158 13 CFR 121.201.
159 U.S. Census Bureau does not provide receipt
data that allow a break at the $38.5 million
threshold as defined by SBA. As such, the 97
percent figure is a slight underestimate.
160 RIA at 4.
157 U.S.

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atmosphere.161 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). 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 rule, the above
estimates overstate the likely impacts of
the rule.

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2. Overall Benefits of the Rule
The benefits of the rule include the
additional production of resources from
Federal and Indian leases; reductions in
venting, flaring, and leaks of gas,
including GHG emissions; and
increased opportunities for royalties.
We measure the benefits of the rule as
the cost savings that the industry will
receive from the recovery and sale of
natural gas and the projected
environmental benefits of reducing the
amount of GHG pollution released into
the atmosphere. As with the estimated
costs, we expect benefits on an annual
basis.
The BLM estimates that this rule
would result in monetized benefits of
$209–403 million per year (calculating
the monetized emissions reductions
using model averages of the social cost
of methane with a 3 percent discount
rate).162 We estimate that the rule would
reduce methane emissions by 175,000–
180,000 tpy, which we estimate to be
worth $189–247 million per year (this
social benefit is included in the
monetized benefit above). We estimate
that the rule would reduce VOC
emissions by 250,000–267,000 (this
benefit is not monetized in our
calculations).163 Overall, we predict the
rule will reduce methane emissions by
35% from the 2014 estimates and
reduce the flaring of associated gas by
49%, when the capture requirements are
fully phased in.164
The 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.
161 Some gas that would have otherwise been
vented would now be combusted on-site or
downstream to generate electricity. The estimated
value of the carbon additions do not exceed $30,000
in any given year.
162 RIA at 5.
163 RIA at 106.
164 Id.

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3. Net Benefits of the Rule
Overall, the BLM estimates that the
benefits of this rule outweigh its costs
by a significant margin. The BLM
expects net benefits ranging from $46–
199 million per year (capital costs
annualized using a 7% discount rate) or
$50–204 million per year (capital costs
annualized using a 3% discount rate).165
4. Distributional Impacts
a. Energy Systems
The rule has a number of
requirements that are expected to
influence the production of natural gas
and crude oil from onshore Federal and
Indian oil and gas leases. We estimate
the following incremental changes in
production, noting the representative
share of the total U.S. production in
2015 for context. We estimate additional
natural gas production ranging from 9–
41 Bcf per year (representing 0.03–0.15
percent of the total U.S. production) and
a reduction in crude oil production
ranging from 0.0–3.2 million bbl per
year (representing 0–0.07 percent of the
total U.S. production).166 Separate from
the volumes listed above, we also expect
0.8 Bcf of gas to be combusted on-site
that would have otherwise been vented.
Since the relative changes in production
are expected to be small, we do not
expect that the rule would significantly
impact the price, supply, or distribution
of energy.
b. Royalties
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. We
estimate that the rule will result in
additional royalties of $3–13 million per
year.167
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
165 RIA

at 6. The highs and lows of the benefits
and costs do not occur during the same years;
therefore, the net benefit ranges presented here do
not calculate simply as the range of benefits minus
the range of costs presented above.
166 RIA at 7.
167 RIA at 8.

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economic analysis of the benefits and
costs of a regulation, they may be
important for describing distributional
effects.
c. Small Businesses
The BLM identified up to 1,828
entities that currently operate Federal
and Indian leases. The vast majority of
these entities are small businesses, 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 the RIA. 168
Recognizing that the SBA defines a
small business for oil and gas producers
as one with fewer than 1,250 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 169 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 midpoint of the
low and high average per-entity cost
increase figures, or $55,200, recognizing
that this figure includes compliance
costs (annualized using a 7% discount
rate) and cost savings. For these 26
small companies, a per-entity
compliance cost increase of $55,200
would result in an average reduction in
profit margin of 0.15 percentage points
(based on the 2014 company data). The
full detail of this calculation is available
in the RIA.170
d. Employment
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.’’ 171 An analysis of
employment impacts is a standalone
analysis and the impacts should not be
included in the estimation of benefits
and costs.
168 The BLM conducted a Final Regulatory
Flexibility Analysis, RIA at 123–136.
169 The profit margin was calculated by dividing
the net income by the total revenue as reported in
the companies’ 10–K filings.
170 RIA at 129.
171 Executive Order 13563, Improving Regulation
and Regulatory Review (Jan. 18, 2011).

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The rule is not expected to materially
impact employment within the oil and
gas extraction, drilling, and support
industries.172 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 rule
would not alter the investment or
employment decisions of firms or
significantly adversely impact
employment.
The requirements would require the
one-time installation or replacement of
equipment and the ongoing
implementation of an LDAR program,
and labor would be necessary to comply
with each of these. The Supporting
Statement for the Paperwork Reduction
Act describes the labor requirements
posed by the rule.
e. Impacts on Tribal Lands
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.173
We estimate that the rule’s operation on
Indian lands would pose costs ranging
from $15–$39 million per year (using a
7% discount rate to annualize capital
costs) or $14–$39 million per year
(using a 3% discount rate to annualize
capital costs).174 Projected benefits from
the rule’s operation on Indian lands
range from $3–$23 million per year
(using model averages of the social cost
of methane with a 3 percent discount
rate).175 Net benefits from operation of
the rule on leases on Indian lands range
from $3–$25 million per year (with
capital costs annualized using 7% and
3% discount rates).176
For impacts on production from
leases on Indian lands, the rule is
projected to result in additional natural
gas production ranging from 1.1–5.8 Bcf
per year and a reduction in crude oil
production ranging from 0–320,000 bbl
per year.177 We further estimate that the
rule would reduce methane emissions
from leases on Indian lands by 22,000
tpy, and would reduce VOC emissions

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172 RIA

at 118.
at 118–120.
174 RIA at 118.
175 RIA at 119.
176 RIA at 119. The highs and lows of the benefits
and costs do not occur during the same years;
therefore, the net benefit ranges presented here do
not calculate simply as the range of benefits minus
the range of costs presented above.
177 Id.
173 RIA

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by 30,000–32,000 tpy.178 We estimate
additional royalties from leases on
Indian lands of $0.3–1.9 million per
year.179
IX. Procedural Matters
A. Executive Order 12866, Regulatory
Planning and Review 180
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.
After reviewing the requirements, the
BLM has determined that the rule is an
economically significant regulatory
action according to the criteria of
Executive Order 12866, and we have
prepared a regulatory impact analysis
for the rule.
B. Regulatory Flexibility Act and Small
Business Regulatory Enforcement
Fairness Act of 1996 181
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.182
Congress enacted the RFA to ensure that
government regulations do not
unnecessarily or disproportionately
burden small entities. Small entities
include small businesses, small
178 Id.
179 RIA

at 120.
at 138.
181 RIA at 167–168.
182 5 U.S.C. 601–612. The exception is found in
5 U.S.C. 605(b).
180 RIA

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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
will likely affect a substantial number of
small entities. The BLM believes,
however, that the final rule will not
have a significant economic impact on
a substantial number of small entities.
Although the rule will affect a
substantial number of small entities, the
BLM does not believe that these effects
would be economically significant. 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 chose to prepare an Initial
Regulatory Flexibility Analysis and
Final Regulatory Flexibility Analysis for
this rule. Due to the fact that the rule is
economically significant and impacts a
substantial number of small entities, the
BLM believes it is prudent, and
potentially helpful to small entities, to
provide an IRFA and FRFA for the
rulemaking. We do not believe this
decision should be viewed as a
precedent for other rulemakings.
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 final 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 final rule is also
not subject to the requirements of
Section 205 of UMRA.
This final 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

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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
final rule would not have significant
takings implications. A takings
implication assessment is not required.
The final rule would establish a limited
set of standards 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 final rule is
consistent with the terms of those
Federal leases and is authorized by
applicable statutes. Thus, the final 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 final 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 final
rule does not have sufficient Federalism
implications to warrant preparation of a
Federalism Assessment.

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F. Executive Order 12988, Civil Justice
Reform
This final 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.

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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 will
not have substantial direct effects on
federally recognized Indian tribes.
Nevertheless, on a government-togovernment basis we initiated
consultation with tribal governments
that the final 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).183 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. 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.
After the proposed rule published on
February 8, 2016, the BLM conducted
another round of outreach meetings,
with the tribal sessions taking place in
the morning, and the general-public
sessions taking place in the afternoon,
with a conference call-in number for the
public to listen in remotely. These
meetings were held at four locations:
Farmington, New Mexico (February 16,
2016), Oklahoma City, Oklahoma
(February 18, 2016), Denver, Colorado
(March 1, 2016), and Dickinson, North
Dakota (March 3, 2016).
H. Paperwork Reduction Act
1. Overview
The Paperwork Reduction Act
(PRA) 184 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 OMB control number.
Collections of information include
requests and requirements that an
individual, partnership, or corporation
obtain information, and report it to a
Federal agency. See 44 U.S.C. 3502(3);
5 CFR 1320.3(c) and (k).
This rule contains information
collection activities that require
183 More

info can be found at: http://
www.blm.gov/wo/st/en/prog/energy/public_events_
on_oil.html.
184 44 U.S.C. 3501–3521.

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approval by the OMB under the PRA.
The BLM included an information
collection request in the proposed rule.
OMB has approved the information
collection for the final rule under
control number 1004–0211.
2. Summary of Information Collection
Requirements
• Title: Waste Prevention, Production
Subject to Royalties, and Resource
Conservation (43 CFR parts 3160 and
3170).
• Forms: Form 3160–3, Application
for Permit to Drill or Reenter; and Form
3160–5, Sundry Notices and Reports on
Wells.
• OMB Control Number: 1004–0211.
• 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 those who 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 rule updates
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 Number of Responses:
63,200.
• Estimated Total Annual Burden
Hours: 82,170 hours.
• Estimated Total Non-Hour Cost:
None.
3. Discussion of Regulations
Except for the recordkeeping required
by 43 CFR 3179.305, the informationcollection activities in the final rule
involve new uses and burdens for BLM
Forms 3160–3 and 3160–5, the use of
which has been cleared by OMB under
control number 1004–0137, Onshore Oil
and Gas Operations (43 CFR part 3160)
(expiration date January 31, 2018). After
this rule goes into effect, the BLM plans
to request that OMB merge the new uses
and burdens of Forms 3160–3 and
3160–5 with control number 1004–0137.
The information collection activities
in this 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 information
collection.
Plan to Minimize Waste of Natural Gas
(43 CFR 3162.3–1)
This rule adds a new provision to 43
CFR 3162.3–1 that requires a plan to

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minimize waste of natural gas when
submitting an APD for a development
oil well. This information is 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).
Request for Approval for Royalty-Free
Uses On-Lease or Off-Lease (43 CFR
3178.5, 3178.7, 3178.8, and 3178.9)
Section 3178.5 requires submission of
a Sundry Notice (Form 3160–5) to
request prior written BLM approval for
use of gas royalty-free for the following
operations and production purposes on
the lease, unit or communitized area:
• Using oil or gas that an operator
removes from the pipeline at a location
downstream of the facility measurement
point (FMP);
• Removal of gas initially from a
lease, unit PA, or communitized area for
treatment or processing because of
particular physical characteristics of the
gas, prior to use on the lease, unit PA
or communitized area; and
• 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.
Section 3178.7 requires submission of
a Sundry Notice (Form 3160–5) 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 communitized area for
engineering, economic, resourceprotection, or physical-accessibility
reasons; and
• The operations are conducted
upstream of the FMP.
Section 3178.9 requires the following
additional information in a request for
prior approval of royalty-free use under
section 3178.5, or for prior approval of
off-lease royalty-free use under section
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 volume of oil or gas that the
operator expects will be used in the
operation and the method of measuring
or estimating that volume;
• 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

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through use of a gas-activated
pneumatic controller, returned to the
reservoir, or some other disposition).
Notification of Choice To Comply on
County- or State-Wide Basis (43 CFR
3179.7(c)(3)(ii))
Section 3179.7 requires operators
flaring gas from development oil wells
to capture a specified percentage of the
operator’s adjusted volume of gas
produced over the relevant area. The
‘‘relevant area’’ is each of the operator’s
leases, units, or communitized areas,
unless the operator chooses to comply
on a county- or State-wide basis and the
operator notifies the BLM of its choice
by Sundry Notice by January 1 of the
relevant year.
Request for Approval of Alternative
Capture Requirement (43 CFR 3179.8(b))
Section 3179.8 applies only to leases
issued before the effective date of the
final rule and to operators choosing to
comply with the capture requirement in
section 3179.7 on a lease-by-lease, unitby-unit, or communitized area-bycommunitized area basis. The regulation
provides that operators who meet those
parameters may seek BLM approval of a
capture percentage other than that
which is applicable under 43 CFR
3179.7. The operator must submit a
Sundry Notice that includes the
following information:
• The name, number, and location of
each of the operator’s wells, and the
number of the lease, unit, or
communitized area with which it is
associated;
• The oil and gas production levels of
each of the operator’s wells on the lease,
unit, or communitized area for the most
recent production month for which
information is available and the
volumes being vented and flared from
each well;
In addition, the request must include
map(s) showing:
• The entire lease, unit, or
communitized area, 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;
• 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;
• 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

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• Identification of all of the operator’s
wells within the lease from which gas
is captured;
The following information is also
required:
• Data that show pipeline capacity
and the operator’s projections of the cost
associated with installation and
operation of gas capture infrastructure,
to the extent that the operator is able to
obtain this information, as well as cost
projections for alternative methods of
transportation that do not require
pipelines; and
• Projected costs of and the combined
stream of revenues from both gas and oil
production, including:
Æ 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
communitized area, whichever is less;
and
Æ 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 next 15 years
or the life of the operator’s lease, unit,
or communitized area, whichever is
less.
Request for Exemption From Well
Completion Requirements (43 CFR
3179.102(c) and (d))
Section 3179.102 lists several
requirements pertaining to gas that
reaches the surface during well
completion and related operations. An
operator may seek an exemption from
these requirements by submitting a
Sundry Notice that includes the
following information:
(1) The name, number, and location of
each of the operator’s wells, and the
number of the lease, unit, or
communitized area with which it is
associated;
(2) The oil and gas production levels
of each of the operator’s wells on the
lease, unit or communitized area for the
most recent production month for
which information is available;
(3) Data that show the costs of
compliance; and
(4) Projected costs of and the
combined stream of revenues from both
gas and oil production, including: the
operator’s projections of oil and gas
prices, production volumes, quality (i.e.,
heating value and H2S content),
revenues derived from production, and
royalty payments on production over
the next 15 years or the life of the
operator’s lease, unit, or communitized
area, whichever is less.

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The rule also provides that an
operator that is in compliance with the
EPA regulations for well completions
under 40 CFR part 60, subpart OOOO or
subpart OOOOa is deemed in
compliance with the requirements of
this section. As a practical matter, all
hydraulically fractured or refractured
wells are now subject to the EPA
requirements, so the BLM does not
believe that the requirements of this
section would have any independent
effect, or that any operator would
request an exemption from the
requirements of this section, as long as
the EPA requirements remain in effect.
Request for Extension of Royalty-Free
Flaring During Initial Production
Testing (43 CFR 3179.103)
Section 3179.103 allows gas to be
flared royalty-free during initial
production testing. The regulation lists
specific volume and time limits for such
testing. An operator may seek an
extension of those limits by submitting
a Sundry Notice to the BLM.

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Request for Extension of Royalty-Free
Flaring During Subsequent Well Testing
(43 CFR 3179.104)
Section 3179.104 allows gas to be
flared royalty-free for no more than 24
hours during well tests subsequent to
the initial production test. The operator
may seek authorization to flare for a
longer period by submitting a Sundry
Notice to the BLM.
Reporting of Venting or Flaring (43 CFR
3179.105)
Section 3179.105 allows an operator
to flare gas royalty-free during a
temporary, short-term, infrequent, and
unavoidable emergency. Venting gas is
permissible if flaring is not feasible
during an emergency. The regulation
defines limited circumstances that
constitute an emergency, and other
circumstances that do not constitute an
emergency. The operator must estimate
and report to the BLM on a Sundry
Notice the volumes flared or vented in
the following circumstances that, as
provided by 43 CFR 3179.105, do not
constitute emergencies for the purposes
of royalty assessment:
(1) More than 3 failures of the same
component within a single piece of
equipment within any 365-day period;
(2) The operator’s failure to install
appropriate equipment of a sufficient
capacity to accommodate the
production conditions;
(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;

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(4) Scheduled maintenance;
(5) A situation caused by operator
negligence; or
(6) A situation on a lease, unit, or
communitized area that has already
experienced 3 or more emergencies
within the past 30 days, unless the BLM
determines that the occurrence of more
than 3 emergencies within the 30 day
period could not have been anticipated
and was beyond the operator’s control.
Pneumatic Controllers—Introduction
Section 3179.201 pertains to any
pneumatic controller that: (1) Is not
subject to EPA regulations at 40 CFR
60.5360 through 60.5390, but would be
subject to those regulations if it were a
new or modified source; and (2) has a
continuous bleed rate greater than 6
standard cubic feet (scf) per hour.
Section 3179.201(b) requires operators
to replace each high-bleed pneumatic
controller with a controller with a bleed
rate lower than 6 scf per hour within 1
year of the effective date of the rule,
unless (1) the pneumatic controller
exhaust is routed to processing
equipment; (2) the pneumatic controller
exhaust was, as of the effective date of
the rule, and continues to be routed to
a flare device or low pressure
combustor; or (3) one of the following
applies:
Notification of Functional Needs for a
Pneumatic Controller (43 CFR
3179.201(b)(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 that may
include, but are not limited to, response
time, safety, and positive actuation, and
the Sundry Notice describes those
functional needs.
Showing That Cost of Compliance
Would Cause Cessation of Production
and Abandonment of Oil Reserves
(Pneumatic Controllers) (43 CFR
3179.201(b)(4) and 3175.201(c))
The operator demonstrates to the BLM
through a Sundry Notice, and the BLM
agrees, that 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.
The Sundry Notice must include the
following information:
(1) The name, number, and location of
each of the operator’s wells, and the
number of the lease, unit, or
communitized area with which it is
associated;
(2) The oil and gas production levels
of each of the operator’s wells on the

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lease, unit or communitized area for the
most recent production month for
which information is available;
(3) Data that show the costs of
compliance;
(4) Projected costs of and the
combined stream of revenues from both
gas and oil production, including: 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 communitized
area, 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 next 15 years or the
life of the operator’s lease, unit, or
communitized area, whichever is less.
Showing in Support of Replacement of
Pneumatic Controller Within 3 Years
(43 CFR 3179.201(d))
The operator may replace a high-bleed
pneumatic controller within 3 years of
the effective date of the rule (instead of
within 1 year of the effective date) if the
operator notifies the BLM through a
Sundry Notice that 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 the rule.
Pneumatic Diaphragm Pumps—
Introduction
With some exceptions, section
3179.202 pertains to any pneumatic
diaphragm pump that: (1) Uses natural
gas produced from a Federal or Indian
lease, or from a unit or communitized
area that includes a Federal or Indian
lease; and (2) Is not subject to EPA
regulations at 40 CFR 60.5360 through
60.5390, but would be subject to those
regulations if it were a new or modified
source. This regulation generally
requires replacement of such a pump
with a zero-emissions pump or routing
of the pump’s exhaust gas to processing
equipment for capture and sale within
1 year of the effective date of the final
rule.
This requirement does not apply to
pneumatic diaphragm pumps that do
not vent exhaust gas to the atmosphere.
In addition, this requirement does not
apply if one of the following applies:
Showing That a Pneumatic Diaphragm
Pump Was Operated on Fewer Than 90
Individual Days in the Prior Calendar
Year (43 CFR 3179.202(b)(2))
A pneumatic diaphragm pump is not
subject to section 3179.202 if the

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operator documents in a Sundry Notice
that the pump was operated fewer than
90 days in the prior calendar year.

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Notification of Functional Needs for a
Pneumatic Diaphragm Pump (43 CFR
3179.202(d))
In lieu of replacing a pneumatic
diaphragm pump or routing the pump
exhaust gas to processing equipment, an
operator may submit a Sundry Notice to
the BLM showing that replacing the
pump with a zero emissions pump is
not viable because a pneumatic pump is
necessary to perform the function
required, and that routing the pump
exhaust gas to processing equipment for
capture and sale is technically infeasible
or unduly costly.
Showing That Cost of Compliance
Would Cause Cessation of Production
and Abandonment of Oil Reserves
(Pneumatic Diaphragm Pumps) (43 CFR
3179.202(f) and (g))
An operator may be exempted from
the replacement requirement if the
operator submits a Sundry Notice to the
BLM that provides an economic analysis
that demonstrates, and the BLM agrees,
that compliance with these
requirements would impose such costs
as to cause the operator to cease
production and abandon significant
recoverable oil reserves under the lease.
The Sundry Notice must include the
following information:
(1) Well information that must
include: (i) The name, number, and
location of each well, and the number
of the lease, unit, or communitized area
with which it is associated; and (ii) The
oil and gas production levels of each of
the operator’s wells on the lease, unit or
communitized area for the most recent
production month for which
information is available;
(2) Data that show the costs of
compliance with paragraphs (c) through
(e) of § 3179.202; and
(3) The operator’s estimate of the costs
and revenues of the combined stream of
revenues from both the gas and oil
components, including: (i) 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 communitized
area, whichever is less; and (ii) 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 next 15 years or the
life of the operator’s lease, unit, or
communitized area, whichever is less.

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Showing in Support of Replacement of
Pneumatic Diaphragm Pump Within 3
Years (43 CFR 3179.202(h))
The operator may replace a pneumatic
diaphragm pump within 3 years of the
effective date of the rule (instead of
within 1 year of the effective date) if the
operator notifies the BLM through a
Sundry Notice that 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 the rule.
Storage Vessels (43 CFR 3179.203(c))
A storage vessel is subject to 43 CFR
3179.203(c) if the vessel: (1) Contains
production from a Federal or Indian
lease, or from a unit or communitized
area that includes a Federal or Indian
lease; and (2) Is not subject to any of the
requirements of EPA regulations at 40
CFR part 60, subpart OOOO, but would
be subject to that subpart if it were a
new or modified source.
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, the operator must
determine, record, and make available
to the BLM upon request, whether the
storage vessel has the potential for VOC
emissions equal to or greater than 6 tpy
based on the maximum average daily
throughput for a 30-day period of
production. The determination may take
into account requirements under a
legally and practically enforceable limit
in an operating permit or other
requirement established under a federal,
state, local or tribal authority that limit
the VOC emissions to less than 6 tpy.
If a storage vessel has the potential for
VOC emissions equal to or greater than
6 tpy, no later than 1 year after the
effective date of this section, or 3 years
if the operator must and will replace the
storage vessel at issue in order to
comply with the requirements of this
section, the operator must:
(1) Route all tank vapor gas from the
storage vessel to a sales line;
(2) If the operator determines that
compliance with paragraph (c)(1) of this
section is technically infeasible or
unduly costly, route all tank vapor gas
from the storage vessel to a device or
method that ensures continuous
combustion of the tank vapor gas; or
(3) Submit an economic analysis to
the BLM through a Sundry Notice that
demonstrates, and the BLM agrees,
based on the information identified in
paragraph (d) of this section, that
compliance with paragraph (c)(2) of this
section would impose such costs as to
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease.

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To support the demonstration
described above, the operator must
submit a Sundry Notice that includes
the following information:
(1) The name, number, and location of
each well, and the number of the lease,
unit, or communitized area with which
it is associated;
(2) The oil and gas production levels
of each of the operator’s wells on the
lease, unit or communitized area for the
most recent production month for
which information is available;
(3) Data that show the costs of
compliance with paragraph (c)(1) or
(c)(2) of this section on the lease; and
(4) The operator must consider the
costs and revenues of the combined
stream of revenues from both the gas
and oil components, including: The
operator’s projections of oil and gas
prices, production volumes, quality (i.e.,
heating value and H2S content),
revenues derived from production, and
royalty payments on production over
the next 15 years or the life of the
operator’s lease, unit, or communitized
area, whichever is less.
Downhole Well Maintenance and
Liquids Unloading—Documentation and
Reporting (43 CFR 3179.204(c) and (e))
The operator must minimize vented
gas and the need for well venting
associated with downhole well
maintenance and liquids unloading,
consistent with safe operations. Before
the operator manually purges a well for
liquids unloading for the first time after
the effective date of this section, the
operator must consider other methods
for liquids unloading and determine
that they are technically infeasible or
unduly costly. The operator must
provide information supporting that
determination as part of a Sundry
Notice within 30 calendar days after the
first liquids unloading event by manual
or automated well purging conducted
after the effective date of this section.
This requirement applies to each well
the operator operates.
For any liquids unloading by manual
well purging, the operator must:
(1) Ensure that the person conducting
the well purging remains present on-site
throughout the event to minimize to the
maximum extent practicable any
venting to the atmosphere;
(2) Record the cause, date, time,
duration, and estimated volume of each
venting event; and
(3) Maintain the records for the period
required under § 3162.4–1 and make
them available to the BLM, upon
request.

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Federal Register / Vol. 81, No. 223 / Friday, November 18, 2016 / Rules and Regulations
Downhole Well Maintenance and
Liquids Unloading—Notification of
Excessive Duration or Volume (43 CFR
3179.204(f))
The operator must notify the BLM by
Sundry Notice, within 30 calendar days,
if:
(1) The cumulative duration of
manual 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 manual
well purging operations for a well
exceeds 75 Mcf during any production
month.
Leak Detection—Compliance With EPA
Regulations (43 CFR 3179.301(j))
Sections 3179.301 through 3179.305
include information collection activities
pertaining to the detection and repair of
gas leaks during production operations.
These regulations require operators to
inspect all equipment covered under
§ 3179.301(a) for gas leaks. Section
3179.301(k) allows an operator to satisfy
the requirements of §§ 3179.301 through
3179.305 for all of the equipment on a
given lease by notifying the BLM in a
Sundry Notice that the operator is
applying the EPA subpart OOOOa
fugitive emissions requirements to such
equipment.

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Leak Detection—Request To Use an
Alternative Monitoring Device and
Protocol (43 CFR 3179.302(c))
Section 3175.302 specifies the
instruments and methods that an
operator may use to detect leaks.
Section 3175.302(d) allows the BLM to
approve an alternative monitoring
device and associated inspection
protocol if the BLM finds that the
alternative would achieve equal or
greater reduction of gas lost through
leaks compared with the approach
specified in § 3179.302(a)(1) when used
according to § 3179.303(a).
Any person may request approval of
an alternative monitoring device and
protocol by submitting a Sundry Notice
to BLM that includes the following
information: (1) Specifications of the
proposed monitoring device, including
a detection limit capable of supporting
the desired function; (2) The proposed
monitoring protocol using the proposed
monitoring device, including how
results will be recorded; (3) Records and
data from laboratory and field testing,
including but not limited to
performance testing; (4) A
demonstration that the proposed
monitoring device and protocol will
achieve equal or greater reduction of gas
lost through leaks compared with the

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approach specified in the regulations;
(5) Tracking and documentation
procedures; and (6) Proposed
limitations on the types of sites or other
conditions on deploying the device and
the protocol to achieve the
demonstrated results.
Leak Detection—Operator Request To
Use an Alternative Leak Detection
Program (43 CFR 3179.303(b))
Section 3179.303(b) allows an
operator to submit a Sundry Notice
requesting authorization to detect gas
leaks using an alternative instrumentbased leak detection program, different
from the specified requirement to
inspect each site semi-annually using an
approved monitoring device.
To obtain approval for an alternative
leak detection program, the operator
must submit a Sundry Notice that
includes the following information:
(1) A detailed description of the
alternative leak detection program,
including how it will use one or more
of the instruments specified in or
approved under § 3179.302(a) and an
identification of the specific
instruments, methods and/or practices
that would substitute for specific
elements of the approach specified in
§§ 3179.302(a) and 3179.303(a);
(2) The proposed monitoring protocol;
(3) Records and data from laboratory
and field testing, including, but not
limited to, performance testing, to the
extent relevant;
(4) A demonstration that the proposed
alternative leak detection program will
achieve equal or greater reduction of gas
lost through leaks compared to
compliance with the requirements
specified in §§ 3179.302(a) and
3179.303(a);
(5) A detailed description of how the
operator will track and document its
procedures, leaks found, and leaks
repaired; and
(6) Proposed limitations on types of
sites or other conditions on deployment
of the alternative leak detection
program.
Leak Detection—Operator Request for
Exemption Allowing Use of an
Alternative Leak-Detection Program
That Does Not Meet Specified Criteria
(43 CFR 3179.303(d))
An operator may seek authorization
for an alternative leak detection program
that does not achieve equal or greater
reduction of gas lost through leaks
compared to the required approach, if
the operator demonstrates that
compliance with the leak-detection
regulations (including the option for an
alternative program under 43 CFR
3179.303(b)) would impose such costs

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83075

as to cause the operator to cease
production and abandon significant
recoverable oil or gas reserves under the
lease. The BLM may approve an
alternative leak detection program that
does not achieve equal or greater
reduction of gas lost through leaks, but
is as effective as possible consistent
with not causing the operator to cease
production and abandon significant
recoverable oil or gas reserves under the
lease.
To obtain approval for an alternative
program under this provision, the
operator must submit a Sundry Notice
that includes the following information:
(1) The name, number, and location of
each well, and the number of the lease,
unit, or communitized area with which
it is associated;
(2) The oil and gas production levels
of each of the operator’s wells on the
lease, unit or communitized area for the
most recent production month for
which information is available;
(3) Data that show the costs of
compliance on the lease with the
requirements of §§ 3179.301–305 and
with an alternative leak detection
program that meets the requirements of
§ 3179.303(b);
(4) The operator must consider the
costs and revenues of the combined
stream of revenues from both the gas
and oil components and provide the
operator’s projections of oil and gas
prices, production volumes, quality (i.e.,
heating value and H2S content),
revenues derived from production, and
royalty payments on production over
the next 15 years or the life of the
operator’s lease, unit, or communitized
area, whichever is less;
(5) The information required to obtain
approval of an alternative program
under § 3179.303(b), except that the
estimated volume of gas that will be lost
through leaks under the alternative
program must be compared to the
volume of gas lost under the required
program, but does not have to be shown
to be at least equivalent.
Leak Detection—Notification of Delay in
Repairing Leaks (43 CFR 3179.304(a))
Section 3179.304(a) requires an
operator to repair any leak no later than
30 calendar days after discovery of the
leak, unless there is good cause for
delay in repair. If there is good cause for
a delay beyond 30 calendar days,
section 3179.304(b) requires the
operator to submit a Sundry Notice
notifying the BLM of the cause.

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Leak Detection—Inspection
Recordkeeping and Reporting (43 CFR
3179.305)
Section 3179.305 requires operators to
maintain the following records and
make them available to the BLM upon
request: (1) For each inspection required
under § 3179.303, documentation of the
date of the inspection and the site where
the inspection was conducted; (2) The
monitoring method(s) used to determine
the presence of leaks; (3) A list of leak
components on which leaks were found;
(4) The date each leak was repaired; and
(5) The date and result of the follow-up
inspection(s) required under § 3179.304.
By March 31 each calendar year, the
operator must provide to the BLM an
annual summary report on the previous
year’s inspection activities that

includes: (1) The number of sites
inspected; (2) The total number of leaks
identified, categorized by the type of
component; (3) The total number of
leaks repaired; (4) The total number of
leaks that were not repaired as of
December 31 of the previous calendar
year due to good cause and an estimated
date of repair for each leak; and (5) A
certification by a responsible officer that
the information in the report is true and
accurate.
Leak Detection—Annual Reporting of
Inspections (43 CFR 3179.305(b))
By March 31 each calendar year, the
operator must provide to the BLM an
annual summary report on the previous
year’s inspection activities that
includes:
(1) The number of sites inspected;

(2) The total number of leaks
identified, categorized by the type of
component;
(3) The total number of leaks repaired;
(4) The total number leaks that were
not repaired as of December 31 of the
previous calendar year due to good
cause and an estimated date of repair for
each leak.
(5) A certification by a responsible
officer that the information in the report
is true and accurate to the best of the
officer’s knowledge.
4. 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.

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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 ...............................
Request for Approval for Royalty-Free Uses On-Lease or Off-Lease, 43 CFR 3178.5, 3178.7,
3178.8, and 3178.9, Form 3160–5 ..........................................................................................
Notification of Choice to Comply on County- or State-wide Basis, 43 CFR 3179.7(c)(3)(iii) .....
Request for Approval of Alternative Capture Requirement, 43 CFR 3179.8(b), Form 3160–5 ..
Request for Exemption from Well Completion Requirements, 43 CFR 3179.102(c) and (d),
Form 3160–5 ............................................................................................................................
Request for Extension of Royalty-Free Flaring During Initial Production Testing, 43 CFR
3179.103, Form 3160–5 ...........................................................................................................
Request for Extension of Royalty-Free Flaring During Subsequent Well Testing, 43 CFR
3179.104, Form 3160–5 ...........................................................................................................
Reporting of Venting or Flaring, 43 CFR 3179.105, Form 3160–5 ............................................
Notification of Functional Needs for a Pneumatic Controller, 43 CFR 3179.201(b)(1), Form
3160–5 .....................................................................................................................................
Showing that Cost of Compliance Would Cause Cessation of Production and Abandonment
of Oil Reserves, 43 CFR 3179.201(b)(4) and 3179.201(c), Form 3160–5 .............................
Showing in Support of Replacement of Pneumatic Controller within 3 Years, 43 CFR
3179.201(d), Form 3160–5 ......................................................................................................
Showing that a Pneumatic Diaphragm Pump was Operated on Fewer than 90 Individual
Days in the Prior Calendar Year, 43 CFR 3179.202(b)(2), Form 3160–5 ..............................
Notification of Functional Needs for a Pneumatic Diaphragm Pump, 43 CFR 3179.202(d),
Form 3160–5 ............................................................................................................................
Showing that Cost of Compliance Would Cause Cessation of Production and Abandonment
of Oil Reserves, 43 CFR 3179.202(f) and (g), Form 3160–5 .................................................
Showing in Support of Replacement of Pneumatic Diaphragm Pump within 3 Years, 43 CFR
3179.202(h), Form 3160–5 ......................................................................................................
Storage Vessels, 43 CFR 3179.203(c), Form 3160–5 ................................................................
Downhole Well Maintenance and Liquids Unloading—Documentation and Reporting, 43 CFR
3179.204(c) and (e), Form 3160–5 ..........................................................................................
Downhole Well Maintenance and Liquids Unloading—Notification of Excessive Duration or
Volume, 43 CFR 3179.204(f), Form 3160–5 ...........................................................................
Leak Detection—Compliance with EPA Regulations, 43 CFR 3179.301(j), Form 3160–5 ........
Leak Detection—Request to Use an Alternative Monitoring Device and Protocol, 43 CFR
3179.302(c), Form 3160–5 ......................................................................................................
Leak Detection—Operator Request to Use an Alternative Leak Detection Program, 43 CFR
3179.303(b), Form 3160–5 ......................................................................................................
Leak Detection—Operator Request for Exemption Allowing Use of an Alternative Leak-Detection Program that Does Not Meet Specified Criteria, 43 CFR 3179.303(d), Form 3160–5 ....
Leak Detection—Notification of Delay in Repairing Leaks, 43 CFR 3179.304(a), Form 3160–5
Leak Detection—Inspection Recordkeeping and Reporting, 43 CFR 3179.305 ........................
Leak Detection—Annual Reporting of Inspections, 43 CFR 3179.305(b), Form 3160–5 ..........
Totals ....................................................................................................................................

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2,000

8

16,000

50
200
50

4
1
16

200
200
800

0

0

0

500

2

1,000

5
250

2
2

10
500

10

2

20

50

4

200

100

1

100

100

1

100

150

1

150

10

4

40

100
50

1
4

100
200

5,000

1

5,000

250
50

1
4

250
200

5

40

200

20

40

800

150
100
52,000
2,000
63,200

20
1
.25
20
........................

3,000
100
13,000
40,000
82,170

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Federal Register / Vol. 81, No. 223 / Friday, November 18, 2016 / Rules and Regulations
I. National Environmental Policy Act
The BLM 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’’
under Section 102(2)(C) of the National
Environmental Policy Act (NEPA). This
EA was posted for public comment for
a period of 75 days, from February 8
through April 22, 2016. During the
public comment period for the proposed
rule and draft EA, BLM received
comments that further informed the
analysis of the potential environmental
impacts of the rule. In response to these
comments, BLM incorporated changes
in the final EA, which will be released
concomitantly with the rule.
The BLM believes that the 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 rule would reduce light
pollution and other impacts from
flaring. These reductions would
contribute to a more robust
environmental quality overall. BLM has
determined that the rule may also have
a certain degree of adverse
environmental impacts, primarily due to
land disturbance from increased or
accelerated construction of gas gathering
lines or pipelines and compressors and/
or increased truck traffic on existing
disturbed surfaces from the increased
use of mobile capture technology. After
careful consideration of the impacts and
alternatives discussed in the final EA,
BLM has determined that this action
does not meet the criteria of significance
under 40 CFR 1508.27 either in terms of
context or intensity; therefore, BLM
finds that the promulgation of the rule
has no significant impact.

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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

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‘‘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, the incremental production
of gas estimated to result from the rule’s
enactment constitutes 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
final rule will 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. 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 final rule in a manner consistent
with these requirements.
X. 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.

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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 record keeping
requirements; Royalty-free use; Venting.
Dated: November 14, 2016.
Amanda Leiter,
Acting Assistant Secretary, Land and
Minerals Management.

43 CFR Chapter II
For the reasons set out in the
preamble, the Bureau of Land
Management amends 43 CFR parts 3100,
3160 and 3170 as follows:
PART 3100—ONSHORE OIL AND GAS
LEASING
1. Amend 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.
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
January 17, 2017, the rate prescribed in
the lease or in applicable regulations at
the time of lease issuance;
(2) For leases issued January 17, 2017:
(i) 121⁄2 percent on all noncompetitive
leases;
(ii) A 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 of this
title;

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(3) 162⁄3 percent on noncompetitive
leases reinstated under § 3108.2–3 of
this title plus an additional 2
percentage-point increase added for
each succeeding reinstatement;
(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. 226c) 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
from the gas stream. Applications for
the right to extract helium from the gas
stream will be made under part 16 of
this title.
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.

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*

*
*
*
*
(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 and flaring, and must
explain how the operator plans to
capture associated gas upon the start of
oil production, or as soon thereafter as
reasonably possible, including an
explanation of why any delay in capture
of the associated gas would be required.
Failure to submit a complete and
adequate waste minimization plan is
grounds for denying or disapproving an
Application for Permit to Drill. The

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waste minimization plan must include
the following information:
(1) The anticipated completion date of
the proposed well(s);
(2) 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.
(3) 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;
(4) Identification of a gas pipeline to
which the operator plans to connect,
with sufficient capacity to accommodate
the anticipated production of the
proposed well(s), and information on
the pipeline, including, to the extent
that the operator can obtain it, the
following information:
(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; and
(v) Any plans known to the operator
for expansion of pipeline capacity for
the area that includes the proposed
well; and
(5) If an operator cannot identify a gas
pipeline with sufficient capacity to
accommodate the anticipated
production of the proposed well(s), the
waste minimization plan must also
include:
(i) 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
trunklines within 20 miles of the well.
The map should also contain:
(A) 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;
(B) The location and name of the
operator of each gas trunkline within 20
miles of the proposed well;

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(C) The proposed route and tie-in
point that connects or could connect the
subject well to an existing gas trunkline;
(ii) The total volume of produced gas,
and percentage of total produced gas,
that 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
(iii) A detailed evaluation, including
estimates of costs and returns, of
opportunities for on-site capture
approaches, such as compression or
liquefaction of natural gas, removal of
natural gas liquids, or generation of
electricity from gas.
PART 3170—ONSHORE OIL AND GAS
PRODUCTION
6. The authority citation for part 3170
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, 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
communitized area that do not require
prior written BLM approval for royaltyfree treatment of volumes used.
3178.5 Uses of oil or gas on a lease, unit,
or communitized area 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 communitized area 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 communitized area that
require prior written approval for
royalty-free treatment of volumes used.
3178.8 Measurement or estimation of
volumes of oil or gas that are used
royalty-free.
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
3179.1 Purpose.
3179.2 Scope.
3179.3 Definitions and acronyms.
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 Venting prohibition.
3179.7 Gas capture requirement.
3179.8 Alternative limits on venting and
flaring.
3179.9 Measuring and reporting volumes of
gas vented and flared from wells.

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3179.10 Determinations regarding royaltyfree venting or flaring.
3179.11 Other waste-prevention measures.
3179.12 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 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. This subpart
supersedes those portions of Notice to
Lessees and Operators of Onshore
Federal and Indian Oil and Gas Leases,
Royalty or Compensation for Oil or Gas
Lost (NTL–4A), pertaining to oil or gas
used for beneficial purposes.

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§ 3178.2

Scope.

(a) This subpart applies to:
(1) All onshore Federal and Indian
(other than Osage Tribe) oil and gas
leases, units, and communitized areas,
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

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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; and
(5) All onshore wells, and production
equipment located on a Federal or
Indian lease or a federally approved unit
or communitized area, and compressors
located on a Federal or Indian lease or
a federally approved unit or
communitized area and which compress
production from the same Federal or
Indian lease or federally approved unit
or communitized area.
(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 communitized area and used for
operations and production purposes
(including placing oil or gas in
marketable condition) on the same lease
or communitized area without being
removed from the lease or
communitized area; 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.
(b) 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 communitized area that do not require
prior written BLM approval for royalty-free
treatment of volumes used.

(a) Oil or gas produced from a lease,
unit, or communitized area may be used
royalty-free for operations and
production purposes on the lease, unit,
or communitized area without prior
written BLM approval in the following
circumstances:
(1) Use of fuel to generate power or
operate combined heat and power;
(2) Use of fuel to power equipment,
including artificial lift equipment,
equipment used for enhanced recovery,
drilling rigs, and completion and
workover equipment;
(3) Use of gas to actuate pneumatic
controllers or operate pneumatic pumps
at production facilities;
(4) Use of fuel to heat, separate, or
dehydrate production;

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(5) Use of gas as a pilot fuel or as
assist gas for a flare, combustor, thermal
oxidizer, or other control device;
(6) Use of fuel to compress or treat gas
to place it in marketable condition;
(7) Use of oil to clean the well and
improve production, e.g., hot oil
treatments. 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;
(8) Use of oil as a circulating medium
in drilling operations, if the use is part
of an approved Drilling Plan under
Onshore Oil and Gas Order No. 1;
(9) Injection of gas for the purpose of
conserving gas or increasing the
recovery of oil or gas, if the BLM has
approved the injection under applicable
regulations in parts 3100, 3160, or 3180
of this title; and
(10) Injection of gas that is cycled in
a contained gas-lift system.
(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 communitized area that require prior
written BLM approval for royalty-free
treatment of volumes used.

(a) Oil or gas produced from a lease,
unit, or communitized area may also be
used royalty-free for the following
operations and production purposes on
the lease, unit, or communitized area,
but prior written BLM approval is
required to ensure that production
accountability is maintained:
(1) Use of oil or gas that the operator
removes from the pipeline at a location
downstream of the Facility
Measurement Point (FMP);
(2) Use of gas that has been removed
from the lease, unit PA, or
communitized area for treatment or
processing because of particular
physical characteristics of the gas that
require the gas to be treated or
processed prior to use, where the gas is
returned to, and used on, the lease, unit
PA, or communitized area from which
it was produced; and
(3) Any other types of use of produced
oil or gas for operations and production
purposes, which are 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. If the BLM
disapproves a request for royalty-free
treatment for volumes used under this

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section, the operator must pay royalties
on such volumes. If the BLM approves
a request for royalty-free treatment for
volumes used under this section, such
approval will be deemed effective from
the date the request was filed.
(2) With respect to uses under
paragraph (a)(1) of this section, the
operator must measure the volume of oil
or gas used in accordance with Onshore
Oil and Gas Orders No. 4 (oil) and 5
(gas) as applicable, or other successor
regulations.
(3) With respect to removals under
paragraph (a)(2) of this section, the
operator must measure any gas returned
to the lease, unit, or communitized area
under such an approval in accordance
with Onshore Oil and Gas Order No. 5
or other successor regulations.
§ 3178.6 Uses of oil or gas moved off the
lease, unit, or communitized area 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 communitized area
may be treated as royalty free without
prior written BLM approval only if the
use meets the criteria under § 3178.4
and when:
(a) The oil or gas is transported from
one area of the lease, unit, or
communitized area to another area of
the same lease, unit, or communitized
area where it is used, and no oil or gas
is added to or removed from the
pipeline while crossing lands that are
not part of the lease, unit, or
communitized area; or
(b) A well is directionally drilled, the
wellhead is not located on the
producing lease, unit, or communitized
area, and oil or gas is used on the same
well pad for operations and production
purposes for that well.

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§ 3178.7 Uses of oil or gas moved off the
lease, unit, or communitized area that
require prior written approval for royaltyfree 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 communitized area.
(b) The BLM may grant prior written
approval to treat oil or gas used in
operations conducted off the lease, unit,
or communitized area as royalty free
(referred to as off-lease royalty-free use)
if the use is among those listed in
§ 3178.4(a) and § 3178.5(a) and if:
(1) The equipment or facility in which
the operation is conducted is located off
the lease, unit, or communitized area for
engineering, economic, resource
protection, or physical accessibility
reasons; and

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(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. If the BLM disapproves
a request for royalty-free treatment for
volumes used under this section, the
operator must pay royalties on such
volumes. If the BLM approves a request
for royalty-free treatment for volumes
used under this section, such approval
will be deemed effective from the date
the request was filed.
(d) Approval of measurement or
commingling off the lease, unit, or
communitized area under other
regulations does not constitute approval
of off-lease royalty-free use. The
operator or lessee must expressly
request, and submit its justification for,
approval of off-lease royalty-free use.
(e) If equipment or a facility located
on a particular lease, unit, or
communitized area 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 communitized area 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 communitized area on which
the equipment is located, unless
otherwise authorized by the BLM under
this section.
§ 3178.8 Measurement or estimation of
volumes of oil or gas that are used royaltyfree.

(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 the
volume of gas that is removed from the
product stream downstream of the FMP
and used royalty-free pursuant to
sections 3178.4 through 3178.7.
(c) The operator must measure the
volume of oil that is used royalty-free
pursuant to sections 3178.4 through
3178.7. The operator must also
document removal of such oil from the
tank or pipeline.
(d) If the operator removes oil or gas
downstream of the FMP and that oil or
gas is used royalty-free pursuant to
sections 3178.4 through 3178.7, the
operator must apply for an FMP under
section 3173.12 to measure the oil or gas
that is removed for use.
(e) When estimating gas volumes, the
operator must use the best available

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information to make a reasonable
estimate.
(f) 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 § 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 used in some other way).
§ 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, Royalty or
Compensation for Oil and Gas Lost
(NTL–4A),, 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:

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(1) All onshore Federal and Indian
(other than Osage Tribe) oil and gas
leases, units, and communitized areas,
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
or established under 43 CFR subpart
3105 or 43 CFR part 3180;
(5) All onshore wells, tanks,
compressors, and other equipment
located on a Federal or Indian lease or
a federally approved unit or
communitized area; and
(b) For purposes of this subpart, the
term ‘‘lease’’ also includes IMDA
agreements.

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§ 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.
Automatic ignition system means an
automatic ignitor and, where needed to
ensure continuous combustion, a
continuous pilot flame.
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.
Compressor station means any
permanent combination of one or more
compressors that move natural gas at
increased pressure through gathering or
transmission pipelines, or into or out of
storage. This includes, but is not limited
to, gathering and boosting stations and
transmission compressor stations. The

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combination of one or more
compressors located at a well site, or
located at an onshore natural gas
processing plant, is not a compressor
station.
Continuous bleed means a continuous
flow of pneumatic supply natural gas to
a pneumatic controller.
Development oil well or development
gas well means a well drilled to produce
oil or gas, respectively, from an
established field in which commercial
quantities of hydrocarbons have been
discovered and are being produced. 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 6,000 standard
cubic feet (scf) 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 6,000 scf of gas per barrel of oil.
High pressure flare means an open-air
flare stack or flare pit designed for the
combustion of natural gas leaving a
pressurized production vessel (such as a
separator or heater-treater) that is not a
storage vessel.
Leak means a release of natural gas
from a component that is not associated
with normal operation of the
component, when such release is:
(1) A visible hydrocarbon emission
detected by use of an optical gas
imaging instrument;
(2) At least 500 ppm of hydrocarbon
detected using a portable analyzer or
other instrument that can measure the
quantity of the release; or
(3) Visible bubbles detected using
soap solution.
Releases due to normal operation of
equipment intended to vent as part of
normal operations, such as gas-driven
pneumatic controllers and safety release
devices, are not considered leaks unless
the releases exceed the quantities and
frequencies expected during normal
operations. Releases due to operator
errors or equipment malfunctions or
from control equipment at levels that
exceed applicable regulatory

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requirements, such as releases from a
thief hatch left open, a leaking vapor
recovery unit, or an improperly sized
combustor, are considered leaks.
Leak component means any
component that has the potential to leak
gas and can be monitored in the manner
described in sections 3179.301 through
3179.305 of this subpart, including, but
not limited to, valves, connectors,
pressure relief devices, open-ended
lines, flanges, covers and closed vent
systems, thief hatches or other openings
on a storage vessel, compressors,
instruments, and meters.
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 from 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 communitized area, and
cannot be recovered.
Pneumatic controller means an
automated instrument used for
maintaining a process condition such as
liquid level, pressure, delta-pressure, or
temperature.
Storage vessel means a tank or other
vessel that contains an accumulation of
crude oil, condensate, intermediate
hydrocarbon liquids, or produced water,
and that is constructed primarily of nonearthen materials (such as wood,
concrete, steel, fiberglass, or plastic),
which provide structural support. A
well completion vessel that receives
recovered liquids from a well after
startup of production following
flowback, for a period that exceeds 60
days, is considered a storage vessel
under this subpart unless the storage of
the recovered liquids in the vessel is
governed by § 3162.3–3 of this title. For
purposes of this subpart, the following
are not considered storage vessels:
(1) Vessels that are skid-mounted or
permanently attached to something that
is mobile (such as trucks, railcars,
barges or ships), and are intended to be
located at a site for less than 180
consecutive days. This exclusion does
not apply to well completion vessels or
to storage vessels that are located at a
site for at least 180 consecutive days.
(2) Process vessels such as surge
control vessels, bottoms receivers, or
knockout vessels.

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(3) Pressure vessels designed to
operate in excess of 204.9 kilopascals
and without emissions to the
atmosphere.
(4) Tanks holding hydraulic fracturing
fluid prior to implementation of an
approved permanent disposal plan
under Onshore Oil and Gas Order No.
7.
Volatile organic compounds (VOC)
has the same meaning as defined in 40
CFR 51.100(s).

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

For purposes of this subpart:
Unavoidably lost oil or gas means lost
oil or gas provided that the operator has
not been negligent; the operator has
complied fully with applicable laws,
lease terms, regulations, provisions of a
previously approved operating plan, or
other written orders of the BLM; and the
oil or gas is:
(1) Produced oil or gas that is lost
from the following operations or
sources, and that 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) Normal operating losses from a
natural gas-activated pneumatic
controller or pump that is in compliance
with § 3179.201 and § 3179.202;
(viii) Normal operating losses from a
storage vessel or other low pressure
production vessel that is in compliance
with § 3179.203 and § 3174.5(b);
(ix) Well venting in the course of
downhole well maintenance and/or
liquids unloading performed in
compliance with § 3179.204;
(x) Leaks, when the operator has
complied with the leak detection and
repair requirements in §§ 3179.301–305;
(xi) Facility and pipeline
maintenance, such as when an operator
must blow-down and depressurize
equipment to perform maintenance or
repairs; or
(xii) Flaring of gas from which at least
50 percent of natural gas liquids have
been removed and captured for market,
if the operator has notified the BLM
through a Sundry Notice that the
operator is conducting such capture; or
(2) Produced gas that is flared or
vented from a well that is not connected

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to a gas pipeline, provided the BLM has
not determined loss of gas through such
venting or flaring is otherwise
avoidable.
Avoidably lost oil or gas means: Lost
oil or gas that is not ‘‘unavoidably lost,’’
as defined in paragraph (a) of this
section; waste oil that became waste oil
through operator negligence; and, any
‘‘excess flared gas,’’ as defined in
§ 3179.7.
§ 3179.5 When lost production is subject
to royalty.

(a) Royalty is due on all avoidably lost
oil or gas.
(b) Royalty is not due on any
unavoidably lost oil or gas.
§ 3179.6

Venting prohibition.

(a) Gas well gas may not be flared or
vented, except where it is unavoidably
lost pursuant to § 3179.4(a).
(b) 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, as
defined in § 3179.105, when the loss of
gas is uncontrollable or venting is
necessary for safety;
(3) When the gas is vented through
normal operation of a natural gasactivated pneumatic controller or pump;
(4) When the gas is vented from a
storage vessel, provided that § 3179.203
does not require the combustion or
flaring of the gas;
(5) When the gas is vented during
downhole well maintenance or liquids
unloading activities performed in
compliance with § 3179.204;
(6) When the gas is vented through a
leak, provided that the operator is in full
compliance with §§ 3179.301 through
3179.305;
(7) When the gas venting is necessary
to allow non-routine facility and
pipeline maintenance to be performed,
such as when an operator must, upon
occasion, blow-down and depressurize
equipment to perform maintenance or
repairs; or
(8) When a release of gas is
unavoidable under § 3179.4 and flaring
is prohibited by Federal, State, local or
Tribal law, regulation, or enforceable
permit term.
(c) For purposes of this subpart, all
flares or combustion devices must be
equipped with an automatic ignition
system.
§ 3179.7

Gas capture requirement.

(a) Except as provided in § 3179.8, on
a monthly basis, each operator must

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capture for sale or use on site a volume
of gas sufficient to meet the ‘‘capture
percentage’’ requirement specified in
paragraph (b) of this section.
(b) Beginning January 17, 2018, the
operator’s capture percentage must
equal:
(1) For each month during the period
from January 17, 2018 until December
31, 2019: 85 percent;
(2) For each month during the period
from January 1, 2020 until December 31,
2022: 90 percent;
(3) For each month during the period
from January 1, 2023 until December 31,
2025: 95 percent; and
(4) For each month beginning January
1, 2026: 98 percent.
(c) The term ‘‘capture percentage’’ in
this section means the ‘‘total volume of
gas captured’’ over the ‘‘relevant area’’
divided by the ‘‘adjusted total volume of
gas produced’’ over the ‘‘relevant area.’’
(1) The term ‘‘total volume of gas
captured’’ in this section means: for
each month, the volume of gas sold from
all of the operator’s development oil
wells in the relevant area plus the
volume of gas from such wells used on
lease, unit, or communitized area in the
relevant area.
(2) The term ‘‘adjusted total volume of
gas produced’’ in this section means: the
total volume of gas captured over the
month plus the total volume of gas
flared over the month from high
pressure flares from all of the operator’s
development oil wells that are in
production in the relevant area, minus:
(i) For each month from January 17,
2018 until December 31, 2018: 5,400
Mcf times the total number of
development oil wells ‘‘in production’’
in the relevant area;
(ii) For each month in calendar year
2019: 3,600 Mcf times the total number
of development oil wells in production
in the relevant area;
(iii) For each month in calendar year
2020: 1,800 Mcf times the total number
of development oil wells in production
in the relevant area; and
(iv) For each month in calendar year
2021: 1,500 Mcf times the total number
of development oil wells in production
in the relevant area;
(v) For each month in calendar years
2022–2023: 1,200 Mcf times the total
number of development oil wells in
production in the relevant area;
(vi) For each month in calendar year
2024: 900 Mcf times the total number of
development oil wells in production in
the relevant area; and
(vii) For each month in calendar year
2025 and thereafter: 750 Mcf times the
total number of development oil wells
in production in the relevant area.
(3) The term ‘‘relevant area’’ in this
section means:

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Federal Register / Vol. 81, No. 223 / Friday, November 18, 2016 / Rules and Regulations
(i) Each of the operator’s leases, units,
or communitized areas; or
(ii) All of the operator’s development
oil wells on leases, units, and
communitized areas within a county or
within a State, if the operator notifies
the BLM by Sundry Notice by January
1, of the relevant year that the operator
has chosen to comply on a county- or
State-wide basis.
(4) An oil well is considered ‘‘in
production’’ only after the well has
begun producing oil, and only during a
month in which it produces gas (that is
sold or flared) for 10 or more days.
(d) In any month in which the
operator fails to meet the required
capture percentage, the ‘‘excess flared
gas’’ is royalty-bearing under § 3179.4.
The term ‘‘excess flared gas’’ means:
Excess flared gas = (required capture
percentage * adjusted total volume of gas
produced over the relevant area) ¥ total
volume of gas captured.

(e) For purposes of calculating
royalties on an operator’s excess flared
gas in a given month, the operator must
prorate the excess flared gas across the
relevant area to each lease, unit or
communitized area that reported highpressure flaring during the month.

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§ 3179.8

Alternative capture requirement.

(a) With respect to leases issued
before the effective date of this
regulation, for operators choosing to
comply with the capture requirement in
§ 3179.7 on a lease-by-lease, unit-byunit, or communitized area-bycommunitized area basis, the BLM may
approve a capture percentage lower than
the applicable capture percentage
specified under § 3179.7, if the operator
demonstrates, and the BLM agrees, that
the applicable capture percentage under
§ 3179.7 would impose such costs as to
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease.
(b) To support a demonstration under
paragraph (a) of this section, the
operator must submit a Sundry Notice
that includes the following information:
(1) The name, number, and location of
each of the operator’s wells, and the
number of the lease, unit, or
communitized area with which it is
associated;
(2) The oil and gas production levels
of each of the operator’s wells on the
lease, unit or communitized area for the
most recent production month for
which information is available and the
volumes being vented and flared from
each well;
(3) Map(s) showing:
(i) The entire lease, unit, or
communitized area and the surrounding

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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, unit,
or communitized area 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, unit,
or communitized area from which gas is
captured;
(4) Data that show pipeline capacity
and the operator’s projections of the cost
associated with installation and
operation of gas capture infrastructure,
to the extent that the operator is able to
obtain this information, as well as cost
projections for alternative methods of
transportation that do not require
pipelines;
(5) Projected costs of and the
combined stream of revenues from both
gas and oil production, including:
(i) 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
communitized area, whichever is less;
and
(ii) 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 next 15 years
or the life of the operator’s lease, unit,
or communitized area, whichever is
less.
(c) In establishing an alternative
capture requirement under this section,
the BLM will set the capture percentage
at the highest 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.
§ 3179.9 Measuring and reporting volumes
of gas vented and flared.

(a) The operator must estimate or
measure all volumes of gas vented or
flared from wells, facilities and
equipment on a lease, unit PA, or
communitized area and report those

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83083

volumes under applicable ONRR
reporting requirements.
(b) The operator may estimate such
volumes, except:
(1) If the operator estimates that the
volume of gas flared from a high
pressure flare stack or manifold equals
or exceeds an average of 50 Mcf per day
for the life of the flare, or the previous
12 months, whichever is shorter, then,
beginning January 17, 2018 the operator
must either:
(i) Measure the volume of the flared
gas; or
(ii) Calculate the volume of the flared
gas based on the results of a regularly
performed GOR test and measured
values for the volumes of oil production
and gas sales, so as to allow BLM to
independently verify the volume, rate,
and heating value of the flared gas; 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, then the operator must
measure the volume of the flared gas.
(c) If measurement or calculation is
required under paragraph (b) of this
section for a flare that is combusting gas
that is combined across multiple leases,
unit PAs, or communitized areas, the
operator may measure or calculate the
gas at a single point at the flare, but
must use an allocation method
approved by the BLM to allocate the
quantities of flared gas to each lease,
unit PA, or communitized area.
§ 3179.10 Determinations regarding
royalty-free flaring.

(a) Approvals to flare royalty free,
which are in effect as of the effective
date of this rule, will continue in effect
until January 17, 2018.
(b) The provisions of this subpart do
not affect any determination made by
the BLM before or after January 17,
2017, with respect to the royalty-bearing
status of flaring that occurred prior to
January 17, 2017.
§ 3179.11 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 pipeline, the BLM may exercise
its authority under applicable laws and
regulations, as well as its authority
under the terms of applicable permits,
orders, leases, and unitization or
communitization agreements, 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 pipeline.

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(b) If gas capture capacity is not yet
available on a given lease, the BLM may
exercise its authority under applicable
laws and regulations, as well as its
authority under the terms of applicable
permits, orders, leases, and unitization
or communitization agreements, to
delay action on an APD for that lease,
or approve the APD with conditions for
gas capture or limitations on
production. If the lease for which an
APD is submitted is not yet producing,
the BLM may direct or grant a lease
suspension under 43 CFR 3103.4–4.
§ 3179.12 Coordination with State
regulatory authority.

To the extent that any BLM action to
enforce a prohibition, limitation, or
order under this subpart may adversely
affect 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 of
this subpart, and unless technically
infeasible, 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
to combust any flammable gasses;
(3) Used in operations on the lease,
unit, or communitized area; 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
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.

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§ 3179.102 Well completion and related
operations.

(a) Except as provided in § 3179.6,
and unless technically infeasible, after a
well has been hydraulically fractured or
refractured, gas that reaches the surface
during well completion, postcompletion, and fluid recovery
operations must be:
(1) Captured and sold;
(2) Directed to a flare pit or flare stack
to combust any flammable gasses,
subject to the volumetric limitations in
§ 3179.103(a)(3);

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(3) Used in operations on the lease,
unit, or communitized area; or
(4) Injected.
(b) An operator will be deemed to be
in compliance with the requirements of
paragraph (a) of this section, if the
operator is in compliance with the
requirements for control of gas from
well completions established under 40
CFR part 60, subpart OOOO or subpart
OOOOa or if the well is not a ‘‘well
affected facility’’ under either of those
subparts.
(c) The requirements of paragraph (a)
of this section will not apply where the
operator demonstrates through a Sundry
Notice, and the BLM agrees, that
compliance with paragraph (a) of this
section would impose such costs as to
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease.
(d) To support a demonstration under
paragraph (d) of this section, the
operator must submit a Sundry Notice
that includes the following information:
(1) The name, number, and location of
each of the operator’s wells, and the
number of the lease, unit, or
communitized area with which it is
associated;
(2) The oil and gas production levels
of each of the operator’s wells on the
lease, unit or communitized area for the
most recent production month for
which information is available;
(3) Data that show the costs of
compliance with paragraph (a) of this
section on the lease; (4) Projected costs
of and the combined stream of revenues
from both gas and oil production,
including: the operator’s projections of
oil and gas prices, production volumes,
quality (i.e., heating value and H2S
content), revenues derived from
production, and royalty payments on
production over the next 15 years or the
life of the operator’s lease, unit, or
communitized area, whichever is less.
§ 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 (d) 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(a)(2), except as provided in
paragraph (c) of this section; or

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(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) The BLM may increase the limit
specified in paragraph (a)(3) by up to an
additional 30 million cubic feet of gas
for exploratory wells in remote locations
where additional testing is needed in
advance of development of pipeline
infrastructure.
(d) 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.
(e) The operator must submit its
request for a longer test period or
increased limit under paragraphs (b),
(c), or (d) 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, unless the BLM approves or
requires a longer period. The operator
must request a longer period under this
section using 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 § 3179.4(a)(vi) of
this subpart during an emergency. For
purposes of this subpart, an
‘‘emergency’’ is a temporary, infrequent
and unavoidable situation in which the
loss of gas or oil is uncontrollable or
necessary to avoid risk of an immediate
and substantial adverse impact on
safety, public health, or the
environment. For purposes of royalty
assessment, an ‘‘emergency’’ is limited
to a short-term situation of 24 hours or
less (unless the BLM agrees that the
emergency conditions necessitating
venting or flaring extend for a longer
period) caused by an unanticipated
event or failure that is out of the
operator’s control and was not due to
operator negligence.
(b) The following do not constitute
emergencies for the purposes of royalty
assessment:
(1) More than 3 failures of the same
component within a single piece of
equipment within any 365-day period;
(2) The operator’s failure to install
appropriate equipment of a sufficient

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capacity to accommodate the
production conditions;
(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;
(5) A situation caused by operator
negligence; or
(6) A situation on a lease, unit, or
communitized area that has already
experienced 3 or more emergencies
within the past 30 days, unless the BLM
determines that the occurrence of more
than 3 emergencies within the 30 day
period could not have been anticipated
and was beyond the operator’s control.
(c) Within 45 days of the start of the
emergency, 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
and During Well Maintenance
Operations

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§ 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
communitized area 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 any of the
requirements of 40 CFR part 60, subpart
OOOO or subpart OOOOa, but would be
subject to one of those subparts if it
were a new, modified, or reconstructed
source.
(b) The operator must replace a
pneumatic controller subject to this
section with a controller (including but
not limited to a continuous or
intermittent pneumatic controller)
having a bleed rate of 6 scf per hour or
less within the timeframes set forth in
paragraph (d) of this section, unless:
(1) Use of a pneumatic controller with
a bleed rate greater than 6 scf per hour
is required based on functional needs
that may include, but are not limited to,
response time, safety, and positive
actuation, provided that the operator
notifies the BLM through a Sundry
Notice that describes the functional
needs necessitating the use of a
pneumatic controller with a bleed rate
greater than 6 scf per hour;
(2) The pneumatic controller exhaust
was, as of January 17, 2017 and
continues to be, routed to a flare device
or low-pressure combustor;

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(3) The pneumatic controller exhaust
is routed to processing equipment; or
(4) The operator notifies the BLM
through a Sundry Notice and
demonstrates, and the BLM agrees,
based on the information identified in
paragraph (c) of this section, 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) To support a demonstration under
paragraph (b)(4) of this section, the
operator must submit a Sundry Notice
that includes the following information:
(1) The name, number, and location of
each of the operator’s wells, and the
number of the lease, unit, or
communitized area with which it is
associated;
(2) The oil and gas production levels
of each of the operator’s wells on the
lease, unit or communitized area for the
most recent production month for
which information is available;
(3) Data that show the costs of
compliance with paragraph (b) of this
section on the lease;
(4) Projected costs of and the
combined stream of revenues from both
gas and oil production, including:
(i) 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
communitized area, whichever is less;
and
(ii) 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 next 15 years
or the life of the operator’s lease, unit,
or communitized area, whichever is
less.
(d) 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. If, however, 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, then
the operator may notify the BLM
through a Sundry Notice and replace the
pneumatic controller no later than 3
years from the effective date of this
section.
(e) The operator must ensure
pneumatic controllers are functioning
within manufacturers’ specifications.

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§ 3179.202 Requirements for pneumatic
diaphragm pumps.

(a) A 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 communitized area that includes a
Federal or Indian lease; and
(2) Is not subject to any of the
requirements of 40 CFR part 60, subpart
OOOOa, but would be subject to that
subpart if it were a new, modified or
reconstructed source.
(b) An operator is not required to
comply with paragraphs (c) through (h),
with respect to a pneumatic diaphragm
pump or pumps if:
(1) The pump does not vent exhaust
gas to the atmosphere; or
(2) The operator submits a Sundry
Notice to the BLM documenting that the
pump(s) operated on less than 90
individual days in the prior calendar
year.
(c) For each pneumatic diaphragm
pump subject to this section and within
the timeframes set forth in paragraph (h)
of this section, the operator must:
(1) Replace the pump with a zeroemissions pump, which may be an
electric-powered pump; or
(2) Route the pump exhaust gas to
processing equipment for capture and
sale.
(d) As an alternative to compliance
with paragraph (c), the operator may
route the pump exhaust gas to a flare or
low pressure combustor device within
the timeframes set forth in paragraph (h)
of this section, if the operator
determines and notifies the BLM
through a Sundry Notice that:
(1) Replacing the pump with a zeroemissions pump is not viable because a
pneumatic pump is necessary to
perform the function required; and
(2) Routing the pump exhaust gas to
processing equipment for capture and
sale is technically infeasible or unduly
costly.
(e) If the operator has met the criteria
in paragraph (d) allowing the operator to
use the compliance alternative provided
in paragraph (d), but the operator has no
flare or low pressure combustor device
on site, or routing the exhaust gas to
such a flare or low pressure combustor
device would be technically infeasible,
the operator need take no further action
to comply with paragraphs (c) through
(h).
(f) An operator that is required to
replace a pump or route the exhaust gas
from a pump to capture or a flare or
combustion device under this section,
may nonetheless be exempt from such
requirement if the operator submits a
Sundry Notice to the BLM that provides
an economic analysis that demonstrates,

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and the BLM agrees, based on the
information identified in paragraph (g)
of this section, that compliance with the
provisions of this section would impose
such costs as to cause the operator to
cease production and abandon
significant recoverable oil reserves
under the lease.
(g) The Sundry Notice described in
paragraph (f) must include the following
information:
(1) Well information must include:
(i) The name, number, and location of
each well, and the number of the lease,
unit, or communitized area with which
it is associated; and
(ii) The oil and gas production levels
of each of the operator’s wells on the
lease, unit or communitized area for the
most recent production month for
which information is available;
(2) Data that show the costs of
compliance with paragraphs (c) through
(e) of this section on the lease;
(3) The operator must consider the
costs and revenues of the combined
stream of revenues from both the gas
and oil components and provide:
(i) 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
communitized area, whichever is less;
and
(ii) 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 next 15 years
or the life of the operator’s lease, unit,
or communitized area, whichever is
less.
(h) The operator must replace the
pneumatic diaphragm pump(s) or route
the exhaust gas to capture or to a flare
or combustion device no later than 1
year after the effective date of this
section, except that if the operator will
comply with paragraph (c) of this
section by replacing the pneumatic
diaphragm pump with a zero-emission
pump and the well or facility that the
pneumatic diaphragm 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 diaphragm pump
no later than 3 years from the effective
date of this section.
(i) The operator must ensure its
pneumatic diaphragm pumps are
functioning within manufacturers’
specifications.

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§ 3179.203

Storage vessels.

(a) A storage vessel is subject to this
section if the vessel:
(1) Contains production from a
Federal or Indian lease, or from a unit
or communitized area that includes a
Federal or Indian lease; and
(2) Is not subject to any of the
requirements of 40 CFR part 60,
subparts OOOO or OOOOa, but would
be subject to one of those subparts if it
were a new, modified or reconstructed
source.
(b) Within 60 days after the effective
date of this section, and within 30 days
after any new source of production is
added to the storage vessel, the operator
must determine, record, and make
available to the BLM upon request,
whether the storage vessel has the
potential for VOC emissions equal to or
greater than 6 tpy based on the
maximum average daily throughput for
a 30-day period of production. The
determination may take into account
requirements under a legally and
practically enforceable limit in an
operating permit or other requirement
established under a federal, state, local
or tribal authority that limit the VOC
emissions to less than 6 tpy.
(c) If a storage vessel has the potential
for VOC emissions equal to or greater
than 6 tpy under paragraph (b) of this
section, no later than one year after the
effective date of this section, or three
years if the operator must and will
replace the storage vessel at issue in
order to comply with the requirements
of this section, the operator must:
(1) Route all tank vapor gas from the
storage vessel to a sales line;
(2) If the operator determines that
compliance with paragraph (c)(1) of this
section is technically infeasible or
unduly costly, route all tank vapor gas
from the storage vessel to a device or
method that ensures continuous
combustion of the tank vapor gas; or
(3) Submit an economic analysis to
the BLM through a Sundry Notice that
demonstrates, and the BLM agrees,
based on the information identified in
paragraph (d) of this section, that
compliance with paragraph (c)(2) of this
section would impose such costs as to
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease.
(d) To support a demonstration under
paragraph (c) of this section, the
operator must submit a Sundry Notice
that includes the following information:
(1) The name, number, and location of
each well, and the number of the lease,
unit, or communitized area with which
it is associated;
(2) The oil and gas production levels
of each of the operator’s wells on the

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lease, unit or communitized area for the
most recent production month for
which information is available;
(3) Data that show the costs of
compliance with paragraph (c)(1) or
(c)(2) of this section on the lease;
(4) The operator must consider the
costs and revenues of the combined
stream of revenues from both the gas
and oil components and provide:
(i) The operator’s projections of oil
and gas prices, production volumes,
quality (i.e., heating value and H2S
content), revenues derived from
production, and royalty payments on
production over the next 15 years or the
life of the operator’s lease, unit, or
communitized area, whichever is less.
(e) If the rate of total uncontrolled
VOCs released from a storage vessel
declines to 4 tpy or less for any
continuous 12 month period, the
requirements of paragraph (c) no longer
apply.
(f) Storage vessels subject to this
section must be adequately sized to
accommodate the operator’s production
levels and equipped to meet any
applicable regulatory requirements
regarding tank vapors.
(g) Storage vessels subject to this
section may only vent through properly
functioning pressure relief devices.
§ 3179.204 Downhole well maintenance
and liquids unloading.

(a) The operator must minimize
vented gas and the need for well venting
associated with downhole well
maintenance and liquids unloading,
consistent with safe operations.
(b) For wells equipped with a plunger
lift system and/or an automated well
control system, minimizing gas venting
under paragraph (a) includes optimizing
the operation of the system to minimize
gas losses to the extent possible
consistent with removing liquids that
would inhibit proper function of the
well.
(c) Before the operator manually
purges a well for liquids unloading for
the first time after the effective date of
this section, the operator must consider
other methods for liquids unloading and
determine that they are technically
infeasible or unduly costly. The
operator must provide information
supporting that determination as part of
the Sundry Notice required under
paragraph (e) of this section.
(d) For any liquids unloading by
manual well purging, the operator must:
(1) Ensure that the person conducting
the well purging remains present on-site
throughout the event to minimize to the
maximum extent practicable any
venting to the atmosphere;

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(2) Record the cause, date, time,
duration, and estimated volume of each
venting event; and
(3) Maintain the records for the period
required under § 3162.4–1 of this title
and make them available to the BLM,
upon request.
(e) The operator must notify the BLM
by Sundry Notice within 30 calendar
days after the first liquids unloading
event by manual or automated well
purging conducted after the effective
date of this section. This requirement
applies to each well the operator
operates.
(f) The operator must notify the BLM
by Sundry Notice, within 30 calendar
days, if:
(1) The cumulative duration of
manual 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 manual
well purging operations for a well
exceeds 75 Mcf during any production
month.
(g) For purposes of this section, ‘‘well
purging’’ means blowing accumulated
liquids out of a wellbore by reservoir gas
pressure, whether manually or by an
automatic control system that relies on
real-time pressure or flow, timers, or
other well data, where the gas is vented
to the atmosphere, and it does not apply
to wells equipped with a plunger lift
system.
(h) Total estimated volumes vented as
a result of downhole well maintenance
and liquids unloading, including
through the operation of plunger lifts
and automated well controls, during the
production month must be included in
volumes reported to ONRR as vented.
Leak Detection and Repair (LDAR)

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§ 3179.301

Operator responsibility.

(a) The requirements of §§ 3179.301
through 3179.305 of this subpart apply
to:
(1) A site and all equipment
associated with it used to produce,
process, compress, treat, store, or
measure natural gas (including oil wells
that also produce natural gas) from or
allocated to a Federal or Indian lease,
unit, or communitized area, where the
site is upstream of or contains the
approved point of royalty measurement;
and
(2) A site and all equipment operated
by the operator and associated with a
site used to store, measure, or dispose
of produced water, where the site is
located on a Federal or Indian lease.
(b) The requirements of §§ 3179.301
through 3179.305 of this subpart do not
apply to:

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(1) A site that contains a wellhead or
wellheads and no other equipment; or
(2) A well or well equipment that has
been depressurized.
(c) As prescribed in §§ 3179.302 and
3179.303 of this subpart, the operator
must inspect all equipment covered
under this section, as provided in
paragraph (a) of this section, for gas
leaks from leak components.
(d) The operator is not required to
inspect or monitor a leak component
that is not an accessible component.
(e) For purposes of §§ 3179.301
through 3179.305, the term ‘‘site’’ means
a discrete area located on a lease, unit,
or communitized area, and containing a
wellhead, wellhead equipment, or other
equipment used to produce, process,
compress, treat, store, or measure
natural gas or store, measure, or dispose
of produced water, which is suitable for
inspection in a single visit.
(f) The operator must make the first
inspection of each site:
(1) Within one year of January 17,
2017 for sites that have begun
production prior to January 17, 2017;
(2) Within 60 days of beginning
production for sites that begin
production after January 17, 2017; and
(3) Within 60 days of the date when
a site that was out of service is brought
back into service and re-pressurized.
(g) The operator must make
subsequent inspections as prescribed in
§ 3179.303.
(h) All leak inspections must occur
during production operations.
(i) The operator must fix identified
leaks as prescribed in §§ 3179.304 and
3179.305 of this subpart. See 43 CFR
3162.5–1 for responsibility to repair oil
leaks.
(j) With respect to new, modified or
reconstructed equipment, an operator
will be deemed to be in compliance
with the requirements of this section for
such equipment, if the operator is in
compliance with the requirements of
subpart OOOOa applicable to such
equipment.
(k) For each lease, unit, or
communitized area, for all covered sites
and equipment not already deemed in
compliance with the requirements of
this section pursuant to paragraph (j), an
operator may choose to satisfy the
requirements of §§ 3179.301 through
3179.305 by:
(1) Treating each of those sources as
if it were a collection of fugitive
emissions components as defined in 40
CFR part 60 subpart OOOOa;
(2) Complying with the requirements
of 40 CFR part 60 subpart OOOOa that
apply to affected facility fugitive
emissions components at a well site (or
for compressor stations, that apply to

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83087

affected facility fugitive emissions
components at a compressor station)
under 40 CFR part 60, subpart OOOOa;
and
(3) Notifying the BLM through a
Sundry Notice regarding such
compliance.
§ 3179.302
methods.

Approved instruments and

(a) The operator must use one or more
of the following instruments, operated
according to the manufacturer’s
specifications or as specified below, to
detect leaks:
(1) An optical gas imaging device
capable of imaging a gas that is half
methane, half propane at a
concentration of 10,000 ppm at a flow
rate of less than or equal to 60 grams per
hour from a quarter inch diameter
orifice;
(2) A portable analyzer device capable
of detecting leaks, such as catalytic
oxidation, flame ionization, infrared
absorption or photoionization devices,
used for a leak detection survey
conducted in compliance with the
relevant sections of Method 21 at 40
CFR part 60, appendix A–7, including
section 8.3.1. and assisted by audio,
visual, and olfactory inspection; or
(3) A leak detection device not listed
in this section that is approved by the
BLM for use by any operator under
§ 3179.302(d) of this subpart.
(b) The person operating any of the
leak detection devices listed in or
approved under this section must be
adequately trained in the proper use of
the device.
(c) Any person may request approval
of an alternative monitoring device and
protocol by submitting a Sundry Notice
to BLM that includes the following
information:
(1) Specifications of the proposed
monitoring device, including a
detection limit capable of supporting
the desired function;
(2) The proposed monitoring protocol
using the proposed monitoring device,
including how results will be recorded;
(3) Records and data from laboratory
and field testing, including but not
limited to performance testing;
(4) A demonstration that the proposed
monitoring device and protocol will
achieve equal or greater reduction of gas
lost through leaks compared with the
approach specified in § 3179.302(a)(1)
when used according to § 3179.303(a) of
this subpart;
(5) Tracking and documentation
procedures; and
(6) Proposed limitations on the types
of sites or other conditions on deploying
the device and the protocol to achieve
the demonstrated results.

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(d) The BLM may approve an
alternative monitoring device and
associated inspection protocol, if the
BLM finds that the alternative would
achieve equal or greater reduction of gas
lost through leaks compared with the
approach specified in § 3179.302(a)(1)
when used according to § 3179.303(a) of
this subpart.
(1) The BLM will provide public
notice of a submission for approval
under section 3179.302(c).
(2) The BLM may approve an
alternative device and monitoring
protocol for use in all or most
applications, or for use on a pilot or
demonstration basis under specified
circumstances that limit where and for
how long the device may be used.
(3) The BLM will post on the BLM
Web site a list of each approved
alternative monitoring device and
protocol, along with any limitations on
its use.

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§ 3179.303 Leak detection inspection
requirements for natural gas wellhead
equipment and other equipment.

(a) Except as provided below or
otherwise authorized in paragraph (b) of
this section, the operator must inspect
leak components located on and around
the equipment identified in
§ 3179.301(a) of this subpart for leaks
using a leak detection device listed
under § 3179.302 according to the
following parameters:
(1) The operator must inspect each
site at least semi-annually, and
consecutive semiannual inspections
must be conducted at least 4 months
apart; and
(2) The operator must inspect each
compressor station at least quarterly,
and consecutive quarterly inspections
must be conducted at least 60 days
apart.
(b) The BLM may approve an
operator’s request to use an alternative
instrument-based leak detection
program, in lieu of compliance with the
requirements of § 3179.303(a), if the
BLM finds that the alternative program
would achieve equal or greater
reduction of gas lost through leaks
compared with 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 program through a Sundry
Notice that includes the following
information:
(1) A detailed description of the
alternative leak detection program,
including how it will use one or more
of the instruments specified in or
approved under § 3179.302(a) and an
identification of the specific
instruments, methods and/or practices

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that would substitute for specific
elements of the approach specified in
§§ 3179.302(a) and 3179.303(a);
(2) The proposed monitoring protocol;
(3) Records and data from laboratory
and field testing, including, but not
limited to, performance testing, to the
extent relevant;
(4) A demonstration that the proposed
alternative leak detection program will
achieve equal or greater reduction of gas
lost through leaks compared to
compliance with the requirements
specified in §§ 3179.302(a) and
3179.303(a);
(5) A detailed description of how the
operator will track and document its
procedures, leaks found, and leaks
repaired; and
(6) Proposed limitations on types of
sites or other conditions on deployment
of the alternative leak detection
program.
(c) If the operator demonstrates, and
the BLM agrees, that compliance with
the requirements of §§ 3179.301–305,
including the option for compliance
with an alternative leak detection
program under § 3179.303(b) would
impose such costs as to cause the
operator to cease production and
abandon significant recoverable oil or
gas reserves under the lease, the BLM
may approve an alternative leak
detection program for that operator that
does not meet the criterion specified in
§ 3179.303(b)(4), but is as effective as
possible consistent with not causing the
operator to cease production and
abandon significant recoverable oil or
gas reserves under the lease.
(d) To support a demonstration under
paragraph (c) of this section, the
operator must submit a Sundry Notice
that includes the following information:
(1) The name, number, and location of
each well, and the number of the lease,
unit, or communitized area with which
it is associated;
(2) The oil and gas production levels
of each of the operator’s wells on the
lease, unit or communitized area for the
most recent production month for
which information is available;
(3) Data that show the costs of
compliance on the lease with the
requirements of §§ 3179.301–305 and
with an alternative leak detection
program that meets the requirements of
§ 3179.303(b);
(4) The operator must consider the
costs and revenues of the combined
stream of revenues from both the gas
and oil components and provide the
operator’s projections of oil and gas
prices, production volumes, quality (i.e.,
heating value and H2S content),
revenues derived from production, and
royalty payments on production over

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the next 15 years or the life of the
operator’s lease, unit, or communitized
area, whichever is less;
(5) The information required under
§ 3179.303(b), except that in lieu of the
demonstration required under
§ 3179.303(b)(4), the operator must
demonstrate that the alternative
program is as effective as possible,
consistent with not imposing such costs
as to cause the operator to cease
production and abandon significant
recoverable oil or gas reserves under the
lease.
(e) For any BLM approval of an
operator’s use of an alternative leak
detection program under subparagraph
(b) or (c) of this section, the BLM will
post online the alternative program
approved for that operator, including, at
minimum, the information required in
subparagraph (b)(1), (b)(2), (b)(5), and
(b)(6) of this section.
§ 3179.304

Repairing leaks.

(a) The operator must repair any leak
as soon as practicable, and in no event
later than 30 calendar days after
discovery, unless good cause exists for
repair requiring a longer period. Good
cause for delay of repair exists if the
repair (including replacement) is
technically infeasible (including
unavailability of parts that have been
ordered), would require a pipeline
blowdown, a compressor station
shutdown, a well shut-in, or would be
unsafe to conduct during operation of
the unit.
(b) If there is good cause for delaying
the repair beyond 30 calendar days, the
operator must notify the BLM of the
cause by Sundry Notice and must
complete the repair at the earliest
opportunity, for example during the
next compressor station shutdown, well
shut-in, or pipeline blowdown. In no
case may the repair be delayed beyond
2 years.
(c) Not later than 30 calendar days
after completion of a repair, the operator
must verify the effectiveness of the
repair through a follow-up inspection
using one of the instruments specified
or approved under § 3179.302(a) or a
soap bubble test under Section 8.3.3 of
EPA Method 21—Determination of
Volatile Organic Compound
Leaks (40 CFR Appendix A–7 to part
60).
(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.

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§ 3179.305 Leak detection inspection
recordkeeping and reporting.

State or Tribal Variances

(a) 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:
(1) For each inspection required
under § 3179.303 of this subpart,
documentation of:
(i) The date of the inspection; and
(ii) The site where the inspection was
conducted;
(2) The monitoring method(s) used to
determine the presence of leaks;
(3) A list of leak components on
which leaks were found;
(4) The date each leak was repaired;
and
(5) The date and result of the followup inspection(s) required under
§ 3179.304 paragraph (c) or (d) of this
subpart.
(b) By March 31 each calendar year,
the operator must provide to the BLM
an annual summary report on the
previous year’s inspection activities that
includes:
(1) The number of sites inspected;
(2) The total number of leaks
identified, categorized by the type of
component;
(3) The total number of leaks repaired;
(4) The total number leaks that were
not repaired as of December 31 of the
previous calendar year due to good
cause and an estimated date of repair for
each leak.
(5) A certification by a responsible
officer that the information in the report
is true and accurate to the best of the
officer’s knowledge.
(c) AVO checks are not required to be
documented unless they find a leak
requiring repair.

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

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(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 provision(s) of
this Subpart that would apply to all
Federal leases, units, or communitized
areas within a State or to all tribal
leases, units, or communitized areas
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, local, 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, local,
or tribal regulation(s) or rule(s) would
perform at least equally well in terms of
reducing waste of oil and gas, reducing
environmental impacts from venting
and or flaring of gas, and ensuring the
safe and responsible production of oil
and gas, compared to the particular
provision(s) 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, local or tribal regulation(s) or
rule(s) would perform at least equally

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well in terms of reducing waste of oil
and gas, reducing environmental
impacts from venting and/or flaring of
gas, and ensuring the safe and
responsible production of oil and gas,
compared to the particular provision(s)
from which the State or tribe is
requesting the variance, and would be
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 appeals 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.
(e) If the BLM approves a variance
under this section, the State or tribe that
requested the variance must notify the
BLM in writing in a timely manner of
any substantive amendments, revisions,
or other changes to the State, local or
tribal regulation(s) or rule(s) to be
applied under the variance.
(f) If the BLM approves a variance
under this section, the State, local or
tribal regulation(s) or rule(s) to be
applied under the variance can be
enforced by the BLM as if the
regulation(s) or rule(s) were provided
for in this Subpart. The State, locality,
or tribes’ own authority to enforce its
regulation(s) or rule(s) to be applied
under the variance would not be
affected by the BLM’s approval of a
variance.
[FR Doc. 2016–27637 Filed 11–17–16; 8:45 am]
BILLING CODE 4310–84–P

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