[Federal Register Volume 81, Number 223 (Friday, November 18, 2016)]
[Rules and Regulations]
[Pages 83008-83089]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-27637]



[[Page 83007]]

Vol. 81

Friday,

No. 223

November 18, 2016

Part VIII





Department of the Interior





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 Bureau of Land Management





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43 CFR Parts 3100, 3160 and 3170





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

  Federal Register / Vol. 81 , No. 223 / Friday, November 18, 2016 / 
Rules and Regulations  

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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

AGENCY: Bureau of Land Management, Interior.

ACTION: Final rule.

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SUMMARY: 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
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
    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
    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

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 Sec.  187. The BLM 
believes there are economical, cost-effective, 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 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\
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    \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).
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    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.
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    \3\ See Intergovernmental Panel on Climate Change, Climate 
Change 2013: The Physical Science Basis, Chapter 8, Anthropogenic 
and Natural Radiative Forcing, at 714 (Table 8.7), available at 
https://www.ipcc.ch/pdf/assessment-report/ar5/wg1/WG1AR5_Chapter08_FINAL.pdf.
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    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 
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\
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    \4\ Mineral Leasing Act, 30 U.S.C. 188-287; Mineral Leasing Act 
for Acquired Lands, 30 U.S.C. 351-360; Federal Oil and Gas Royalty 
Management Act, 30 U.S.C. 1701-1758; Federal Land Policy and 
Management Act of 1976, 43 U.S.C. 1701-1785; Indian Mineral Leasing 
Act of 1938, 25 U.S.C. 396a-g; Indian Mineral Development Act of 
1982, 25 U.S.C. 2101-2108; Act of March 3, 1909, 25 U.S.C. 396.
    \5\ 30 U.S.C. 225.
    \6\ 30 U.S.C. 187.
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    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\
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    \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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    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

[[Page 83010]]

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 
royalty-free, on-site use of oil and gas.
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    \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.
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    The BLM has engaged in substantial stakeholder outreach in the 
course of developing this proposal. In 2014, the BLM conducted a series 
of forums to consult with tribal governments and 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 non-governmental 
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-to-government 
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.
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    \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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    The BLM is not the only regulator with the responsibility to 
oversee aspects of onshore oil and gas production, and throughout this 
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 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

[[Page 83011]]

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.
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    \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 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.
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    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.
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    \14\ See 43 CFR 3179.6.
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    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 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 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\
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    \15\ RIA at 3.
    \16\ RIA at 27.
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    Like the proposed rule, the final rule requires operators to use an 
instrument-based 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.
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    \17\ See 40 CFR part 60, appendix A-7.
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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

[[Page 83012]]

unloading, and well drilling and completions.
a. Pneumatic Controllers and Pumps
    We estimate that on BLM-administered 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.
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    \18\ RIA at 4.
    \19\ ICF International, Economic Analysis of Methane Emission 
Reduction Opportunities in the U.S. in the Onshore Oil and Natural 
Gas Industries, 4-4 (Mar. 2014), available at https://www.edf.org/sites/default/files/methane_cost_curve_report.pdf (ICF 2014 Study) 
(base case assumed $4/Mcf price for recovered gas and a 10 percent 
discount rate/cost of capital).
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \20\ RIA at 17.
    \21\ RIA 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.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \23\ RIA at 3.
---------------------------------------------------------------------------

    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 BLM-administered 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

[[Page 83013]]

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 BLM-
administered leases.
---------------------------------------------------------------------------

    \24\ RIA at 3.
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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.
---------------------------------------------------------------------------

    \25\ 30 U.S.C. 226(c)(1).
---------------------------------------------------------------------------

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 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 royalty-free 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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 83014]]

profit margin of 0.15percentage points.\29\
---------------------------------------------------------------------------

    \29\ RIA at 129. These estimates rely on 2014 company data, and 
use a 7 percent discount rate.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

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

    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
    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\
---------------------------------------------------------------------------

    \32\ RIA at 111.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \33\ RIA at 5.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \34\ RIA at 143.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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. 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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 BLM-
administered 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

[[Page 83015]]

stability and undermine respiratory and cardiovascular health.
---------------------------------------------------------------------------

    \37\ The President's Climate Action Plan (June 2013) (https://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf).
---------------------------------------------------------------------------

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
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 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\
---------------------------------------------------------------------------

    \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/ghgrp-petroleum-and-natural-gas-systems.
    \40\ EPA, 2016 GHG Inventory Report: 1990-2014. Available at 
https://www3.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2016-Main-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-methane-emissions-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.
---------------------------------------------------------------------------

    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 oil-well gas increased by 318 
percent, while reported volumes of flared gas-well gas 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\
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    \44\ BLM analysis of ONRR OGOR-B data provided for 2009-2015.
    \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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    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 super-emitter 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.

[[Page 83016]]

    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.
---------------------------------------------------------------------------

    \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/2016-04/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-ghg-inventory-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-oilgas-methane-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/8d49f7ad4bbcf4ef852573590040b7f6/5c432a7068e191e985257f630054fea8!OpenDocument.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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

    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 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.
---------------------------------------------------------------------------

    \49\ Schwietzke, Stefan et al. ``Upward Revision of Global 
Fossil Fuel Methane Emissions Based on 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-finds-fossil-fuel-methane-emissions-greater-than-previously-estimated).
---------------------------------------------------------------------------

    There have also been recent and ongoing studies of so-called 
``super-emitters,'' 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 emission-factor 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\
---------------------------------------------------------------------------

    \50\ Zavala-Araiza, et al., (2015) ``Toward a Function 
Definition of Methane Super-Emitters: Application to Natural Gas 
Production Sites,'' Environ. Sci. Technol., 49, at 8167-8174 
(``Zavala-Araiza (2015)''), available at http://pubs.acs.org/doi/abs/10.1021/acs.est.5b00133.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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/uploadedFiles/Gas_Wells/AirQualityStudy_final.pdf.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \53\ David R. Lyon et. al, Aerial Surveys of Elevated 
Hydrocarbon Emissions from Oil and Gas Production Sites, 1 Envtl. 
Sci. Tech. (2016)
---------------------------------------------------------------------------

    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

[[Page 83017]]

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 high-emitting sites detected in its survey were low 
production sites, producing 15 barrel of oil equivalent (BOE) per day 
or less.\54\
---------------------------------------------------------------------------

    \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 ``Site-level parameter 
data for well pads in the surveyed areas and basins'' file columns M 
and N in the ``Surveyed Well Pads'' worksheet.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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
---------------------------------------------------------------------------

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 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-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

[[Page 83018]]

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 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\
---------------------------------------------------------------------------

    \56\ 79 FR 49490, August 16, 2012.
    \57\ Subpart 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.
---------------------------------------------------------------------------

    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 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 semi-annual 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.
---------------------------------------------------------------------------

    \58\ 80 FR 56593, Sept. 18, 2015.
    \59\ 81 FR 35823, June 3, 2016.
---------------------------------------------------------------------------

    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

[[Page 83019]]

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.
---------------------------------------------------------------------------

    \60\ I.e., nonattainment areas designated ``moderate'' or above.
    \61\ These are the attainment dates for areas designated as 
moderate nonattainment or above.
---------------------------------------------------------------------------

    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 determined that it is necessary and prudent to update and finalize 
this regulation at this time.
---------------------------------------------------------------------------

    \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-cut-methane-emissions-from-existing-oil-and-gas-sources.
    \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.
---------------------------------------------------------------------------

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 BLM-
administered 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.
---------------------------------------------------------------------------

    \65\ 81 FR at 6633-34.
    \66\ 81 FR at 6636.
---------------------------------------------------------------------------

    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. 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 low-emissions 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.
---------------------------------------------------------------------------

    \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.
    \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%201-19-2016%20PDF.pdf.
---------------------------------------------------------------------------

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\
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    \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.
---------------------------------------------------------------------------

    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

[[Page 83020]]

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.
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    \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'').
    \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 16\2/3\%, absent approval of the Secretary. 25 CFR 211.41, 
212.41.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \73\ 30 U.S.C. 225.
    \74\ 30 U.S.C. 187.
    \75\ 30 U.S.C. 1756.
---------------------------------------------------------------------------

    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 surface-disturbing 
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\
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    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \81\ 30 U.S.C. 187.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

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

    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 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\
---------------------------------------------------------------------------

    \86\ 43 U.S.C. 1702(c), 1732(a).
    \87\ 43 U.S.C. 1702(c).
    \88\ 43 U.S.C. 1702(c).
    \89\ 43 U.S.C. 1702(c).
---------------------------------------------------------------------------

    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

[[Page 83021]]

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.
---------------------------------------------------------------------------

    \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.
    \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.
---------------------------------------------------------------------------

    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.

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 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.
---------------------------------------------------------------------------

    \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 outreach-events page: 
http://www.blm.gov/wo/st/en/prog/energy/public_events_on_oil.
---------------------------------------------------------------------------

    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.
    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 waste-prevention 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

[[Page 83022]]

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 
(royalty-free) 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 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 BLM Web site and is part of the rule-making 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.
---------------------------------------------------------------------------

    \98\ BLM analysis of ONRR OGOR-B data provided for 2009-2015 and 
EPA GHG Inventory data for 2014.
---------------------------------------------------------------------------

1. Venting Prohibition
a. Requirements of Final Rule
    First, final rule Sec.  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 Sec.  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 Sec.  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 Sec. Sec.  3179.301-3179.305. 
Venting is also permissible during ``emergencies,'' which final rule 
Sec.  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 Sec.  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 Sec.  3179.4, and thus subject to royalties under final rule 
Sec.  3179.5.

[[Page 83023]]

b. Changes From Proposed Rule and Significant Comments
    The final venting prohibition largely tracks proposed section Sec.  
3179.6, although the BLM modified a few provisions and added additional 
express exemptions in response to comments received. First, proposed 
Sec.  3179.6(a)(3), which exempted gas vented from storage vessels 
subject to conditions specified in Sec.  3179.203, has been renumbered 
Sec.  3179.6(b)(4) and reworded for clarity. Second, proposed Sec.  
3179.6(a)(4), which exempted gas vented during normal operations of 
natural gas-activated pneumatic controllers and pumps, has been 
renumbered Sec.  3179.6(b)(3). Third, the BLM added a provision, final 
rule Sec.  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 Sec.  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 Sec.  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 Sec. Sec.  
3179.301-305. Fifth, the BLM added Sec.  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 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 Sec.  
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 Sec. Sec.  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 Sec. Sec.  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.
---------------------------------------------------------------------------

    \99\ As defined in final rule Sec.  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.
---------------------------------------------------------------------------

    First, in response to comments, the final rule shifts from 
numerical limits on per-well flaring volumes (the approach taken in 
proposed rule Sec.  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 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 Sec.  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 
Sec.  3179.7(b)(1)-(4) and reproduced in Table 1:

                                 Table 1
------------------------------------------------------------------------
                                                               Required
                                                               monthly
                                                               capture
                                                                target
                         Date range                          (percent of
                                                              associated
                                                                 gas
                                                               captured
                                                              per month)
------------------------------------------------------------------------
1/17/2018 through 12/31/2019...............................           85
1/1/2020 through 12/31/2022................................           90
1/1/2023 through 12/31/2025................................           95
Beginning 1/1/2026.........................................           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 Sec.  3179.7(c)(3)(i)), or instead to comply on a county-
wide or state-wide basis (the ``averaging approach,'' see final rule 
Sec.  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 Sec.  3179.7(c), is for an operator to 
determine its total volume of gas produced from development oil wells 
in the relevant

[[Page 83024]]

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 Sec.  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 
Sec.  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).
---------------------------------------------------------------------------

    \100\ As defined in Sec.  3179.7(c)(4), a well is considered 
``in production'' after ``a completion, a completion report, or a 
notice of first production, whichever occurs first, and only during 
a month in which it produces gas (that is sold or flared) for 10 or 
more days.''

                                 Table 2
------------------------------------------------------------------------
                                                               Monthly
                                                               flaring
                         Date range                           allowable
                                                               per well
                                                                (Mcf)
------------------------------------------------------------------------
1/17/2018 through 12/31/2018...............................        5,400
1/1/2019 through 12/31/2019................................        3,600
1/1/2020 through 12/31/2020................................        1,800
1/1/2021 through 12/31/2021................................        1,500
1/1/2022 through 12/31/2023................................        1,200
1/1/2024 through 12/31/2024................................          900
Beginning 1/1/2025.........................................          750
------------------------------------------------------------------------

    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 Sec.  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 Sec.  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 Sec.  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 limit 
of 7,200 Mcf/month per development oil well in production on the lease, 
unit, or communitized area, for the first year the rule was in effect 
(proposed rule Sec.  3179.6(b)(1)); 3,600 Mcf/month per development oil 
well in production on the lease, unit, or communitized area for the 
second year the rule was in effect (proposed rule Sec.  3179.6(b)(2)); 
and 1,800 Mcf/month per development oil well in production on the 
lease, unit, or communitized area for every month beginning in year 
three and thereafter (proposed rule Sec.  3179.6(b)(3)).
    The proposed rule included a broad request for comments on a range 
of issues relating to this section, including: The feasibility and 
costs of imposing a 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 Sec.  3179.7 
for allowing operators to obtain an alternative flaring limit.
    The BLM developed the capture target approach in final rule Sec.  
3179.7, and the alternative capture target provisions in final rule 
Sec.  3179.8, after careful consideration of the many comments received 
on the flaring limit approach set forth in proposed rule Sec. Sec.  
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 
BLM-administered leases, thereby increasing gas capture. We have 
structured final rule Sec. Sec.  3179.7 and 3179.8 to achieve a 
comparable volume of flaring reductions as proposed rule Sec. Sec.  
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 Sec.  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

[[Page 83025]]

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 Sec.  
3179.6(b) and final rule Sec.  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 Sec.  3179.7, therefore, 
requires capture of a specified percentage of gas above the flaring 
allowable volume; this specified capture 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\
---------------------------------------------------------------------------

    \101\ 81 FR at 6634.
---------------------------------------------------------------------------

    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 Sec.  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 Sec.  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 goal was the shift from a fixed long-term flaring limit of 
1,800 Mcf/month/well (proposed rule Sec.  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 Sec.  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 Sec.  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 Sec.  3179.7(c)(3) allows an operator 
to choose whether to comply with the capture targets on a county- or 
state-wide 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\
---------------------------------------------------------------------------

    \102\ 81 FR at 6634.
---------------------------------------------------------------------------

    Fifth and finally, the final rule makes certain changes to the 
alternative flaring provisions (proposed rule Sec.  3179.7, renumbered 
as final rule Sec.  3179.8) in part to address some commenters' 
concerns that the proposed renewable 2-year exemption (proposed rule 
Sec.  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 Sec.  3179.7 as an alternative capture 
target rather than

[[Page 83026]]

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 Sec.  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 month-by-
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 almost a 
50% reduction in flaring by 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 
Sec.  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\
---------------------------------------------------------------------------

    \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, high-pressure 
flaring of the type addressed by the BLM's capture targets in Sec.  
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-routine-flaring-by-2030.
---------------------------------------------------------------------------

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 BLM-administered leases.\104\ 
This quantity of gas would supply nearly 55,000 homes each year.\105\
---------------------------------------------------------------------------

    \104\ RIA at 17.
    \105\ Based on an estimate of 74 Mcf of gas used per household 
per year. See footnote 2.
---------------------------------------------------------------------------

    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 Sec. Sec.  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, 
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
---------------------------------------------------------------------------

    \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, open-ended lines, 
flanges, covers and closed vent systems, thief hatches or other 
openings on a storage vessel, compressors, instruments, and meters.
---------------------------------------------------------------------------

    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,

[[Page 83027]]

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, 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 Sec.  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.
---------------------------------------------------------------------------

    \109\ See 40 CFR part 60, appendix A-7.
---------------------------------------------------------------------------

    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, 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

[[Page 83028]]

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 semi-annual, 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 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 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 15-day 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

[[Page 83029]]

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 cost-effectiveness.
    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[deg] 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 on-
site, 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, 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 low-producing 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 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 cost-effectiveness 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\
---------------------------------------------------------------------------

    \110\ Proposed Rule at __.
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    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 
high- and 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

[[Page 83030]]

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.
---------------------------------------------------------------------------

    \111\ 81 FR at 35856.
---------------------------------------------------------------------------

    In addition, the BLM does not anticipate a significant number of 
individual well shut-ins or any lease-wide 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[deg] 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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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.

[[Page 83031]]

    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 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 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\
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    \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.
---------------------------------------------------------------------------

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

[[Page 83032]]

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 semi-annual inspections is a 
reasonable approach that balances the leak-detection advantages of more 
frequent inspections against the associated costs. Further discussion 
of the cost-effectiveness 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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 83033]]

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 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 un-
electrified. 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 
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

[[Page 83034]]

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 Sec.  60.5411a, and thief 
hatches or other openings on a controlled storage vessel not subject to 
Sec.  60.5395a. Subpart OOOOa has a separate, detailed set of 
requirements in Sec.  60.5411a for sources covered by that section, and 
another set of requirements in Sec.  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, 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-to-monitor 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 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.

[[Page 83035]]

    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 high-emitting 
existing wells as well.\116\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 cost-effective way 
to minimize venting from liquids unloading activities.

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

[[Page 83036]]

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 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 requirements and 
produce the benefits 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.

[[Page 83037]]

    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 emission reduction requirements for 
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 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 Sec.  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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 mineral-development 
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\
---------------------------------------------------------------------------

    \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).

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

[[Page 83038]]

    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 source-
specific 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' Congressionally-granted 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 OOOOa regulations harmonize to the maximum 
extent practicable.
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

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 Sec.  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 royalty-
bearing under the MLA, requires a case-by-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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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. 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\
---------------------------------------------------------------------------

    \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).
    \128\ 30 U.S.C. 1756.
---------------------------------------------------------------------------

    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

[[Page 83039]]

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.
---------------------------------------------------------------------------

    \129\ 30 U.S.C. 225.
    \130\ 30 U.S.C. 189.
    \131\ 30 U.S.C. 187.
    \132\ BLM Form 3100-11 (emphasis added).
    \133\ Coastal Oil & Gas Corp., et al., 108 IBLA 62, 66 (1989).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \134\ Mobil Oil Exploration & Producing Southeast v. United 
States, 530 U.S. 604, 613-20 (2000).
---------------------------------------------------------------------------

    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 royalty-accountability 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 
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 non-Federal 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 
non-Federal 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. Sec.  3161.1.
---------------------------------------------------------------------------

    \135\ 72 FR 10308, 10313 (March 7, 2007).
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \136\ 43 CFR 2881.11.
    \137\ Mineral 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).
---------------------------------------------------------------------------

    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

[[Page 83040]]

currently has just four ROW applications pending.
---------------------------------------------------------------------------

    \138\ Based on internal BLM analysis of North Dakota activity 
from AFMSS queried on April 16, 2015.
---------------------------------------------------------------------------

    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 
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 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

[[Page 83041]]

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 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 Sec.  3103.3-1(a)(1), and do five things: (1) Remove two 
provisions of the existing regulations that are no longer necessary 
(Sec.  3103.3-1(a)(1)(i) and (ii)); (2) add a new Sec.  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.
---------------------------------------------------------------------------

    \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 Sec.  3103.3-1, and for ease of 
reference.
---------------------------------------------------------------------------

    The final rule also renumbers existing Sec.  3103-1(a)(2) and 
(a)(3) as Sec.  3103-1(a)(3) and (a)(4) and makes minor changes to 
existing Sec.  3103-1(a)(3)) (final Sec.  3103-1(a)(4)) for clarity.
    Additionally, the final rule reprints existing Sec. Sec.  3103-1(b) 
and (c), for clarity. Finally, the BLM made a minor revision to Sec.  
3103.3-1(d) from the proposed rule. To improve the clarity of this 
provision, final Sec.  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

[[Page 83042]]

corresponding rate provisions in the MLA. The BLM would engage in 
additional process before raising the rate.
Section 3160.0-5 Definitions
    This amendment to Sec.  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 Sec.  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 conditionally-required 
information includes: A gas pipeline system location map showing the 
proposed well(s); the name and location of the gas processing plant(s) 
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.
    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., Sec.  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

[[Page 83043]]

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
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 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 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, Sec.  3178.5 qualifies the general provisions 
of Sec.  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 Sec.  
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 royalty-free 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,

[[Page 83044]]

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 Sec.  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);
     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 Sec.  
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.
     Any other types of use for operations and production 
purposes which are not identified in Sec.  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 Sec.  
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 Sec.  3178.5 should not require prior approval. The BLM agrees 
and, in response to this and other comments on Sec.  3178.4, moved some 
provisions to Sec.  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 royalty-free 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

[[Page 83045]]

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 Sec.  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 Sec.  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.
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\
---------------------------------------------------------------------------

    \140\ Plains Exploration & Production Co., 178 IBLA 327, 341 
n.16 (2010).
---------------------------------------------------------------------------

    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 
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 Sec.  3178.6 will add 
clarity and consistency in implementation of that ONRR regulation.
---------------------------------------------------------------------------

    \141\ 30 CFR 1202.150(b).
---------------------------------------------------------------------------

    Paragraph (b) of this section identifies circumstances in which, 
despite the general rule articulated in paragraph (a), the BLM will 
consider approving off-lease 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 Sec.  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)

[[Page 83046]]

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 Sec.  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 (on-lease) is royalty-free; however, the 
proportion of the oil or gas used from 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 royalty-free 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 Sec.  3178.6 
as not requiring prior approval. The circumstances described in Sec.  
3178.7 give the BLM the flexibility to approve additional off-lease 
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) 
royalty-free 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 Sec.  3173.12, as well as Sec.  3178.4 through 
Sec.  3178.7 to clarify that royalty-free 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 Sec.  3178.5 or Sec.  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

[[Page 83047]]

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.
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 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 Sec.  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 low-
emitting 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 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, Sec.  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

[[Page 83048]]

definition of ``unavoidably lost.'' Also included in the ``avoidably 
lost'' category is any ``excess flared gas,'' which Sec.  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 Sec. Sec.  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 Sec. Sec.  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 Sec.  3179.204; and (4) 
leaks are considered unavoidable, provided the operator has complied 
with the leak detection and repair requirements of Sec. Sec.  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 Sec.  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 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 
Sec.  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 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.

[[Page 83049]]

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.
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 Sec.  
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 Sec.  3179.204; (6) 
when the gas is vented through a leak where the operator is in 
compliance with Sec.  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 Sec.  3179.203 does not 
require combustion or flaring of the gas; (5) renumbered proposed 
paragraph (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 Sec.  3179.201 
and Sec.  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 Sec.  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 Sec.  3179.7. 
Under Sec.  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 
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 
Sec.  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, Sec.  3179.6 will likely increase 
the number of operators that must measure their flared gas volumes 
under Sec.  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 Sec. Sec.  
3179.102, 3179.103, and 3179.104. Under Sec. Sec.  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 Sec.  3179.4(a)(1)(C). The BLM believes that in many 
instances, the venting prohibition in Sec.  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 Sec.  3179.104, all flaring during subsequent well 
tests that exceeds 24 hours is treated as avoidably lost gas subject to 
royalties under Sec.  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

[[Page 83050]]

and GHG impacts on and from the public lands, pursuant to FLPMA and the 
MLA, as discussed in Section III.C of this Preamble.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 auto-ignition 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 
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 Gas Capture Requirement
    Final rule Sec.  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 Sec.  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 Sec.  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 Sec.  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 high-pressure 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 Sec.  3179.7 after careful 
consideration of the many comments received on the flaring limit 
approach taken in proposed rule Sec.  3179.6(b). The key comments 
received on Sec.  3179.7 and BLM's response to these comments are also 
discussed in Section III.B of this preamble. Additional substantive 
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 on-site 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 re-analysis 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

[[Page 83051]]

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.
---------------------------------------------------------------------------

    \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.
    \144\ M.J. Bradley and Associates. ``Re-analysis of Proposed BLM 
Flaring Reduction Rule; Projected Costs and Benefits''. September 9, 
2016. Pages 13-14.
---------------------------------------------------------------------------

    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.
Section 3179.8 Alternative Capture Requirement
    Section 3179.8 (Sec.  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 Sec.  3179.7. Under Sec.  
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-by-lease, 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 the BLM agrees, that the applicable capture percentage 
under final rule Sec.  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, Sec.  3179.8 was 
revised in the final rule to reflect the shift to gas capture targets 
in final rule Sec.  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 Sec.  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 (Sec.  3179.7(c)), with flaring 
limits changed to capture percentages. The final rule also does not 
contain the renewable 2-year exemption in proposed Sec.  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 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 Sec.  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 Sec.  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

[[Page 83052]]

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 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 Sec.  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 royalty-bearing 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 non-Federal 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 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 
Sec.  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 Sec.  3179.9 (Sec.  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 co-benefits 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

[[Page 83053]]

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 GOR-based 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 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 statistically-
significant 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 GOR-based approach can also produce adequately accurate 
results. A GOR-based 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 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 Sec.  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 royalty-free volumes.
    The BLM does not believe that it is necessary to specify estimation 
methods, as the BLM expects the industry to continue to use well-
understood 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

[[Page 83054]]

protections for confidential business information.
Section 3179.10 Determinations Regarding Royalty-Free Flaring
    This section (which was Sec.  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 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 Sec.  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., third-party 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 BLM-
administered 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.
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 non-Federal 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 Sec.  
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

[[Page 83055]]

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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 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 
Sec.  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 Sec.  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 
Sec.  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 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 cost-
effective 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

[[Page 83056]]

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 
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 Sec.  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 
Sec.  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 Sec.  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 
Sec.  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 Sec.  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 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 Sec.  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

[[Page 83057]]

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 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.
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 Sec.  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 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 Sec.  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 24-hour 
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 
Sec.  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/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

[[Page 83058]]

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 low-pressure 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 Sec.  
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 already routing such exhaust in this 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 low-pressure 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 zero-
bleed 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 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

[[Page 83059]]

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 low-pressure 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 low-pressure 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 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 Sec.  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 zero-bleed 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 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 Sec.  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 pre-existing on-site flare. Moreover, 
because the BLM is not including chemical injection pumps in this final 
rule, operators will need to address far fewer

[[Page 83060]]

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 high-pressure 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 Sec.  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 Sec.  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 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 on-site, 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.
---------------------------------------------------------------------------

    \145\ 81 FR 35851.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \146\ 81 FR 35884.
    \147\ 80 FR 56625.
---------------------------------------------------------------------------

    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 gas-driven 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

[[Page 83061]]

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 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 OOOO or OOOOa'' could encompass storage vessels that 
neither the EPA nor the BLM intended to cover. In the final rule, Sec.  
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 
Sec.  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 Sec.  3179.203(c) to provide a 3-year 
initial compliance period when the operator must replace a storage 
vessel in order to comply with the rule requirements.
    In the proposed rule, Sec.  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, Sec.  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

[[Page 83062]]

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 Sec.  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 Sec.  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.
---------------------------------------------------------------------------

    \148\ See, e.g., 81 FR 6647.
---------------------------------------------------------------------------

    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 Sec.  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, Sec.  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 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 Sec.  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 Sec.  
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 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

[[Page 83063]]

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 Sec.  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 Sec.  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.
---------------------------------------------------------------------------

    \149\ 81 FR 6655-6656.
---------------------------------------------------------------------------

    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 Sec.  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\
---------------------------------------------------------------------------

    \150\ 81 FR 6617-6618.
    \151\ 42 U.S.C. 7411(a)(1).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \152\ 81 FR 35846.
---------------------------------------------------------------------------

Section 3179.301 Operator Responsibility
    This section establishes that the LDAR requirements in Sec. Sec.  
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

[[Page 83064]]

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 Sec.  3179.303. Operators may 
satisfy the requirements of Sec. Sec.  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., 
Sec.  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 Sec.  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 Sec.  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 Sec.  3179.3. 
We also moved the definition of ``site'' from Sec.  3179.303(a) to 
Sec.  3179.301(e) and revised the definition for clarity.
    Additionally, the BLM moved the requirement in proposed Sec.  
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 Sec.  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 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 re-pressurized. 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

[[Page 83065]]

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 cost-effective 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.
---------------------------------------------------------------------------

    \153\ See Luff Exploration Co., 115 IBLA 134 (1990) (upholding 
enforcement action against operator based on noncompliant equipment 
owned and operated by purchaser).
---------------------------------------------------------------------------

    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, 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.
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

    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 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 Sec.  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

[[Page 83066]]

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 Sec.  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.
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 Sec. Sec.  
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 Sec.  3179.303(b) when it can be demonstrated that 
compliance with the requirements of Sec. Sec.  3179.301 through 
3179.305 would cause the operator to cease production and abandon 
significant recoverable oil or gas reserves under the lease.
    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 Sec.  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 Sec.  
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 Sec. Sec.  3179.302(a)(1) and 3179.303(a). The 
BLM also added details of what the Sundry Notice must include at Sec.  
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 
Sec.  3179.303(b) when it can be demonstrated that compliance with the 
requirements of Sec. Sec.  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 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 Sec.  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 Sec.  
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 
Sec.  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.

[[Page 83067]]

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.
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 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 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

[[Page 83068]]

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 Sec.  
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 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.
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    \155\ The actual number is expected to be slightly lower due to 
duplicate entries.
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    The potentially affected entities are likely to fall within one of 
the following industries, identified by the North American Industry 
Classification System (NAICS) codes:

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

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 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.
---------------------------------------------------------------------------

    \156\ RIA at 122.
    \157\ U.S. Census Bureau data does not readily differentiate 
between the number of firms involved in oil development and 
production activities versus gas development and production.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \158\ 13 CFR 121.201.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
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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

[[Page 83069]]

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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    \160\ RIA at 4.
    \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.
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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\
---------------------------------------------------------------------------

    \162\ RIA at 5.
    \163\ RIA at 106.
    \164\ Id.
---------------------------------------------------------------------------

    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.
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\
---------------------------------------------------------------------------

    \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.
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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.
---------------------------------------------------------------------------

    \166\ RIA at 7.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \167\ RIA at 8.
---------------------------------------------------------------------------

    Royalty payments are recurring income to Federal or tribal 
governments and costs to the operator or lessee. As such, they are 
private transfer payments that do not affect the total resources 
available to society. An important but sometimes difficult problem in 
cost estimation is to distinguish between real costs and transfer 
payments. While transfers should not be included in the economic 
analysis of the benefits and costs of a regulation, they may be 
important for describing distributional effects.
c. Small Businesses
    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\
---------------------------------------------------------------------------

    \168\ The BLM conducted a Final Regulatory Flexibility Analysis, 
RIA at 123-136.
---------------------------------------------------------------------------

    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 small-sized entities that currently hold BLM-managed 
oil and gas leases. The BLM ascertained the following information from 
the companies' annual reports to the U.S. Securities and Exchange 
Commission (SEC) for 2012 to 2014. From data in the companies' 10-K 
filings to the SEC, the BLM was able to calculate the companies' profit 
margins \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\
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    \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.
---------------------------------------------------------------------------

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.
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    \171\ Executive Order 13563, Improving Regulation and Regulatory 
Review (Jan. 18, 2011).

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[[Page 83070]]

    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.
---------------------------------------------------------------------------

    \172\ RIA at 118.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \173\ RIA 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.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \177\ Id.
    \178\ Id.
    \179\ RIA at 120.
---------------------------------------------------------------------------

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:
---------------------------------------------------------------------------

    \180\ RIA at 138.
---------------------------------------------------------------------------

    (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 governmental 
jurisdictions, and small not-for-profit enterprises.
---------------------------------------------------------------------------

    \181\ RIA at 167-168.
    \182\ 5 U.S.C. 601-612. The exception is found in 5 U.S.C. 
605(b).
---------------------------------------------------------------------------

    The BLM reviewed the Small Business Administration (SBA) size 
standards for small businesses and the number of entities fitting those 
size standards as reported by the U.S. Census Bureau in the Economic 
Census. The BLM concludes that the vast majority of entities operating 
in the relevant sectors are small businesses as defined by the SBA. As 
such, the rule 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

[[Page 83071]]

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 BLM-administered leases are subject to 
lease terms that expressly require that subsequent lease activities be 
conducted in compliance with applicable Federal laws and regulations. 
The 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.

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.

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-to-government 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.
---------------------------------------------------------------------------

    \183\ More info can be found at: http://www.blm.gov/wo/st/en/prog/energy/public_events_on_oil.html.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \184\ 44 U.S.C. 3501-3521.
---------------------------------------------------------------------------

    This rule contains information collection activities that require 
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 
information-collection 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

[[Page 83072]]

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 Sec.  3178.3 that is not 
identified in Sec.  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, resource-protection, 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 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, unit-by-
unit, or communitized area-by-communitized 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
     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:
    [cir] 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
    [cir] 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.

[[Page 83073]]

    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.
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;
    (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 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

[[Page 83074]]

operator documents in a Sundry Notice that the pump was operated fewer 
than 90 days in the prior calendar year.
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 Sec.  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.
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.
    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 Sec.  
3162.4-1 and make them available to the BLM, upon request.

[[Page 83075]]

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 Sec.  3179.301(a) for gas leaks. Section 
3179.301(k) allows an operator to satisfy the requirements of 
Sec. Sec.  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.
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 Sec.  3179.302(a)(1) when used according to Sec.  
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 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 
instrument-based 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 Sec.  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 
Sec. Sec.  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 
Sec. Sec.  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 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 Sec. Sec.  3179.301-305 and with an alternative leak 
detection program that meets the requirements of Sec.  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 Sec.  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.

[[Page 83076]]

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 Sec.  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 Sec.  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.

                                             Estimated Hour Burdens
----------------------------------------------------------------------------------------------------------------
                                                                                                    Total hours
                        Type of response                             Number of       Hours per      (column B x
                                                                     responses       response        column C)
A.                                                                            B.              C.              D.
----------------------------------------------------------------------------------------------------------------
Plan to Minimize Waste of Natural Gas, 43 CFR 3162.3-1, Form               2,000               8          16,000
 3160-3.........................................................
Request for Approval for Royalty-Free Uses On-Lease or Off-                   50               4             200
 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,             200               1             200
 43 CFR 3179.7(c)(3)(iii).......................................
Request for Approval of Alternative Capture Requirement, 43 CFR               50              16             800
 3179.8(b), Form 3160-5.........................................
Request for Exemption from Well Completion Requirements, 43 CFR                0               0               0
 3179.102(c) and (d), Form 3160-5...............................
Request for Extension of Royalty-Free Flaring During Initial                 500               2           1,000
 Production Testing, 43 CFR 3179.103, Form 3160-5...............
Request for Extension of Royalty-Free Flaring During Subsequent                5               2              10
 Well Testing, 43 CFR 3179.104, Form 3160-5.....................
Reporting of Venting or Flaring, 43 CFR 3179.105, Form 3160-5...             250               2             500
Notification of Functional Needs for a Pneumatic Controller, 43               10               2              20
 CFR 3179.201(b)(1), Form 3160-5................................
Showing that Cost of Compliance Would Cause Cessation of                      50               4             200
 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             100               1             100
 3 Years, 43 CFR 3179.201(d), Form 3160-5.......................
Showing that a Pneumatic Diaphragm Pump was Operated on Fewer                100               1             100
 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,             150               1             150
 43 CFR 3179.202(d), Form 3160-5................................
Showing that Cost of Compliance Would Cause Cessation of                      10               4              40
 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                100               1             100
 within 3 Years, 43 CFR 3179.202(h), Form 3160-5................
Storage Vessels, 43 CFR 3179.203(c), Form 3160-5................              50               4             200
Downhole Well Maintenance and Liquids Unloading--Documentation             5,000               1           5,000
 and Reporting, 43 CFR 3179.204(c) and (e), Form 3160-5.........
Downhole Well Maintenance and Liquids Unloading--Notification of             250               1             250
 Excessive Duration or Volume, 43 CFR 3179.204(f), Form 3160-5..
Leak Detection--Compliance with EPA Regulations, 43 CFR                       50               4             200
 3179.301(j), Form 3160-5.......................................
Leak Detection--Request to Use an Alternative Monitoring Device                5              40             200
 and Protocol, 43 CFR 3179.302(c), Form 3160-5..................
Leak Detection--Operator Request to Use an Alternative Leak                   20              40             800
 Detection Program, 43 CFR 3179.303(b), Form 3160-5.............
Leak Detection--Operator Request for Exemption Allowing Use of               150              20           3,000
 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             100               1             100
 3179.304(a), Form 3160-5.......................................
Leak Detection--Inspection Recordkeeping and Reporting, 43 CFR            52,000             .25          13,000
 3179.305.......................................................
Leak Detection--Annual Reporting of Inspections, 43 CFR                    2,000              20          40,000
 3179.305(b), Form 3160-5.......................................
    Totals......................................................          63,200  ..............          82,170
----------------------------------------------------------------------------------------------------------------


[[Page 83077]]

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.

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

    Under Executive Order 13211, agencies are required to prepare and 
submit to OMB a Statement of Energy Effects for significant energy 
actions. This statement is to include a detailed statement of ``any 
adverse effects on energy supply, distribution, or use (including a 
shortfall in supply, price increases, and increase use of foreign 
supplies)'' for the action and reasonable alternatives and their 
effects.
    Section 4(b) of Executive Order 13211 defines a ``significant 
energy action'' as ``any action by an agency (normally published in the 
Federal Register) that promulgates or is expected to lead to the 
promulgation of a final rule or regulation, including notices of 
inquiry, advance notices of proposed rulemaking, and notices of 
proposed rulemaking: (1)(i) That is a significant regulatory action 
under Executive Order 12866 or any successor order, and (ii) is likely 
to have a significant adverse effect on the supply, distribution, or 
use of energy; or (2) that is designated by the Administrator of (OIRA) 
as a significant energy action.''
    Since the compliance costs for this rule would represent such a 
small fraction of company net incomes, we believe that the rule is 
unlikely to impact the investment decisions of firms. Also, 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.

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

0
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).


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


Sec.  3103.3-1  Royalty on production.

    (a) Royalty on production will be payable only on the mineral 
interest owned by the United States. Royalty must be paid in amount or 
value of the production removed or sold as follows:
    (1) For leases issued on or before 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) 12\1/2\ percent on all noncompetitive leases;
    (ii) A rate of not less than 12\1/2\ percent on all competitive 
leases, exchange and renewal leases, and leases issued in lieu of 
unpatented oil placer mining claims under Sec.  3108.2-4 of this title;

[[Page 83078]]

    (3) 16\2/3\ percent on noncompetitive leases reinstated under Sec.  
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 12\1/2\ 
percent royalty rate.
    (c) The average production per well per day for oil and gas will be 
determined pursuant to 43 CFR 3162.7-4.
    (d) Payment of a royalty on the helium component of gas will not 
convey the right to extract the helium 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

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

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


Sec.  3160.0-5  [Amended]

0
4. Amend Sec.  3160.0-5 by removing the definition of ``Avoidably 
lost.''

0
5. Amend Sec.  3162.3-1 by adding paragraph (j) to read as follows:


Sec.  3162.3-1  Drilling applications and plans.

* * * * *
    (j) When submitting an Application for Permit to Drill an oil well, 
the operator must also submit a plan to minimize waste of natural gas 
from that well. The waste minimization plan must accompany, but would 
not be part of, the Application for Permit to Drill. The waste 
minimization plan must set forth a strategy for how the operator will 
comply with the requirements of 43 CFR subpart 3179 regarding control 
of waste from venting 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 
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;
    (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

0
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.

0
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 royalty-free 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.

[[Page 83079]]

3179.10 Determinations regarding royalty-free 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.


Sec.  3178.1  Purpose.

    The purpose of this subpart is to address the circumstances under 
which oil or gas produced from Federal and Indian leases may be used 
royalty-free in operations on the lease, unit, or communitized area. 
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.


Sec.  3178.2  Scope.

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


Sec.  3178.3  Production on which royalty is not due.

    (a) To the extent specified in Sec. Sec.  3178.4 and 3178.5, 
royalty is not due on:
    (1) Oil or gas that is produced from a lease or 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 Sec.  3178.5, the operator must 
obtain prior written BLM approval for the volumes used for operational 
and production purposes to be royalty free.


Sec.  3178.4  Uses of oil or gas on a lease, unit, or 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;
    (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.


Sec.  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 Sec.  3178.4.
    (b)(1) The operator must obtain BLM approval to conduct activities 
under paragraph (a) of this section by submitting a Form 3160-5, Sundry 
Notices and Reports on Wells (Sundry Notice) containing the information 
required under Sec.  3178.9. If the BLM disapproves a request for 
royalty-free treatment for volumes used under this

[[Page 83080]]

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.


Sec.  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 Sec.  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.


Sec.  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.

    (a) Except as provided in Sec.  3178.6(b) and paragraph (b) of this 
section, royalty is owed on all oil or gas used in operations conducted 
off the lease, unit, or 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 Sec.  3178.4(a) and Sec.  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
    (2) The operations are conducted upstream of the FMP.
    (c) The operator must obtain BLM approval under paragraph (b) of 
this section by submitting a Sundry Notice containing the information 
required under Sec.  3178.9. 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.


Sec.  3178.8  Measurement or estimation of volumes of oil or gas that 
are used royalty-free.

    (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 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.


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

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


Sec.  3178.10  Facility and equipment ownership.

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

Subpart 3179--Waste Prevention and Resource Conservation


Sec.  3179.1  Purpose.

    The purpose of this subpart is to implement and carry out the 
purposes of statutes relating to prevention of waste from Federal and 
Indian (other than Osage Tribe) leases, conservation of surface 
resources, and management of the public lands for multiple use and 
sustained yield. This subpart supersedes those portions of Notice to 
Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases, 
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.


Sec.  3179.2  Scope.

    (a) This subpart applies to:

[[Page 83081]]

    (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.


Sec.  3179.3  Definitions and acronyms.

    As used in this subpart, the term:
    Accessible component means a component that can be reached, if 
necessary, by safe and proper use of portable ladders or by built-in 
ladders and walkways. Accessible components also include components 
that can be reached by the safe use of an extension on a monitoring 
probe.
    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 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 gas-to-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 
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 non-
earthen 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 Sec.  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.

[[Page 83082]]

    (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).


Sec.  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 Sec.  
3179.103;
    (iv) Subsequent well tests, subject to the limitations in Sec.  
3179.104;
    (v) Exploratory coalbed methane well dewatering;
    (vi) Emergencies, subject to the limitations in Sec.  3179.105;
    (vii) Normal operating losses from a natural gas-activated 
pneumatic controller or pump that is in compliance with Sec.  3179.201 
and Sec.  3179.202;
    (viii) Normal operating losses from a storage vessel or other low 
pressure production vessel that is in compliance with Sec.  3179.203 
and Sec.  3174.5(b);
    (ix) Well venting in the course of downhole well maintenance and/or 
liquids unloading performed in compliance with Sec.  3179.204;
    (x) Leaks, when the operator has complied with the leak detection 
and repair requirements in Sec. Sec.  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 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 Sec.  3179.7.


Sec.  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.


Sec.  3179.6  Venting prohibition.

    (a) Gas well gas may not be flared or vented, except where it is 
unavoidably lost pursuant to Sec.  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 Sec.  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 
gas-activated pneumatic controller or pump;
    (4) When the gas is vented from a storage vessel, provided that 
Sec.  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 Sec.  
3179.204;
    (6) When the gas is vented through a leak, provided that the 
operator is in full compliance with Sec. Sec.  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 Sec.  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.


Sec.  3179.7  Gas capture requirement.

    (a) Except as provided in Sec.  3179.8, on a monthly basis, each 
operator must 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:

[[Page 83083]]

    (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 
Sec.  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 high-pressure flaring during the month.


Sec.  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 Sec.  3179.7 on a lease-by-lease, unit-by-unit, or 
communitized area-by-communitized area basis, the BLM may approve a 
capture percentage lower than the applicable capture percentage 
specified under Sec.  3179.7, if the operator demonstrates, and the BLM 
agrees, that the applicable capture percentage under Sec.  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 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.


Sec.  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 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.


Sec.  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.


Sec.  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.

[[Page 83084]]

    (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.


Sec.  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


Sec.  3179.101   Well drilling.

    (a) Except as provided in Sec.  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.


Sec.  3179.102  Well completion and related operations.

    (a) Except as provided in Sec.  3179.6, and unless technically 
infeasible, after a well has been hydraulically fractured or 
refractured, gas that reaches the surface during well completion, post-
completion, 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 Sec.  3179.103(a)(3);
    (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.


Sec.  3179.103  Initial production testing.

    (a) Gas flared during a well's initial production test is royalty-
free under Sec. Sec.  3179.4(a)(1)(iii) and 3179.5(b) of this subpart 
until one of the following occurs:
    (1) The operator determines that it has obtained adequate reservoir 
information for the well;
    (2) 30 days have passed since the beginning of the production test, 
except as provided in paragraph (b) and paragraph (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 Sec.  3179.102(a)(2), except as provided in paragraph (c) of this 
section; or
    (4) Production begins.
    (b) The BLM may extend the period specified in paragraph (a)(2) not 
to exceed an additional 60 days, based on testing delays caused by well 
or equipment problems or if there is a need for further testing to 
develop adequate reservoir information.
    (c) 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.


Sec.  3179.104  Subsequent well tests.

    During well tests subsequent to the initial production test, the 
operator may flare gas for no more than 24 hours royalty free, unless 
the BLM approves or requires a longer period. The operator must request 
a longer period under this section using a Sundry Notice.


Sec.  3179.105  Emergencies.

    (a) An operator may flare or, if flaring is not feasible given the 
emergency, vent gas royalty-free under Sec.  3179.4(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

[[Page 83085]]

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


Sec.  3179.201  Equipment requirements for pneumatic controllers.

    (a) A pneumatic controller that uses natural gas produced from a 
Federal or Indian lease, or from a unit or 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;
    (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.


Sec.  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 zero-emissions 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 zero-emissions 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,

[[Page 83086]]

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.


Sec.  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 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.


Sec.  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;

[[Page 83087]]

    (2) Record the cause, date, time, duration, and estimated volume of 
each venting event; and
    (3) Maintain the records for the period required under Sec.  
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)


Sec.  3179.301   Operator responsibility.

    (a) The requirements of Sec. Sec.  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 Sec. Sec.  3179.301 through 3179.305 of 
this subpart do not apply to:
    (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 Sec. Sec.  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 Sec. Sec.  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 
Sec.  3179.303.
    (h) All leak inspections must occur during production operations.
    (i) The operator must fix identified leaks as prescribed in 
Sec. Sec.  3179.304 and 3179.305 of this subpart. See 43 CFR 3162.5-1 
for responsibility to repair oil leaks.
    (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 Sec. Sec.  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 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.


Sec.  3179.302   Approved instruments and methods.

    (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 Sec.  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 Sec.  3179.302(a)(1) when 
used according to Sec.  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.

[[Page 83088]]

    (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 Sec.  3179.302(a)(1) when used 
according to Sec.  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.


Sec.  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 Sec.  3179.301(a) of this 
subpart for leaks using a leak detection device listed under Sec.  
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 Sec.  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 Sec. Sec.  
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 Sec.  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 
Sec. Sec.  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 
Sec. Sec.  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 Sec. Sec.  3179.301-305, including 
the option for compliance with an alternative leak detection program 
under Sec.  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 Sec.  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 Sec. Sec.  3179.301-305 and with an alternative leak 
detection program that meets the requirements of Sec.  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 under Sec.  3179.303(b), except that 
in lieu of the demonstration required under Sec.  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.


Sec.  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 Sec.  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 Sec.  3179.303.

[[Page 83089]]

Sec.  3179.305   Leak detection inspection recordkeeping and reporting.

    (a) The operator must maintain the following records for the period 
required under Sec.  3162.4-1 of this title and make them available to 
the BLM upon request:
    (1) For each inspection required under Sec.  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 follow-up inspection(s) required 
under Sec.  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.

State or Tribal Variances


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

    (a)(1) At the request of a State (for Federal land) or a tribe (for 
Indian lands), the BLM State Director may grant a variance from any 
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 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