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Federal Register / Vol. 89, No. 79 / Tuesday, April 23, 2024 / Rules and Regulations
DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3000, 3100, 3110, 3120,
3130, 3140, 3150, 3160, 3170, and 3180
[BLM_HQ_FRN_MO4500176829]
RIN 1004–AE80
Fluid Mineral Leases and Leasing
Process
Bureau of Land Management,
Interior.
ACTION: Final rule.
AGENCY:
The Bureau of Land
Management (BLM) is revising its oil
and gas leasing regulations. Among
other changes, the final rule implements
provisions of the Inflation Reduction
Act (IRA) pertaining to royalty rates,
rentals, and minimum bids; updates the
bonding requirements for leasing,
development, and production; and
revises some operating requirements.
The final rule will improve the BLM’s
leasing process by ensuring proper
stewardship of public lands and
resources.
SUMMARY:
The final rule is effective on June
22, 2024.
FOR FURTHER INFORMATION CONTACT:
Yvette M. Fields, Division Chief, Fluid
Minerals Division, telephone: 240–712–
8358, email: [email protected], or by mail
1849 C St. NW, Washington, DC 20240,
for information regarding the substance
of this final rule.
Individuals in the United States who
are deaf, deafblind, hard of hearing, or
have a speech disability may dial 711
(TTY, TDD, or TeleBraille) to access
telecommunications relay services.
Individuals outside the United States
should use the relay services offered
within their country to make
international calls to the point-ofcontact in the United States. For a
summary of the final rule, please see the
final rule summary document in docket
BLM–2023–0005 on
www.regulations.gov.
DATES:
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SUPPLEMENTARY INFORMATION:
I. List of Acronyms
II. Executive Summary
III. Discussion of Public Comments on the
Proposed Rule
IV. Overview of Modifications to the
Proposed Rule
V. Procedural Matters
List of Acronyms
APD = Application for Permit to Drill
BLM = Bureau of Land Management
BOEM = Bureau of Ocean Energy
Management
CA = Communitization Agreement
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CD = Certificate of Deposit
CFR = Code of Federal Regulations
DOI = Department of the Interior
E.O. = Executive Order
EOI = Expression of Interest
FLPMA = Federal Land Policy and
Management Act
GAO = Government Accountability Office
GHG = Greenhouse Gas
IBLA = Interior Board of Land Appeals
IIJA = Infrastructure Investment and Jobs Act
of 2021
IM = Instruction Memoranda
IRA = Inflation Reduction Act of 2022
LOC = Letter of Credit
MLA = Mineral Leasing Act of 1920, as
amended (MLA is also referred to as ‘‘Act’’
in the regulations.)
MLAAL = Mineral Leasing Act for Acquired
Lands of 1947, as amended
MLRS = Mineral and Land Records System
NAICS = North American Industry
Classification System
NEPA = National Environmental Policy Act
OIG = Office of the Inspector General
ONRR = Office of Natural Resources
Revenue
PRA = Paperwork Reduction Act
RIA = Regulatory Impact Analysis
RMP = Resource management plan
ROW = Right-of-way
SBA = Small Business Administration
U.S.C. = United States Code
Executive Summary
On July 24, 2023, the BLM published
a proposed rule to amend the
regulations in 43 CFR parts 3000, 3100,
3110, 3120, 3130, 3140, 3150, 3160,
3170, and 3180 in the Federal Register
(88 FR 47562), with a 60-day comment
period. Generally, the comments
supported this rulemaking and
expressed the view that the changes
outlined by the proposed rule will be
helpful. Comments on specific sections
of the proposed rulemaking opposed
certain provisions and recommended
changes. Within this preamble, the BLM
discusses those comments and the
BLM’s responses.
Overall, this rule will enhance the
BLM’s administration of oil and gasrelated activities on America’s public
lands and reflects Congress’s changes to
the oil and gas program in the IRA.
Specifically, the rule will reflect
requirements of the IRA by increasing
royalty rates, rentals, and minimum bids
for BLM-issued oil and gas leases, and
by imposing a fee for the submittal of an
expression of interest (EOI) for leasing
Federal oil and gas. The rule also
updates the bonding requirements for
leasing, development, and production to
address shortcomings identified in
reports by the Government
Accountability Office (GAO) and the
Department of the Interior’s (DOI’s)
Office of Inspector General (OIG).
Collectively, the BLM proposed these
changes to bring the regulations into
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compliance with the IRA and the
Infrastructure Investment and Jobs Act
(IIJA) mandates and to ensure that
reclamation costs are not borne by the
American public. The BLM is also
adjusting its cost recovery mechanisms
so that project applicants provide a
more appropriate share of the BLM’s upfront costs for processing these
applications. Finally, the BLM is
implementing several changes to focus
leasing on areas with fewer resource
conflicts. The BLM’s final rule will be
the first comprehensive update to the
Federal onshore oil and gas program’s
regulatory framework since 1988.
The Secretary of the Interior manages
the Federal onshore oil and gas program
pursuant to the requirements of various
statutes, including the Federal Land
Policy and Management Act of 1976, as
amended (43 U.S.C. 1701 et seq.)
(FLPMA); the Mineral Leasing Act of
1920, as amended (30 U.S.C. 181 et seq.)
(MLA or Act); and the Mineral Leasing
Act for Acquired Lands of 1947, as
amended (30 U.S.C. 351 et seq.)
(MLAAL), as well as the recently
enacted IRA (Pub. L. 117–169 (2022))
and IIJA (Pub. L. 117–58 (2021)). Under
section 102 of FLPMA (43 U.S.C.
1701(a)(7)), the BLM manages
approximately 245 million acres of
public lands and approximately 700
million acres of federally owned
subsurface minerals ‘‘on the basis of
multiple use and sustained yield.’’
FLPMA’s definition of ‘‘multiple use’’ in
section 103 (43 U.S.C. 1702(c)) requires
the BLM to achieve ‘‘a combination of
balanced and diverse resource uses that
takes into account the long-term needs
of future generations for renewable and
non-renewable resources.’’ Oil and gasrelated activities are one of the multiple
uses that FLPMA authorizes and which
the BLM administers in accordance with
the MLA and MLAAL. Both of those
Acts govern the leasing of public lands
to explore for and develop oil, natural
gas, coal, and other hydrocarbons,
amongst other mineral deposits.
Discussion of Public Comments on the
Proposed Rule
The public comment period for the
proposed rule ended on September 22,
2023. During the 60-day public
comment period, the BLM received over
215,000 comments submitted by
Federal, State, and local governments,
local agencies, Tribal organizations,
industry representatives, individuals,
and other external stakeholders. The
vast majority of submissions were form
letters. Commenters also submitted
roughly 1,000 unique letters. From all
submissions, the BLM identified
approximately 1,200 unique comments
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raising specific issues on the proposed
rule.
The BLM carefully reviewed all
comments received on the proposed
rule. Certain comments suggesting that
the BLM address issues outside the
scope of this rulemaking are discussed
in Section III.A.
The BLM categorized the remaining
comments received and provides an
overview of those categories and
associated responses in Section III.B.
The BLM provides more detailed
discussions of those comments in
Section IV.B. The Federal Government
posts all comments at the Federal
eRulemaking portal: http://
www.regulations.gov. To access the
comments at that website, enter 1004–
AE80 in the Search box and select the
Fluid Mineral Leases and Leasing
Process proposed rule.
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A. Comments Outside the Scope of This
Rulemaking
The BLM received many comments
directed at matters outside of the scope
of this rulemaking, including those
regarding: project-specific
considerations; the BLM’s existing
website or computer application
programs (e.g., Automated Fluid
Mineral Support System, National Fluid
Lease Sale System, etc.); additional
rulemaking or programmatic
environmental impact statements
specific to greenhouse gas (GHG)
emissions; geothermal or helium leasing
activities; and additional operational
provisions in 43 CFR part 3160 or
additional unit provisions in 43 CFR
part 3180 that were not part of the
proposed rule. Other commenters
recommended changes to national
energy policies and priorities, such as to
halt all oil and gas leasing activities due
to climate change, or discussed matters
not specific to the BLM’s administration
of oil and gas leasing. Many comments
expressed general statements of support
or opposition to the rule. The BLM has
not responded to these comments in
detail, because these myriad matters
were not encompassed in the proposed
rule and are best addressed, if at all,
through future rulemakings.
A commenter stated that the BLM
failed to write this entire rule in a
manner that is easily understood
without providing any examples to
support the assertion. When drafting the
proposed and final rules, the BLM
reviewed the rule text to identify areas
where the regulations could be written
more clearly and made changes as
necessary.
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B. Categorized Public Comments on the
Proposed Rule
This section of the preamble
summarizes the major categories of
public comments that the BLM received
in response to the proposed rule, as well
as the BLM’s responses.
1. Comments Recommending
Additional Oil and Gas Rulemaking, or
Policy Development
Summary of comments: Multiple
commenters recommended that the
BLM initiate additional rulemaking
efforts or develop additional policy that
are beyond the scope of this rulemaking.
These recommendations include: (1) a
rule to update the BLM’s unitization
process in part 3180; (2) a rule to update
the BLM’s permitting process in 43 CFR
part 3160; (3) development of ‘‘The
Bureau of Land Management’s Blueprint
for 21st Century Outdoor Recreation’’;
(4) updated policy related to oil and gas
lease suspension; (5) updated policy
related to oil and gas unitization; (6) a
similar joint rulemaking between the
BLM and the Bureau of Indian Affairs;
and (7) a bureau-wide review of its
standard stipulation lists.
Response: The BLM reviewed these
comments and determined that the
requested changes are outside the scope
of this rulemaking. With respect to the
comments recommending the BLM
update the unitization portion of the
regulations at part 3180, the BLM made
changes to the final rule to implement
the increased royalty rate mandated by
Congress in the IRA but did not propose
any changes to the remaining
unitization provisions. As the BLM did
not propose any changes in the
proposed rule, the public was not
provided with a chance to comment on
any other changes to the regulations
governing unitization. As it reviews its
current policy in light of this rule’s
changes, the BLM will determine
whether to implement any changes to its
approval process for lease suspensions.
Although a comment requested that the
BLM review and standardize a list of
lease stipulations, in addition to the
terms and conditions in the BLM’s
standard form oil and gas lease, the
BLM develops lease stipulations as part
of its resource management planning
process (which includes analysis under
NEPA and other statutes), in which the
public has opportunities to comment,
and those stipulations apply to oil and
gas leases issued within each RMP area.
Any site-specific concerns can be
addressed through the NEPA process for
a particular sale or through conditions
of approval at the Application for
Permit to Drill (APD) stage.
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During the comment period, the BLM
received comments requesting
additional updates to parts 3160 and
3170. As part of its review under
Executive Order (E.O.) 14008, issued on
January 27, 2021, the Department
reviewed the onshore oil and gas leasing
program and published the Report on
the Federal Oil and Gas Leasing
Program on November 26, 2021. The
Report on the Federal Oil and Gas
Leasing Program recommended that the
BLM should reform its royalty rate,
minimum bonus bids, rental rates, and
bonding amounts; establish new
requirements for bidders; and take steps
to discourage nominations of lowpotential lands. When the BLM drafted
the proposed rule, the BLM considered
any critical permitting or operational
changes to parts 3160 and 3170 that
were needed in response to the Report’s
recommendation to reduce speculation
but did not propose any changes to the
remaining provisions. As the BLM did
not propose any changes to parts 3160
and 3170, outside of the limited changes
in the proposed rule, the public was not
provided with a chance to comment on
any other changes to the regulations
governing permitting or operations.
As noted above in the summary of
comments outside the scope of this
rulemaking effort, the BLM received a
comment requesting the development of
a blueprint for outdoor recreation. Such
a revision is beyond the scope of this
rulemaking as it would involve revising
regulations in Title 43 of the CFR,
Subchapter H, and those regulations do
not pertain to oil and gas leasing and
development, which is the focus of this
effort. Finally, a joint rulemaking
between the BLM and the Bureau of
Indian Affairs is outside the scope of
this rulemaking effort.
2. Comments on Greenhouse Gas
Emissions and Climate Change
Summary of comments: In the
proposed rule, the BLM requested
comment on whether the preference
criteria in § 3120.34 or other portions of
the proposed rule should be expanded,
or new provisions added, to discuss
analysis of GHG emissions and related
decision making based on that analysis.
The BLM received many comments
recommending different approaches,
including:
• Not changing the rule to address
GHG emissions and climate change on
the grounds that the NEPA review
process at the project level provides a
sufficient review for climate change
issues, and that refraining from leasing
Federal minerals will not change the
demand for oil and gas production;
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• Amending the rule to forgo future
leasing based upon the need to avoid
exceeding the world’s pre-industrial
global temperature level by 1.5 degree
Celsius;
• Setting lease rates based on the
Social Cost of Carbon calculated by the
U.S. Environmental Protection Agency
in November 2022 at a discount rate of
1.5 percent;
• Aligning the oil and gas program
with President Biden’s climate goals;
• Limiting GHG emissions via
emissions monitoring;
• Implementing a three-stage leasing
process to prioritize lands for leasing
with a final climate screening;
• Creating a carbon budget for the
Federal onshore oil and gas program;
• Requiring climate change
mitigation, analyzing climate impacts
across BLM-managed lands, or
implementing a rule to ensure climate
protection for all new leasing and
permitting decisions;
• Initiating a programmatic
environmental impact statement for the
onshore oil and gas program to assess
the potential GHG impacts;
• Establishing a quantitative climate
test tool to evaluate the relative impact
and significance of GHG emissions at
the project level; and
• Expanding the competitive leasing
preference criteria for conformity with
State policies on GHG emissions.
Response: Climate change is a global
process that is affected by the sum total
of GHGs in the Earth’s atmosphere. The
BLM acknowledges the views and
suggestions reflected in these comments
and recognizes that GHG emissions from
the Federal onshore oil and gas program
contributes to climate change. After
reviewing the comments received, the
BLM did not make any changes to the
final rule to address GHG emissions and
climate change. In this rule, the BLM
implements regulatory modifications
required by Congress in the IRA and
other revisions that aim to improve the
leasing process and ensure proper
management of public lands and
resources. These reforms are not focused
on climate change. For example, the
majority of these regulations cover the
administration of an oil and gas lease,
such as changes to the fixed filing fees,
the fiscal terms mandated by Congress,
the type of lease the BLM can issue
(eliminating noncompetitive leases as
mandated by Congress), and the method
by which the public requests lands to be
considered for leasing (formal
nominations vs. expressions of interest).
In implementing the MLA’s requirement
to hold quarterly lease sales when lands
are eligible and available, the BLM will
continue to use the NEPA review
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process and guidance issued by the
Council on Environmental Quality to
evaluate GHG emissions that result from
oil and gas leasing and development
and its effects on climate change. The
BLM understands the commenters’
suggestions and may proceed with those
suggestions in future rulemakings that
more directly address GHG emissions.
Further responses to comments related
to the preference criteria specifically are
addressed in section IV.B.12 of the
preamble.
3. Comments Recommending the BLM
Stop All Oil and Gas Lease Sales and
Permitting
Summary of comments: Multiple
commenters recommended that the
BLM stop, or phase out, all oil and gas
lease sales, the issuance of leases, as
well as permitting and development,
due to climate change and the GHG
emissions from oil and gas
development.
Response: Pursuant to the IRA, the
BLM is required to conduct lease sales
in order to permit wind and solar energy
development projects on public lands.
The approach suggested by the
commenters thus would require the
BLM to stop desirable wind and solar
development. In implementing the
MLA’s requirement to hold quarterly
lease sales when lands are eligible and
available, the BLM will continue to use
the NEPA review process to evaluate
GHG emissions that result from oil and
gas leasing and development and its
effects on climate change.
4. Comments on Public Participation
Summary of comments: Tribes, States,
and local governments submitted
comments requesting that the BLM
update the rule to provide additional
consultation and outreach to them on
oil and gas leasing and development.
Some comments encouraged the BLM to
coordinate with the relevant State and
county agencies when land-use actions
are taken or if the BLM is considering
leasing lands adjacent to State-owned or
managed lands. Other comments
requested that the BLM explore
opportunities for Tribal cultural site
protection and co-stewardship to ensure
the BLM fully advances opportunities
for the incorporation of Indigenous
Knowledge, respect for Tribal
sovereignty and treaty rights, and the
protection of Tribal cultural sites.
Comments also recommended that the
BLM consult the State or local
government’s land use plans to ensure
the BLM applies the appropriate
provisions to responsibly manage
natural resources, climate, and
environmental quality issues during the
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decision making and planning efforts for
oil and gas leasing.
Response: The BLM will continue to
engage with the public, Tribes, Federal,
State, and local government partners on
the BLM’s management of its public
lands, as appropriate. Subsequent
actions that the BLM may take will be
subject to the applicable policies, laws,
and regulations pertaining to that
action, including those for consultation
and environmental review. The BLM
added language into the competitive
leasing process (see § 3120.42) to
include scoping, comment, and protest
periods to ensure that the BLM provides
adequate time to evaluate the views of
a wide range of partners, stakeholders,
and landowners in any future decisions.
Furthermore, in formulating or
amending its resource management
plans (RMPs), the BLM complies with
FLPMA, NEPA, and its regulations
providing for public participation,
coordination of planning efforts, and
consistency. See 43 CFR 1610.2, 1610.3–
1, 1610.3–2. The RMPs serve as
blueprints to enable the BLM to sustain
the health, diversity, and productivity of
public lands for the use and enjoyment
of present and future generations. Under
an RMP, the BLM will identify the lands
closed to leasing of Federal oil and gas,
the lands open to leasing of Federal oil
and gas, and the appropriate
stipulations to apply to a Federal oil and
gas lease based upon the location of the
lease. These decisions are not made as
part of this rulemaking and will
continue to be made through the BLM’s
land use planning process, which
involves cooperating with State and
local governments, consulting with
Tribes, and robust public engagement.
The BLM takes its responsibilities to
Tribes seriously and respects Tribal
sovereignty and treaty rights. Where
there are such opportunities, the BLM is
committed to exploring co-stewardship
opportunities with Tribes. However, costewardship is outside the scope of this
rulemaking.
5. Comments on the BLM’s Discretion
To Offer Parcels for Lease Sales
Summary of comments: Multiple
commenters stated that the rule
improperly limits and discourages
exploration or closes off lands to leasing
outside of the NEPA process. These
commenters pointed to different aspects
of the rule to support their claim that
the rule limits and discourages
exploration. Some comments stated that
the rule violates, or evades, the
multiple-use mandate of FLPMA or
exceeds the authority of the BLM under
the MLA. Other comments stated that
when a person requests the BLM
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include certain lands in an upcoming
competitive oil and gas lease sale (via
EOI) the BLM should offer all lands
described in the EOI in the next
available sale based on and consistent
with the management decisions made in
the relevant RMPs. Multiple comments
stated that the new preference criteria
(see § 3120.32) will create uncertainty,
conflicts among stakeholders and uses,
and will hinder the BLM’s ability to
achieve the congressional mandates
such as offering enough acreage for oil
and gas leasing in order to allow wind
and solar right-of-way (ROW) permit
issuance.
Response: With respect to contentions
that the BLM’s proposed regulations
exceed the Secretary’s authority to
select lands for leasing, the BLM notes
that the MLA, 30 U.S.C. 226(a), by
providing that the Secretary ‘‘may’’
lease lands, necessarily provides the
BLM with broad discretion in
determining precisely which lands and
parcels the BLM will offer at an oil and
gas lease sale. Accordingly, the agency
has, since at least 1988, consistently
applied a public interest determination
to any such decisions. See 53 FR 22828
(June 17, 1988) (‘‘It is Bureau policy
prior to offering the lands to determine
whether leasing will be in the public
interest.’’). The MLA does not specify
how and when this decision is to be
made, and both the Supreme Court and
the U.S. Court of Appeals for the Tenth
Circuit have recognized the Secretary’s
discretion in this sphere. See Udall v.
Tallman, 380 U.S. 1, 4 (1965); W. Energy
All. v. Salazar, 709 F.3d 1040, 1044
(10th Cir. 2013).
Comments asserting that the
application of the preference criteria
will result in the closure of any lands to
oil and gas leasing are incorrect. The
BLM has and will continue to make
land use decisions at the land use
planning stage and document those
decisions in the applicable RMP. The
preference criteria, on the other hand,
were proposed consistent with the MLA
to direct the BLM’s administrative
resources to leasing tracts most likely to
be developed, to reduce conflicts
between oil and gas development and
other public land uses that were not
resolved in the resource management
plans, and to ‘‘take[ ] into account the
long-term needs of future generations
for renewable and nonrenewable
resources,’’ 43 U.S.C. 1702. These
criteria may be considered on a case-bycase basis in light of specific
circumstances. Even if the BLM were to
apply such criteria and decide to defer
including particular lands from any
particular lease sale, nothing in this rule
prevents those lands from being offered
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in future sales. The RMPs do not always
resolve all conflicts, especially those
that may be unforeseen or arise due to
a change in circumstances. In many
cases, this calls for a more specific site
review, and the MLA provides the
necessary discretion, apart from
FLPMA, to engage in this type of sitespecific review.
6. Comments Recommending BLM
Processes Should Be Addressed in
Policy and Not Regulations
Summary of comments: The BLM
received multiple comments stating that
many of the BLM processes in the
proposed rule should instead be
expressed in policy documents and that
the rule goes beyond the authority of the
BLM under the IRA and IIJA. Comments
expressed the view that the function of
regulations is to inform and instruct the
public with regard to actions that they
may or may not take while policy
interprets those regulations and
provides guidance to the agency in
implementing them. The commenters
stated that inserting existing policy
guidance, which applies only to the
BLM’s actions, into the regulations,
rather than leaving it in Instruction
Memoranda (IM), is inappropriate. For
example, commenters suggested that the
preference criteria and the details
regarding lease suspensions belong in
BLM guidance documents and not in
the regulations as these do not impose
any requirements on the oil and gas
industry. Finally, the commenters stated
that the BLM does not need to update
the existing regulations governing the
BLM’s discretionary functions under the
existing regulations, since those
regulations are adequate to protect the
fiscal interests of the American public.
These commenters recommended that
the BLM only make the changes
required by the IRA.
Response: By incorporating
provisions such as the preference
criteria and lease suspensions into the
regulations, the BLM makes those
provisions legally binding and provides
greater certainty and transparency to the
public on the decision-making processes
the BLM will use when it processes
EOIs (see § 3120.32) and the timeframes
for lease suspensions (see § 3165.1).
These regulatory criteria may influence
a person’s decision-making when
deciding whether they will submit an
EOI or may influence lessees when they
are deciding whether to seek a lease
suspension. Therefore, the BLM
declines to make any changes to the
final rule based upon concerns that the
changes could be characterized as
guidance.
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7. Comments on Environmental Justice
Summary of comments: Multiple
commenters stated that the BLM should
ensure that the final rule includes
environmental and social justice
considerations as part of the oil and gas
leasing process. Comments stated that
many of the fluid mineral resources are
located in underserved rural areas and
on Tribal lands where the fluid mineral
industry has a large economic impact.
These comments alleged that the rule
could undercut environmental justice
goals by reducing the economic benefits
that would otherwise flow to
disadvantaged communities as a result
of onshore Federal oil and gas activities.
One comment stated that jobs in
extractive industries, such as oil and gas
development, are not going to the
members of the communities burdened
by the fossil fuel industry and therefore
that the BLM should end the Federal
fossil fuel leasing program. Another
comment stated that the BLM should
solicit the knowledge and experience of
those in underserved communities and
ensure that these communities’
perspectives are meaningfully
incorporated into and actively shape
planning and decision-making, and the
BLM should take into account
community-driven and localized health
impact assessments and relevant local
health and demographic data as part of
this process. Another comment
recommended that the BLM incorporate
environmental justice as part of
§ 3120.32.
Response: The BLM reviewed the
comments recommending changes to
the rule to address environmental
justice concerns and determined that no
changes were necessary. The BLM
believes environmental justice concerns
are initially addressed through the land
use planning process when the BLM is
evaluating whether lands should be
open to leasing and what stipulations
should be imposed, and then at the
more site-specific level when identified
parcels are being evaluated for possible
inclusion in a lease sale. Both of these
processes also involve an evaluation
under NEPA, which provides an
opportunity for considering
environmental justice concerns, which
are dependent on the specific
conditions and history pertaining to
each area and the communities
potentially impacted. In addition, the
preference criteria that the BLM is
including in this final rule will provide
a tool for the BLM to assess
environmental justice concerns through
government-to-government consultation
and through scoping comments received
from the public. To the extent a
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comment noted a specific
environmental-justice-related concern
with a particular section of the rule, the
BLM has also addressed such comments
in the following Section-by-Section
Discussion.
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8. Comments on the Impact of the Rule
on Indian Leases
Summary of comments: The BLM
received a comment stating that the
proposed rule preamble incorrectly
stated that the rule ‘‘will not impact the
leasing of Indian minerals.’’ The
comment asserted that the rule would
impact Indian interest, lands, and
minerals, and that the BLM needs to
clarify this in the final rule. The BLM
also received comments stating that the
rule should be revised to clarify that
public lands managed by the BLM
under FLPMA and do not include
Indian lands; that the rule should
eliminate BLM activities on Indian
lands; and, that the BLM lacks authority
to manage activities on Indian lands.
Response: The BLM does not make
leasing decisions for Indian lands.
However, the BLM does make
recommendations for oil and gas
operations that may impact Indian
lands. Existing regulations at 43 CFR
part 3100 outline the BLM’s authority
over offering lands to lease under the
BLM’s jurisdiction, which does not
include Indian lands. The changes made
in this rulemaking clearly fall within the
BLM’s existing statutory authorities.
The BLM acknowledges that some of the
proposed changes may affect Indian
lands when the BLM makes
recommendations for oil and gas
operations to the Bureau of Indian
Affairs under the Standard Operating
Procedures between agencies for the
leases they manage under their
respective jurisdictions. While the
majority of the changes in the final rule
impact the leasing of Federal minerals
and not Indian leases, there are some
provisions that will apply to Indian
leases: the operational changes for shutin and temporarily abandoned wells at
§ 3162.3–4 and the changes to the APD
timeframe at § 3171.14. The BLM has
also increased filing fees to account for
inflation for applications such as APDs,
as required by 30 U.S.C. 191. The BLM
considers these updates critical for both
Federal and Indian minerals because
these changes will give the BLM the
ability to complete operator-diligence
reviews, ensure that wells are producing
on Indian leases as required by law, and
to recover its costs to process
applications.
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9. Comments on the Rule Potentially
Discouraging Federal Exploration and
Development
Summary of comments: Multiple
commenters expressed concerns that the
proposed rule would discourage or
eliminate future oil and gas exploration
and development on Federal lands or
would force production from Federal
lands onto State or private lands. The
BLM also received comments asserting
that the combination of proposed
§ 3120.32 (reflecting the BLM’s
authority to defer certain parcels) and
the increased fees, royalties, and
bonding would result in the BLM
violating its statutory requirements to
prevent waste of the oil and gas
resource. Specifically, the commenter
claimed that provisions in this rule,
such as the competitive leasing
preference criteria at § 3120.32, could
result in delays in or the complete
exclusion of the development of nonFederal minerals in addition to the loss
in Federal bonuses and royalties. These
commenters also asserted that this rule
fails to recognize studies indicating that
the United States will continue to need
fossil fuels for the foreseeable future.
The commenters urged the BLM to look
for ways to increase energy
development. Commenters also stated
that the proposed rule ignored the
economic benefit provided by oil and
gas development to local schools,
hospitals, and infrastructure.
Response: The GAO and the DOI OIG
reviewed and audited the BLM’s Federal
onshore oil and gas program to identify
problematic areas in this program and
recommended actions to address them.
Both the GAO’s and OIG’s audits 1
highlighted weaknesses in the onshore
program’s fiscal framework and
recommended that the BLM take steps
to ensure that the American public
receives a fair return from oil and gas
activities on public lands. The DOI and
the BLM concurred with these
recommendations in the Report on the
1 See, e.g., OIG, ‘‘Inspector General’s Statement
Summarizing the Major Management and
Performance Challenges Facing the U.S. Department
of the Interior’’ (Nov. 2022); GAO, ‘‘OIL AND GAS
LEASING—BLM Should Update Its Guidance and
Review Its Fees’’ (Nov. 2021); GAO, ‘‘OIL AND
GAS—Onshore Competitive and Noncompetitive
Lease Revenues’’ (Nov. 2020); GAO, ‘‘FEDERAL
ENERGY DEVELOPMENT—Challenges to Ensuring
a Fair Return for Federal Energy Resources’’ (Sept.
2019); GAO, ‘‘OIL AND GAS—Bureau of Land
Management Should Address Risk from Insufficient
Bonds to Reclaim Wells’’ (Sept. 2019); GAO, ‘‘OIL
AND GAS LEASE MANAGEMENT—BLM Could
Improve Oversight of Lease Suspensions with Better
Data and Monitoring Procedures’’ (June 2018); OIG,
‘‘Bureau of Land Management’s Idle Well Program’’
(Jan. 2018).
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Federal Oil and Gas Leasing Program 2
issued in November 2021.
Accordingly, the BLM is adjusting its
oil and gas bonding requirements,
including by increasing minimum bond
amounts for the first time in decades.
The BLM is proposing to adjust its cost
recovery mechanisms to account for
changes in the leasing process since the
fees were initially set in 2005. The BLM
drafted the proposed rule to: (1) reflect
the requirements of the IRA; and (2)
enhance the administration of the
onshore program, to direct leasing to
lands with a higher development
potential, and in response to the GAO’s
and OIG’s numerous reports identifying
shortcomings in the program, as
discussed in the November 2021 Report
on the Federal Oil and Gas Leasing
Program.
The BLM did not make any changes
to the final rule based upon the
comments expressing concerns that the
increased bonding and fees could result
in the potential movement of
production from Federal to State or
private lands. The royalty rates on State
and private lands are often higher than
those for Federal lands as are the rental
rates.3 Given this, the BLM does not
believe the increased rates will have the
asserted affect and instead will bring the
rates more in line with one another
across jurisdictions. Moreover,
§ 3120.32 does not affect longstanding
BLM policies that prioritize leasing
parcels subject to drainage (from
adjacent State and private minerals); the
BLM will continue to work towards
leasing lands that will allow for logical
development of the minerals by giving
preference to lands after accounting for
expected yields of oil and gas, fair
return for U.S. taxpayers, and decisions
embodied by the BLM’s RMPs. This will
provide for continued development of
Federal, State, and private minerals.
IV. Overview of Modifications to the
Proposed Rule
A. Summary of Notable Changes
The BLM made changes to the rule in
response to comments and for accuracy,
clarity, or grammar.
The BLM received numerous
comments on the proposed changes to
the bonding regulations under subpart
3104, and in response to these
comments, the BLM reinstated an
operators’ ability to post personal bonds
secured with letters of credit (LOCs) and
2 DOI, ‘‘Report on the Federal Oil and Gas Leasing
Program’’ (Nov. 2021). https://www.doi.gov/sites/
doi.gov/files/report-on-the-federal-oil-and-gasleasing-program-doi-eo-14008.pdf.
3 DOI, ‘‘Report on the Federal Oil and Gas Leasing
Program’’ (Nov. 2021).
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certificates of deposit (CDs). The
proposed rule requested comments on if
and how the BLM should adjust the
minimum bond amounts in the future.
After review of the comments, bond
amounts will be adjusted for inflation
every 10 years so that the minimum
bond amounts do not become outdated
as they have in the past.
The BLM deleted the existing and
proposed sections governing the formal
lease nomination process under part
3120.
The BLM revised the final rule to
clarify that it will consider the
preference criteria in § 3120.32 as part
of the scoping process and will apply
the criteria after the conclusion of
scoping but before issuing the draft
NEPA document for the lease sale,
consistent with the BLM’s existing
policy and implementation of IM 2023–
007, Evaluating Competitive Oil and
Gas Lease Sale Parcels for Future Lease
Sales.4
The BLM also revised the final rule to
extend an approved APD’s term based
on a lease suspension.
These revisions are discussed in more
detail in the Section-by-Section
Discussion.
B. Section-by-Section Discussion
Sections that did not receive any
comments, or that only received
comments in support of the proposed
changes, are not discussed in this
Section-by-Section analysis and are
adopted in the final rule as proposed. In
addition, throughout the final rule, the
BLM replaced the words ‘‘he,’’ ‘‘she,’’ or
‘‘he/she’’ with the appropriate title or
entity to comply with Executive Order
13988, Preventing and Combating
Discrimination on the Basis of Gender
Identity or Sexual Orientation.
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1. Section-by-Section Discussion for
Changes to 43 CFR Part 3000
Section 3000.5 Definitions
The BLM received a number of
comments on the definition of the terms
‘‘Acreage for which expressions of
interest have been submitted,’’
‘‘Person,’’ and ‘‘Surface Management
Agency.’’
With respect to the phrase ‘‘Acreage
for which expressions of interest have
been submitted,’’ a comment stated the
BLM should change the definition to
‘‘acreage that is identified in an EOI on
land eligible and available for leasing’’
to ensure that the BLM accurately
determines which EOIs have been
properly submitted. No further changes
are made to the final rule as the
definition already states, ‘‘and for which
4 https://www.blm.gov/policy/im-2023-007.
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the BLM may lawfully issue an oil and
gas lease.’’
Comments on the term ‘‘Person’’
recommended that the BLM use the
definition in the Federal Oil and Gas
Royalty Management Act, 30 U.S.C.
1702, to avoid any unnecessary
confusion. The BLM adopts this
recommendation and has revised the
definition of the term ‘‘person’’ in the
final rule accordingly.
Comments on the term ‘‘surface
management agency’’ focused on the
assertion that the definition improperly
required the BLM to obtain consent
from other agencies within the DOI in
order to lease lands managed by those
agencies, and therefore, that the BLM
should not adopt the proposed changes
to this definition. Based on these
comments, the BLM made additional
changes to § 3101.51 to provide that
public domain and acquired lands that
are open to the operation of the Mineral
Leasing Act will be leased only with the
consent of the surface managing agency,
which, upon receipt of a description of
the lands from the authorized officer,
can report to the authorized officer that
it consents to leasing with stipulations,
if any, or withholds consent or objects
to leasing.
Section 3000.40 Appeals
The existing § 3000.4 details the
appeal rights and exceptions for parts
3000 through 3930. The BLM received
suggestions that this section be
amended to include State Director
Reviews, with an option to further
appeal to the Interior Board of Land
Appeals (IBLA). The commenters
asserted that, without the intermediary
appeal to the State Director, there would
effectively be no opportunity to appeal
in light of average times for IBLA
decisions. The BLM does not believe
any change to this section is needed.
Decisions that are signed at the state
office level, which are usually decisions
that affect the administration of a lease
under parts 3100 and 3120, are signed
on behalf of the State Director, meaning
that State Director review is not
applicable. In addition, 43 CFR subpart
3165 already states that onshore oil and
gas operational decisions made under
the authority of part 3160 are subject to
the State Director Review process and
any decision of the State Director is
appealable to the IBLA.
Section 3000.41 Severability
This is a new section that the BLM
has added in response to comments.
The BLM received comments suggesting
that it should include a severability
clause in the final rule similar to that
found in the BLM’s realty regulations
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30921
(43 CFR 2801.8). The final rulemaking
adopts this recommendation by adding
a new section addressing severability.
This section will read, ‘‘If a court holds
any provisions of the regulations in
parts 3000 through 3180 or their
applicability to any person or
circumstances invalid, the remainder of
these rules and their applicability to
other people or circumstances will not
be affected.’’ The BLM published the
proposed rule, in large part, to address
the changes required by the IRA, various
reports by the GAO and OIG, and the
Department’s report in response to
section 208 of E.O. 14008. Those
sections implementing the IRA can and
do function separately from those
sections proposing new bonding
amounts or the competitive leasing
preference criteria.
One commenter stated that the courts
will determine if a provision is or is not
severable from the rule. The comment is
correct in that a court will ultimately
determine whether portions of the rule
can be severed from others in the event
a court determines a provision was
improperly promulgated. This section is
designed to aid that review by
demonstrating that the BLM intends the
various components of the rule, with
various provenances and independent
functions, to continue to operate even if
one or more of the provisions is
declared unlawful.
Section 3000.50 Limitations on Time
To Institute Suit To Challenge a
Decision of the Secretary
The existing § 3000.5 reiterates the 90day statute of limitations for judicial
challenges to certain BLM decisions
under the MLA. The BLM received
comments on this section suggesting
that the BLM clarify that the regulation
does not apply to claims brought under
statutes other than the MLA. The final
rule does not adopt this
recommendation, as this section also
applies to other minerals management
programs, such as mining claims, which
are managed under the general mining
laws (see part 3800).
Section 3000.60 Filing of Documents
The existing § 3000.6 specifies where
and when documents filed under these
regulations must be submitted and
provides for filing by electronic means
in addition to the hard copy or delivery
service, as was previously authorized.
Commenters generally supported the
proposed changes to this section.
Commenters suggested revising the
provision to include a requirement that
each BLM office designate an email
address for filing, and that an e-filing
should be deemed timely if it is
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received by 11:59 p.m. local time in the
appropriate BLM office. These changes
were recommended to ensure that the
appropriate official receives the e-filing
and to avoid any risk of default as a
result of e-filing with the wrong person
in a BLM office. The BLM does not
support the use of emails for electronic
filings for many of the same reasons
stated in the comment, i.e., the potential
to be directed to the wrong person and/
or wrong office. In addition, the BLM
will not incorporate the
recommendation to state a specific local
time, since the time by which a filing
needs to be made is already addressed
in 43 CFR 1821.11. The regulation at 43
CFR 1821.11 is entitled, ‘‘During what
hours may I file an application?’’ and
specifically states, ‘‘You may file
applications or other documents or
inspect official records during BLM
office hours. Each BLM office will
prominently display a notice of the
hours during which that particular
office will be open. Except for offices
which are open periodically, for
example, every Wednesday or the 3rd
Wednesday of the month, all offices will
be open Monday through Friday,
excluding Federal holidays, at least
from 9 a.m. to 3 p.m., local time.’’ Those
instructions necessarily depend upon
and encompass the local time at
particular BLM offices.
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Section 3000.100 Fees in General
The existing § 3000.10 provides
general information on the types of fees
the BLM may assess, how the fees are
calculated, when the fees must be paid
and how and when the BLM will adjust
any fees. The BLM received a comment
recommending a change to paragraph
(c), which addresses adjustment of fees,
recommending that any adjustments to
fixed fees be subject to notice and
comment. The BLM declines to make
this change as further explained in the
discussion of § 3000.120 below.
Section 3000.120 Fee Schedule for
Fixed Fees
The existing § 3000.12 lists the fixed
fees that must be paid for each
transaction requiring a fixed fee and
includes transactions that previously
did not require a fee, such as the
designation of a successor operator; unit
agreement applications; subsurface
storage agreement applications; unit
agreement expansion applications; and
formal lease nominations. The final rule
removes the formal lease nominations
process, consistent with the changes
made under § 3120. The BLM received
several comments on this section. Some
comments supported the BLM’s
proposal to incorporate processing fees
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for new actions that were not previously
subject to a fee, stating that the fees
were appropriate given the BLM’s
limited resources, or stating that the
proposed fees were not sufficient to
cover the BLM’s costs. Other comments
opposed the increased fees, asserting
they were excessive, disproportionate,
unwarranted, and designed to be a
deterrent to Federal oil and gas leasing
activities. In addition, some commenters
stated that the analysis in the preamble
to the proposed rule failed to
comprehensively analyze the BLM’s fee
system, and, specifically, failed to
compare the fees to the increased bonus
bids, rentals, and bonding. Another
comment objected to the application of
the new filing fees, royalty, and rental
provisions to leases sold before the
enactment of the IRA but issued after
the IRA.
The preamble to the proposed rule
outlined the processing steps
considered by the BLM in calculating
each of the fees. The general comments
only criticized the processing steps
associated with the BLM’s review of a
competitive lease application fee, as
discussed below. No comments
criticized the processing steps for the
other application fees; therefore, the
BLM will implement the proposed fixed
filing fees as stated in the preamble to
reimburse the BLM for its processing
costs. With respect to the fixed filing
fees, the preamble specifically stated
that the BLM would not charge a new
fixed filing fee under this rule for
processing a document that the BLM
received before the effective date of the
rule. Documents submitted before the
effective date of the final rule will be
processed based on the fee that was in
effect when the document was
submitted.
One comment recommended that the
competitive lease application fee, which
includes the cost for the BLM to
undertake any necessary NEPA review,
should not be a fixed fee and instead
should be determined on a case-by-case
basis under § 3000.110, or, alternatively,
that the cost should be fixed but that the
applicant should have the option to
request a case-by-case fee determination
to establish a fee for a particular lease
application. Although the BLM
understands the impetus for suggesting
that the fee be determined for a
particular lease, the BLM cannot adopt
the proposed change, because the NEPA
analysis prepared for each lease sale
covers all of the parcels offered in a
given sale and is not for each individual
parcel. Moreover, the competitive lease
application fee is collected after the
NEPA review has been completed, and
after the lease sale has been held.
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Therefore, the applicant would not be
able to help pay for the preparation of
any BLM NEPA document before
performing any case processing on a
parcel-by-parcel basis.
Other comments stated that the BLM
should charge fixed filing fees for
compensatory royalty agreements and
communitization agreements (CAs). The
final rule includes a fixed fee for
compensatory royalty agreements under
ROW pursuant to subpart 3109 where
the processing steps are the same for
leases. The BLM added the following
clarifying language to this provision in
the final rule: ‘‘Leasing and
compensatory royalty agreements
applications under right-of-way
pursuant to subpart 3109.’’ The BLM
does not adopt the recommendation to
require a fixed filing fee for CAs. The
BLM explained in the preamble to the
proposed rule that new fixed filing fees
were considered for Federal CAs
(§ 3105), Federal participating area
applications (§ 3180), and royalty rate
reduction applications (§ 3103), but it
ultimately declined to propose these
fees due to the low value and the public
benefit related to these items.
The BLM received suggestions that
the Bureau clarify requirements for the
fixed filing fee for designation of
successor operator for Federal
agreements, such that the fee would not
be required when a successor operator
is designated for contracted unit
agreements that do not contain Federal
lands. The BLM adopts the suggestion
and has revised the Processing and
Filing Fee table in this section of the
final rule to include the following
language: ‘‘Designation of successor
operator for all Federal agreements,
except for contracted unit agreements
that contain no Federal lands.’’
The BLM also received several
comments stating the BLM erred in
adding the fee for EOIs to the fixed
filing fee table, because these fees are
adjusted for inflation every year; and
section 50262(d) of the IRA expressly
authorizes the Secretary to only adjust
the EOI fee ‘‘not less frequently than
every 4 years . . . to reflect the changes
in inflation.’’ The BLM concurs with
this comment and has moved the EOI
fee to the new § 3103.1(a) where it will
be adjusted based on inflation every 4
years.
Another comment stated that the BLM
did not explain its authority to impose
an annual inflation adjustment and that
for the annual inflation adjustment, the
BLM must re-apply all of the factors set
out in section 304(b) of FLPMA, make
a new determination as to whether the
fee warrants an adjustment, and
similarly codify the determination via
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rulemaking every time a fee is adjusted.
A similar comment asked the BLM to
consider the disproportionate impact
continued increases have on the total
cost to develop Federal minerals.
Section 304 of FLPMA, 43 U.S.C.
1734, authorizes the BLM to establish
fees intended to reimburse the
government for reasonable costs and
authorizes the Secretary to change or
abolish such fees. The BLM establishes
fees based upon the reasonableness
factors at section 304(b) of FLPMA,
which include ‘‘actual costs (exclusive
of management overhead), the monetary
value of the rights or privileges sought
by the applicant, the efficiency to the
government processing involved, that
portion of the cost incurred for the
benefit of the general public interest
rather than for the exclusive benefit of
the applicant, the public service
provided, and other factors relevant to
determining the reasonableness of the
costs.’’ Once the BLM establishes a fee,
the BLM adjusts the fees for inflation
annually to effectively keep fees in line
with current costs. This process
comports with the broad authority given
to the BLM in section 304 to set
reasonable fees. The BLM did not
propose changes to this method, or how
the fees are adjusted annually for
inflation in this proposed rule. The BLM
will not use an alternative method for
annual fee adjustments as it would
require collecting data periodically for
each fee, which is inefficient, costly,
and impractical. However, as
recommended by the GAO,5 the BLM
did review the six factors, commonly
known as ‘‘FLPMA reasonableness
factors’’ in section 304(b), to account for
changes in the leasing process since the
fees were initially set. For the proposed
rule, the BLM: (1) contacted each office
with this type of application (the 10
state offices or all of the 40 field/district
and state offices depending on the
application type); (2) requested the
offices to provide the average processing
time for each type of application and the
employee completing this work; (3)
received the estimates from each office;
(4) calculated the weighted average for
each type of application; (5) reviewed
the monetary value of the right or
privilege that the applicant seeks; (6)
evaluated how efficiently the BLM
processes a document based upon the
processing times; (7) reviewed the
public benefit factor for the application;
and (8) reviewed the public service
factor for the application. The preamble
5 GAO. GAO–22–103968: OIL AND GAS
LEASING BLM Should Update Its Guidance and
Review Its Fees. https://www.gao.gov/assets/gao-22103968.pdf.
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to the proposed rule reflects this
analysis of its fixed filing fees. Without
the inflation adjustment that has existed
since 2005, the BLM would instead be
required to complete the same
burdensome, eight step review under
FLPMA for every subsequent update.
Furthermore, to verify the accuracy of
the BLM’s method for determining fees,
the BLM reviewed a common oil and
gas fixed filing fee—assignments and
transfers—which has not experienced
changes to the process since 2005. The
BLM intentionally selected the
assignment and transfer fixed filing fee
as the most representative filing fee to
review because (1) assignments and
transfers are the most common
application received by the BLM; (2) the
other applications that require filing
fees are more rarely used; and 3) all
state offices are familiar with the
assignment and transfer application.
After completing the review of the
assignment and transfer fixed filing fee
for the proposed rule, the BLM
compared the outcome of that review
with the inflation adjustments (86 FR
54636 (Oct. 4, 2021)). The review
identified that the assignment and
transfer fixed filing fee should be $100
in FY2022 based upon the FLPMA
factors. This amount matched the
inflation-adjusted fixed filing fee for
FY2022, which was also $100.
Therefore, the FY2022 inflation
adjustment matched the calculated fixed
filing fee based upon the FLPMA factors
in FY2022. If the BLM’s review process
changes for an application, and thus
there is the potential that reasonable
costs may change outside of the cost of
inflation, the BLM would update the
fixed filing fees based upon the FLPMA
factors and provide the opportunity for
notice and comment.
Finally, the BLM requested comments
related to changing its current process,
which requires publishing the annual
fee adjustments as a final rule in the
Federal Register and then incorporating
the new fees in the Code of Federal
Regulations (CFR). Instead, the BLM
proposed to post the updated table on
the BLM’s web page with the historical
fees posted in the same location.
Commenters stated that since the
fixed filing fees are not subject to
appeal, the BLM should remove this
provision; that adjustment of the fees
should include a notice and comment
period; and that the BLM should
continue to publish the annual fee
adjustments in the Federal Register.
The BLM is updating the final rule to
state that the BLM will ‘‘announce
annually in the Federal Register’’
revised fees, as well as posting the fees
to the website. The BLM initially
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promulgated the fixed filing fees in 2005
after conducting a notice-and-comment
rulemaking. Each year since, the fees
have been adjusted for inflation through
a final rule without further notice and
comment. This is because the BLM
included the method used to calculate
inflation in its proposal in 2005, and the
same method has been used for each
subsequent increase. As stated in the
proposed rule, the BLM will follow this
same procedure for any new fees. For
example, the BLM will: (1) publish a
proposed rule with information on the
proposed fee and propose to adjust the
fee based on inflation; (2) review the
comments received on the proposed
rule for the new fixed filing; (3) publish
a final rule with the new fixed filing fee;
and (4) adjust the new fixed filing fee
based upon inflation without notice and
comment for any subsequent increases.
This process negates the need for notice
and comment every time the BLM
adjusts the fee solely for inflation. These
periodic inflation adjustments are not
subject to appeal.
Additionally, as stated above, if the
BLM’s review process for any
application changes, and thus there is
the potential that the BLM’s reasonable
costs may change outside of the cost of
inflation, the BLM would review the
FLPMA factors to update the fixed filing
fees and provide the opportunity for
notice and comment.
The BLM adopts the proposed change
to publish the fixed filing fees on the
BLM’s web page and to publish the
adjusted fees each year in the Federal
Register to provide additional public
notice. The table in this section will still
contain a list of the types of applications
that require a fixed filing fee, but the fee
itself will be removed from the table so
it does not become outdated as each
subsequent adjustment for inflation is
made. In addition, the BLM modified
the regulatory text to reflect that the
table in 3000.120 does not include the
actual fee amounts. When fees are
added, deleted, or need to be adjusted
due to changes in the processing steps
for the application or a change to the
method to calculate the inflation
adjustment amount, the BLM will do so
by a notice and comment rulemaking.
Section 3000.130 Fiscal Terms of New
Leases
The provisions within § 3000.130
only apply to oil and gas leasing;
therefore, the BLM moved the fiscal
terms for new leases to a new section
under subpart 3103 for Fees, Rentals
and Royalty in the final rule in response
to comments stating that failure to
specify the rental amounts, within the
context of the regulation on annual
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rentals, would be a disservice,
detracting from the regulations’ value as
an orderly source for basic information.
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2. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3100
The BLM received a recommendation
to reference its legal authority and
duties under FLPMA and NEPA in all
authority citations in the regulation. The
BLM concurred in part and added a full
reference to FLPMA into the authority
introduction to the regulatory text,
which changes ‘‘43 U.S.C. 1732(b),
1733, and 1740’’ to now state, ‘‘43
U.S.C. 1701 et seq.’’ This update was
only made to part 3100 since the other
authority references already include a
reference to FLPMA. The BLM did not
add NEPA into the authority section, as
NEPA does not provide the BLM with
any authority for leasing.
Section 3100.3 Authority
The existing § 3100.0–3 sets out the
BLM’s authority for leasing on various
types of lands, such as public domain
land and acquired lands. During the
comment review period, the BLM
decided to add clarifying language in
the final rule on Wild and Scenic Rivers
to comply with the Wild and Scenic
Rivers Act (16 U.S.C. 1280). Therefore,
the final rule makes the following
adjustments to the language for the Wild
and Scenic Rivers exceptions listed
under both Public Domain and
Acquired lands: ‘‘subject to valid
existing rights,’’ is moved to the
beginning of the sentence to clarify that
this applies to all types of National Wild
and Scenic Rivers Systems lands. The
following clarifying language is added
to the end of the sentence ‘‘lands within
designated Wild and Scenic Rivers
System that constitute the bed or bank
or are situated within one-quarter mile
of the bank of certain rivers designated
as scenic or recreational, and in some
cases, designating legislation may apply
a different boundary extent. Lands
within the National Wild and Scenic
Rivers System that constitute the bed or
bank or are situated within one-half
mile of the bank of any river designated
a wild river by the Alaska National
Interest Lands Conservation Act (16
U.S.C. 3148).’’
The BLM received a comment on
paragraphs (a)(1) and (b)(1), suggesting
that the BLM change the phrase ‘‘are
subject to lease’’ to ‘‘may be subject to
lease’’ to align with the discretion
afforded the Interior Secretary under the
MLA, 30 U.S.C. 226(a), that lands ‘‘may
be leased.’’ The final rule does not adopt
this recommendation. In 1920, Congress
enacted the MLA to facilitate the
exploration and development of oil and
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gas and other federally owned minerals.
The MLA specifies the lands that are
subject to the statute, and then provides
discretion to the Secretary to determine
which of those lands may be leased. The
first step in exercising that discretion is
making decisions in the BLM’s resource
management plans under FLPMA. The
BLM declines to change this phrase so
as not to confuse this section on the
authority to lease, including the
exceptions listed under both public
domain and acquired lands, where there
is no discretion to lease ineligible lands.
A comment recommended that
paragraphs (a)(2) and (b)(2) rely solely
on the subhead—Exceptions—to
indicate what the provisions in the
sections mean and, for clarity, that the
BLM should consider inserting language
to the effect of: ‘‘The following lands are
not subject to lease.’’ The final rule
adopts this recommendation.
The BLM received a comment
requesting that the BLM identify
additional exceptions for both public
domain and acquired lands. This
exception would specify that the BLM
cannot lease lands identified in the land
use plans as unavailable for oil and gas
leasing or otherwise determined by the
authorized officer to be inappropriate
for leasing to protect other multiple use
resources and values. The final rule
does not adopt this recommendation. As
stated in the proposed rule, the purpose
of this section is to describe lands
subject to leasing, and changes proposed
to this section were made to provide
clarity and to conform the regulations to
exceptions identified in various other
laws. The change requested by the
comment does not meet this
requirement, as the comment addresses
discretionary decisions regarding
leasing. Moreover, the concerns
represented by this comment are already
addressed in the BLM’s land use
planning process, NEPA reviews, and
other processes that identify suitable
areas for leasing.
Section 3100.5
Definitions
The existing § 3100.0–5 sets out the
definitions applicable to part 3100. The
BLM added new proposed definitions
for ‘‘competitive auction,’’ ‘‘exception,’’
‘‘modification,’’ ‘‘oil and gas
agreement,’’ ‘‘qualified bidder,’’
‘‘qualified lessee,’’ ‘‘responsible
bidder,’’ ‘‘responsible lessee,’’ and
‘‘waiver.’’ The BLM received several
comments on this section requesting
additional definitions for ‘‘bad actors,’’
‘‘current land use plan,’’ ‘‘exclusion
area,’’ ‘‘mitigation,’’ ‘‘permanent
impairment,’’ and ‘‘preferred leasing
area.’’ Since these terms are not used in
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parts 3000, 3100, and 3120, the BLM has
not adopted these recommendations.
In addition, a comment recommended
adding a definition for ‘‘restoration.’’
The BLM declines to make this change
given that § 3104.10, where this term is
used, specifically states that the
restoration is to be ‘‘in accordance with,
but not limited to, the standards and
requirements set forth in 43 CFR 3162.3
and 3162.5 and orders issued by the
authorized officer.’’ This flexible
definition does not warrant
modification at this time.
Some comments recommended that
the BLM expand the definitions in this
section to include the terms ‘‘eligible’’
and ‘‘available.’’ The BLM declines to
define those terms by regulation at this
time and may revisit the issue in future
rulemakings.
One commenter requested that the
BLM remove the definition for
‘‘modification’’ to avoid confusion
where this term is used in contexts
other than changes to lease stipulations.
The BLM agrees there is a potential for
confusion given the numerous different
contexts in which the word
‘‘modification’’ is used and has
therefore revised the definition to clarify
that it only applies to lease stipulations.
For similar reasons, the BLM has made
changes to ‘‘exception’’ and ‘‘waiver’’ in
the final rule. Each definition now
includes the phrase ‘‘as used for lease
stipulations.’’
A comment recommended modifying
the term ‘‘oil and gas agreement’’ to
reflect the fact that an agreement may in
some instances include unleased lands.
The BLM adopts this recommendation.
The BLM received a comment
suggesting that the term ‘‘operator’’
should be revised to explicitly state that
the operator holds operating rights and
thus has the same obligations as the
operating rights owners to plug wells
and remediate the well sites. The BLM
does not concur with the
recommendation, as an operator could
be a lessee and may or may not own
operating rights. The current definition
for ‘‘operator’’ states, ‘‘including, but
not limited to, the lessee or operating
rights owner, who has stated in writing
to the authorized officer that it is
responsible under the terms and
conditions of the lease for the
operations conducted on the leased
lands or a portion thereof.’’ Therefore,
the BLM kept the existing definition of
‘‘operator’’ in the final rule.
The BLM received several comments
on the proposed definitions for the
terms ‘‘qualified bidder,’’ ‘‘qualified
lessee,’’ ‘‘responsible bidder,’’ and
‘‘responsible lessee.’’ Those comments
that supported the inclusion of these
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new definitions suggested modifications
that would also exclude from those
terms anyone with a history of failing to
make timely rental or royalty payments;
failing to meet a diligent development
obligation; maintaining a significant
number of inactive wells; engaging in
repeated or ongoing environmental,
worker safety, or labor violations;
violating State reclamation requirements
on other leases; or engaging in lease
speculation, such as failing to drill
approved APDs, or holding large
quantities of undeveloped leases.
The BLM declines to include this
language, which is too vague and
overlooks existing enforcement tools.
For example, when a company fails to
make timely payments, such as rental
payments, the Act already dictates that
the lease will automatically terminate
through operation of law. In addition, if
a company fails to make royalty
payments after being notified such
payments are due and exhausting its
legal remedies, the Office of Natural
Resources Revenue (ONRR) may refer an
entity to the Federal suspension and
debarment list. It is the BLM’s policy to
check SAM.gov (the Federal suspension
and debarment site) before issuing a
lease or approving an entity to acquire
a lease interest through an assignment
or transfer of operating rights. The BLM
may also take enforcement actions when
lessees violate the terms of a lease,
including environmental, worker safety,
or labor standards. The BLM does not
agree that a company’s decision to not
drill a well or develop leases should
determine if they are responsible or
qualified, because such fact-specific
business decisions do not, by
themselves, determine whether a lessee
has acted irresponsibly or
incompetently. The BLM generally lacks
the capacity to investigate and evaluate
State law reclamation violations;
however, the current definition for
responsible lessee provides for the
lessee to be in compliance with statutes
applicable to oil and gas development.
While it is not the BLM’s practice to
investigate a person’s compliance with
State law reclamation requirements, the
BLM would not ignore a person’s
noncompliance when it has been
brought to the BLM’s attention for
consideration if a person is a
responsible lessee prior to lease
issuance.
Other comments suggested that, in
connection with these definitions, the
BLM should: (1) create a public registry
of individuals and companies currently
identified as not being responsible
bidders and/or lessees, and make the list
of ‘‘Entities in Noncompliance with
Reclamation Requirements of section
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17(g) of the MLA’’ public and updated
on a regular basis; (2) clarify, in
§ 3108.30, that leases are subject to
cancellation if the lessee is found not to
be a ‘‘qualified lessee’’ or a ‘‘responsible
lessee’’; and (3) implement a system that
allows States, local government, Tribal
governments, and individuals to report
behavior or conduct that warrants
investigation.
The BLM updates the list of ‘‘Entities
in Noncompliance with Reclamation
Requirements of section 17(g) of the
MLA’’ on an as needed basis, and then
forwards the names of the entities to the
Federal Government’s suspension and
debarment program. SAM.gov is a
publicly available website. In turn,
when a company returns to compliance,
the BLM notifies the suspension and
debarment program that the entity
should be removed from SAM.gov. The
cancellation provisions in § 3108.30
contains language for entities that fail to
comply with the laws and regulations.
The BLM also notes that any entity or
individual can contact the BLM to
report behavior or conduct that warrants
investigation, and the BLM declines to
create a separate regulatory system for
this purpose at this time.
The BLM also received comments
regarding the new definitions for
‘‘qualified bidder,’’ ‘‘qualified lessee,’’
‘‘responsible bidder,’’ and ‘‘responsible
lessee.’’ One comment suggested that
the term ‘‘qualified bidder’’ does not
take into account that brokers or nonoperating partners bid on leases, and
that the new term could substantially
impede bidding if it were to mandate
that bonding or similar bidder
requirements that historically only
applied to a lessee be in place prior to
bidding. The BLM considered the
involvement of brokers or non-operating
partners when it drafted these
definitions, which is evidenced by the
separate definitions for ‘‘qualified
bidder’’ and ‘‘responsible bidder’’, as
well as to whom the lease is issued
(‘‘qualified lessee’’ and ‘‘responsible
lessee’’), since these may not be the
same entities. In addition, there is no
mandate, in either the proposed or final
rules, for bonding or similar
requirements prior to bidding.
Another comment suggested that the
BLM should clarify in the definitions
(and in proposed § 3102.51) that it will
continue to adhere only to the factors in
MLA section 17(g), 30 U.S.C. 226(g), in
determining who may hold a lease. The
BLM disagrees. The MLA, 30 U.S.C.
226(b)(1)(A), refers to responsible
qualified bidders and specifically states
that: ‘‘[a]ll lands to be leased which are
not subject to leasing under paragraph
(2) shall be leased as provided in this
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30925
paragraph to the highest responsible
qualified bidder by competitive bidding
under general regulations in units of not
more than 2,560 acres, except in Alaska,
where units shall be not more than
5,760 acres.’’ The MLA also states that
‘‘[t]he Secretary shall accept the highest
bid from a responsible qualified bidder
which is equal to or greater than the
national minimum acceptable bid,
without evaluation of the value of the
lands proposed for lease.’’ The BLM’s
regulations reiterate and rely on these
statutory terms. Specifically, because a
person who bids on a lease is not
necessarily the same person to whom
the lease is issued, it is appropriate to
include definitions for ‘‘qualified
bidder’’ and ‘‘responsible bidder,’’ as
well as definitions for whom the lease
is issued, i.e., ‘‘qualified lessee’’ and
‘‘responsible lessee.’’
Another comment on the definitions
for ‘‘responsible bidder’’ and
‘‘responsible lessee’’ questioned the
inclusion of the phrase ‘‘history of
noncompliance’’ with applicable
regulations and lease terms, stating that
the meaning of a ‘‘history of
noncompliance’’ is unclear. The
comment suggested that the phrase
could be construed broadly to mean
that, if a person ever was found to have
been in noncompliance with the terms
of its Federal oil and gas lease or
applicable regulations, that person
could be precluded from obtaining
future Federal lease interests, even if
they corrected the alleged
noncompliance or disputed the alleged
violation and won.
The BLM agrees the term is imprecise
and has revised the definitions by
changing the phrase ‘‘does not have a
history of noncompliance’’ to ‘‘is in
compliance.’’ A lessee would not be
precluded from obtaining future Federal
lease interests if it corrected the
noncompliance. A lessee’s
noncompliance ends: (1) when the
entity has paid all civil penalties and
performed the required reclamation; (2)
the BLM accepts the required
reclamation performed under contract,
and the entity reimburses the U.S. for all
costs associated with the required
reclamation, including the costs
associated with the BLM’s issuing and
overseeing the performance contract
during its life; and (3) if the bond is
collected and is insufficient to cover the
total costs, the entity pays the entire
amount due to the U.S. and the BLM
accepts compliance. This is outlined in
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the BLM handbook H–3120–1,
Competitive Leases, Appendix 4.6
The BLM proposed to separate the
definitions for ‘‘assignment’’ and
‘‘sublease’’ from the current definition
of ‘‘transfer’’ in the existing regulations.
One comment stated that a greater
understanding of the differences
between assignment and transfer of
operating rights is long overdue.
Another comment stated that the BLM’s
definitions for ‘‘assignment’’ and
‘‘transfer’’ have corresponding, but
different, meanings; that the Bureau of
Ocean Energy Management (BOEM)
recently issued a proposed rule stating
that the terms are interchangeable; and
that the BLM should ensure consistency
and clarity in use of these terms
between the two bureaus regulating
Federal oil and gas leasing onshore and
on the Outer Continental Shelf. The
BLM reviewed its definitions and
believes the two terms are distinct and
should remain separate. An assignment
of record title conveys both record title
and operating rights and is limited
under § 3106.10 to certain restrictions
that do not apply to transfers. The
BOEM regulations do not have this
distinction, which is why the BLM is
retaining the separate definitions.
Comments recommended adding a
definition for ‘‘unnecessary or undue
degradation.’’ The BLM declines to
define this phrase in this rule because
it is used only once, in § 3120.32, and
such a definition would benefit from
public input before promulgation. As
used in § 3120.32, the phrase reflects the
ordinary meaning of the terms used in
section 302(b) of FLPMA.
Section 3100.22 Drilling and
Production or Payment of Compensatory
Royalty
The existing § 3100.2–2 addresses
drainage protection, an express
covenant of the lease agreement. Under
the terms of Federal leases, the lessee
has the obligation to protect the leased
land from drainage by drilling and
producing any well that is necessary to
protect the lease from drainage, or, in
lieu thereof and with the consent of the
authorized officer, by paying a
compensatory royalty assessment to the
Federal government. The BLM did not
propose changes to this section but did
receive a comment stating that the BLM
should consider using this opportunity
to amend this section to (1) clarify when
drainage involving two Federal leases
with different fund distribution codes
occurs; and (2) specify that the lessee
may resolve drainage by creating a
6 https://www.blm.gov/sites/blm.gov/files/
uploads/Media_Library_BLM_Policy_h3120.pdf.
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Section 3100.40 Public Availability of
Information
The proposed rule stated that the
BLM was considering adding language
that would provide notice that names
and addresses of the nominator, lessee,
operating rights holders, and operators
would be made public on the BLM’s
Mineral & Land Records System
(MLRS). The BLM’s lease and agreement
case files are already public records, and
any change to the existing § 3100.4
would merely reflect the BLM’s current
practice. The BLM received comments
supporting additional changes to this
section, stating that it should be made
clear to nominators, lessees, operating
rights holders, and lessees that their
identities will be made public through
the MLRS rather than the current
practice, which requires a member of
the public to be at the BLM state office
to submit a paper request to document
the case file. The BLM will continue to
release the names and addresses of
nominators, lessees, operating rights
holders, and lessees to the extent
allowed by the Privacy Act to ensure
there is a transparent onshore leasing
process and does not believe any further
changes to this section are needed. The
names and addresses of individuals
were redacted from all reports,
including Serial Register Pages, as a
result of a recent privacy review. The
redacted information only applies to
individuals (MLRS personal accounts)
and not companies (MLRS business
accounts). Specifically, the privacy
review determined that all personal
accounts regardless of type of case are
considered to contain Personally
Identifiable Information (PII). In order to
release this PII—specifically names and
addresses that are collected of our
applicants/interest holders—the BLM
must meet two requirements. First, the
BLM must establish and disclose a
routine use for the information—which,
in other words, is establishing that the
public need and benefit outweighs the
need for the protection of the privacy
information and notifies that the PII
may potentially be released. This has
been completed by disclosing the
routine uses contained in BLM System
of Records Notice (SORN) LLM32 in
accordance with the Privacy Act. The
SORN LLM32 is for Lands & Minerals
Authorization Tracking System and
covers the data from both LR2000 and
MLRS. Most requests made in the
Information Access Center at the state
offices fall under routine use number
‘‘(2) to Federal, State, or local agencies
or a member of the general public in
response to a specific request for
pertinent information.’’ Second, to meet
Privacy Act requirements, the BLM
must be able to track who received the
information, when, and for what
purpose to satisfy the Privacy Act’s
requirement that the information was
released in accordance with a ‘‘specific
request for pertinent information.’’ A
member of the public can create an
MLRS account to view unredacted
information. This log in method allows
for the BLM to meet this requirement
through a logging system.
The BLM received a comment stating
that the BLM provides no justification
for publishing information on all
entities registered to bid during a lease
sale, rather than providing this
information only for issued leases.
Publishing participants in oil and gas
lease sales has been a long-standing
Bureau policy to provide transparency
in the competitive leasing process. Refer
to H–3120–1 Competitive Leases
handbook, published February 2013.8
This policy specifically states, ‘‘Names
of bidders/high bidders remain
confidential until the end of the sale.’’
In addition, each Notice of Competitive
Lease Sale provides adequate notice that
the names and addresses of bidders will
be released and no further changes to
the lease sale process are needed.
Another comment stated that the final
rule should also authorize researchers to
use lease and production data to analyze
market-level royalty, bid, and rental
rates. The comment then stated that
independent, professional analysis
would provide the BLM with critical
data on the appropriate market-level
rates for Federal mineral charges. In
addition, the commenter also stated that
the final rule should authorize the BLM
to provide a quarterly report to the
7 BLM. MS–3160, Drainage Protection Manual
(Public). https://www.blm.gov/sites/blm.gov/files/
uploads/mediacenter_blmpolicymanual3160.pdf.
8 BLM: H–3120–1, Competitive Leases handbook.
https://www.blm.gov/sites/blm.gov/files/uploads/
Media_Library_BLM_Policy_h3120.pdf.
federally approved agreement for
sharing production among the affected
leases. These proposals already reflect
current policy; refer to the BLM Manual
Section 3160, Drainage Protection
Manual.7 The Drainage Protection
Manual provides guidelines, standards,
and procedures to prevent the loss of oil
and gas resources and any resulting loss
of royalty revenues from drainage on
leased and unleased public domain,
acquired, and Indian lands. The BLM
does not believe changes are needed to
this section since these proposals are
already allowed under the current
regulations to address possible solutions
to drainage.
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public on all revenues received from
leasing and mineral production on
Federal lands on a lease-by-lease basis,
and as the ultimate owners of the lands
and minerals being leased, the public
has a right to know this information.
The BLM makes lease information,
including lease terms such as rental
rates and royalty rates, available through
the MLRS; however, because the
amount of royalty is a function of
production and proprietary data is
confidential, the royalty amount the
Federal government receives cannot be
released on a lease-by-lease basis. The
public may obtain general information
on production data, rental, and royalty
payments from the ONRR.
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Section-by-Section Discussion for
Changes to 43 CFR Subpart 3101
Section 3101.12 Surface Use Rights
The proposed rule revised the existing
§ 3101.1–2, which was originally
promulgated in 1988, to provide that the
BLM could impose reasonable measures
under the lease terms to avoid,
minimize, or mitigate adverse impacts
to other resource values, land uses or
users, federally recognized Tribes, and
underserved communities. Those
reasonable measures include sitespecific minimum siting and timing
parameters that the BLM may impose on
lessees to protect the public interest.
The BLM received numerous
comments on this section, including: (1)
support for the proposed changes, and
statements that the changes are critical
to mitigate impacts when the relevant
RMP is outdated; (2) requests for
clarification that leases are contingent
on NEPA analysis and not a lessee’s
expectation; (3) requests for clarification
that a lessee’s surface use rights are
subject to a land use plan’s term,
including terms provided for by land
use plans either revised or amended
after a lease is issued; and (4) requests
for the BLM to clarify that the agency
retains its full authority to condition
development and production on leases
after the lease is issued in order to
respond to findings of site-specific
NEPA analyses or changing conditions
between the time a lease is issued and
when it is developed. These changes are
unwarranted as the BLM has the
authority to impose measures that are
more stringent than those in the
regulations as long as they constitute
reasonable measures to minimize
adverse impacts, Yates Petroleum, 176
IBLA 144, 156 (2008). Therefore, the
BLM is not revising this section further
based on these comments, many of
which request unwarranted or
unnecessary clarification or specificity
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that would exceed the scope of this
rulemaking.
Some comments opposed the
proposed changes to this section,
including by asserting that: (1) distance/
siting requirements could lead to the
BLM exceeding its authority to regulate
air quality; (2) the BLM did not
reference a lease provision that grants
the agency the proposed new authority
to constrain or deny lease operations;
and (3) the BLM should consider public
welfare when determining which
measures may be reasonable. The BLM
has the authority to use terms and
conditions under Section 6 of the
standard lease form to control sitespecific environmental or public welfare
impacts on leaseholds, as opposed to
using lease-specific protective measures
in lease stipulations from the RMPs.9
Section 6 of the standard lease form
authorizes the BLM to require
‘‘reasonable measures’’ to the extent that
such measures would be consistent with
the lessee’s lease rights. The existing
regulation has been misconstrued as
limiting the BLM’s authority to establish
reasonable measures to protect
resources and to establish minimum
parameters within which the BLM can
specify site-specific mitigating measures
that are consistent with the lease rights
granted a lessee.
Comments requested (1) the removal
of language that arguably suggests that
the BLM could require a lessee to
‘‘avoid’’ or ‘‘mitigate’’ all adverse
impacts of developing mineral rights;
and (2) that the final rule specify how
water sources will be protected. The
BLM has revised this section by
clarifying that not all surface impacts
must be mitigated and by clarifying the
distance the BLM may require
operations to be moved. The final rule
strikes the words ‘‘avoid, minimize, or’’
since this is not needed as avoidance
and minimization are integral to
mitigating adverse impacts.
Some comments requested changes to
require the relocation distances to be
either a maximum of or be at least 1
mile and requested the BLM to prohibit
new surface disturbing operations. The
language in this section has been in
place since at least 1988 and does not
prohibit new surface disturbance. The
BLM proposed to change only the
minimum siting and timing parameters
to account for changes in technology.
The BLM declines to further increase or
set a maximum parameter as this would
not allow the flexibility that may be
9 Stipulations are additional specific terms and
conditions that change the manner in which
operations may be conducted on a lease or modify
the lease rights granted.
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required to avoid resource conflict. The
final rule amends the last sentence of
the section to clarify the intent of the
proposed rule. The proposed rule
removed the phrase ‘‘At a minimum’’
from the existing regulations but
retained the phrase ‘‘by more than.’’ The
final rule is amended to state, ‘‘At a
minimum, modifications that are
consistent with lease rights include, but
are not limited to, requiring relocation
of proposed operations by up to 800
meters,’’, which allows the BLM to
require a lessee to relocate proposed
operations by up to 800 meters to avoid
a resource conflict that may not have
been identified at the time the BLM
issued the lease. For example, the BLM
may need to move operations to avoid
a sage grouse lek, a contingency that
may not be encompassed by standard
lease terms. In that circumstance, this
provision would allow the BLM to move
the operations up to 800 meters to
minimize the impacts to the sage grouse
lek. As stated in the 1988 final rule
preamble for the existing regulations,
‘‘Similarly, the authority of the BLM to
prescribe ‘‘reasonable,’’ but more
stringent, protection measures is not
affected by the final rulemaking,’’ see 53
FR 17341 (May 16, 1988). This section
does not apply to the protection of
resource values that are already
addressed in lease stipulations.
Comments requested that the BLM
strike the word ‘‘specific’’ as a modifier
for ‘‘nondiscretionary statutes’’ that
provide post-lease restrictions on
surface use rights. The final rule adopts
the recommendation to strike the word
‘‘specific’’ as a modifier to
nondiscretionary statutes.
Comments stated that the language
explicitly allowing a BLM officer to
restrict the development of a project to
proactively avoid impacts to ‘‘land
users’’ or ‘‘underserved communities,’’
is improper because, the commenter
contended, such language is vague and
would improperly expand the BLM’s
authority, potentially encroach upon a
lessee’s lease rights, and cause
uncertainty. Other comments requested
that the BLM add ‘‘overburdened and’’
before ‘‘underserved communities’’ in
the final rule, and that the BLM better
specify procedures the BLM could use
to protect multiple use standards and
Native Americans’ land rights in areas
near reservations. For the reasons
explained below, the BLM does not
agree with these comments and retains
its proposed language to proactively
avoid impacts to ‘‘land users’’ or
‘‘underserved communities.’’
The term ‘‘land users’’ is already used
in the existing 43 CFR 3101.1–2 and is
specifically included in Section 6 of the
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standard lease form. This term identifies
segments of the public that use the land
for recreation or for economic growth in
the community. Like the term, ‘‘resource
values’’—which the BLM’s regulations
do not define—the term ‘‘underserved
communities’’ has a straightforward and
commonly understood meaning that
would not benefit from elaboration here,
and the BLM has an obligation under
the MLA and APA to articulate a
rational connection between
underserved communities and the
proposed operations, as modified by the
BLM. Based on the above, the BLM
declines to modify or remove either
‘‘land users’’ or ‘‘underserved
communities.’’
Section 3101.13 Stipulations and
Information Notices
The BLM proposed to split the
existing § 3101.13 into two separate
provisions and add a new paragraph (a),
stating the BLM would consider the
sensitivity and importance of a resource
when developing stipulations without
regard to the restrictiveness of the
stipulation.
One comment on this section
recommended that the consideration of
affected resources and potential
uncertainty be made mandatory by
substituting ‘‘shall’’ or ‘‘must’’ for
‘‘may’’ in the final rule text to remove
any uncertainty. The BLM declines to
make this change so as to maintain
discretion when considering potential
stipulations. The BLM requires this
discretion because the BLM need not
consider every potentially affected
resource for each parcel. Instead, the
BLM will use its discretion to
determine, based on the sensitivity,
importance, and any uncertainty, which
resources should be considered, and
will then assess whether those resources
are adequately protected by stipulation.
Some comments stated that the BLM
should delete the proposed paragraph
(a) 10, arguing that the language is
subjective and would allow the
inclusion of new stipulations that were
not addressed in the underlying
planning documents. Some comments
stated that proposed paragraph (a), and
in particular the phrase ‘‘without regard
to the restrictiveness of the stipulation,’’
disregards the principle of multiple use
by elevating certain uses or allows the
BLM to essentially prevent oil and gas
10 Proposed regulation text at 43 CFR 3101.13(a):
‘‘The BLM may consider the sensitivity and
importance of potentially affected resources and
any uncertainty concerning the present or future
condition of those resources and will assess
whether a resource is adequately protected by
stipulation without regard for the restrictiveness of
the stipulation on operations.’’
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operations. Another comment
recommended changing the phrase
‘‘without regard’’ to ‘‘along with
consideration.’’
As stated in the proposed rule, the
BLM added this paragraph to more
explicitly recognize its mandate to
manage the Federal lands for multiple
use. Stipulations do not prevent oil and
gas operations from occurring under a
lease. Rather, stipulations that allow,
but control, surface use are a valuable
management tool to achieve balanced
multiple resource use, including oil and
gas development. As stated above, the
BLM retains discretion in this section
and will rely on its expertise when
making these site-specific decisions
regarding stipulations. Consistent with
these objectives, the BLM agrees that the
bureau should consider the
restrictiveness of a stipulation on
operations. In the final rule, the BLM
deletes the phrase ‘‘without regard for’’
and inserts instead ‘‘while considering’’
to recognize the BLM’s mandate to
manage the Federal lands for multiple
use and to provide for the protection of
the resources on those lands.
The BLM also received a comment on
proposed paragraph (c), which specified
that the BLM may attach an information
notice to the lease. That comment
requested that the BLM remove the last
sentence in the paragraph—which
reads, ‘‘Information notices may not be
a basis for denial of lease operations’’—
because it undermines the BLM’s
management authority. Another
comment recommended that this
paragraph incorporate a requirement
that information notices highlight
potential conflicts with other resource
values and be accompanied by full lease
stipulations specifying how those
conflicts will be resolved. The final rule
does not adopt these recommendations,
as the information notice is a method of
informing lessees of requirements that
may be imposed by an existing law or
regulation, not of imposing new
requirements.
Finally, the BLM received comments
recommending the development of
specific stipulations and considerations
for all leases, including a no surface
occupancy within 2 miles of developed
recreation sites and a 1-mile no surface
occupancy from key recreation areas.
The BLM disagrees and declines to
adopt one-size-fits-all stipulations for all
leases. The BLM historically has
identified the appropriate stipulations
through RMPs, ensuring that the BLM
ties the appropriate stipulations to the
lease under consideration. That
approach allows the BLM to develop
and set forth lease stipulations in the
land-use planning documents/RMPs so
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that the public is aware of the balance
that will exist between environmental
protection and opportunities for
development of oil and gas resources in
advance of offering the lands for lease.
Section 3101.14 Modification, Waiver,
or Exception
This section describes the standards
that the BLM will use when evaluating
modifications, waivers, or exceptions.
The BLM proposed changes to the
existing § 3101.14 to more explicitly
recognize its mandate to manage the
Federal lands for multiple use and to
provide for the protection of the
resources on those lands. The proposed
rule also split the existing provision into
two components: one to address
modifications prior to lease issuance
and one for modifications after lease
issuance.
The BLM received multiple comments
on the BLM’s proposed approach. For
example, comments: (1) expressed
concern that the language broadened the
ability of surface management agencies
to object to the inclusion of parcels in
an oil and gas lease sale; (2) requested
a revision to paragraph (a) to state that
requests for modification, waivers, or
exceptions would not be posted for
public comment; (3) suggested the BLM
should clarify that this paragraph does
not alter or affect criteria for
modification, waivers, and exceptions of
stipulations in the BLM’s RMPs; (4)
suggested that the proposed rule
introduced new subjective standards,
such as a ‘‘major concern to the public;’’
and (5) recommended that the BLM
should not remove the language ‘‘or if
proposed operations would not cause
unacceptable impacts,’’, since, in the
commentors’ view, that edit would
curtail the BLM’s flexibility for
addressing circumstances where the
BLM’s granting of the modification or
waiver would not result in unacceptable
impacts.
After consideration of these
comments, the final rule splits
paragraph (a) into two paragraphs for
clarity. The first sentence in proposed
paragraph (a) now appears at the end of
the section in new final paragraph (d),
since modifications, waivers, and
exceptions to a stipulation are
considered later at the APD stage, not at
the leasing stage. The restructuring of
this provision addresses concerns that
the paragraph alters or affects criteria for
modification, waivers, and exceptions of
stipulations in the BLM’s RMPs.
As stated in the proposed rule, the
BLM removed the existing provision—
allowing the granting of modifications,
waivers, or exceptions to lease
stipulations if the authorized officer
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determines that the ‘‘proposed
operations would not cause
unacceptable impacts’’—because this
authority has been overused 11 and has
potentially led to unnecessary adverse
environmental impacts.
The BLM has concluded that it is
appropriate to exempt situations based
on time-sensitive information from the
review requirement. For example, if a
survey is completed for nesting raptors
and it can be confirmed that there are
no raptors present, then an exception
from a timing stipulation based on the
presence of nesting raptors would be
appropriate. However, if the 30-day
review period applied, the conditions
would no longer be in effect to support
the exception. Final paragraph (a),
which applies to lease terms and
stipulations, now states, ‘‘If the
authorized officer determines that a
change to a lease term or stipulation is
substantial or a stipulation involves an
issue of major concern to the public,
except time-sensitive exceptions based
on verified data, the changes will be
subject to public review for at least 30
calendar days.’’ As stated in the
proposed rule, the BLM would consider
a change to the lease terms to be
substantial if the change would have an
important, considerable, consequential,
major, or meaningful effect on the
environment that was not previously
considered, thus requiring public
notification (30-day public review) of a
lease term or stipulation.
The language in this section does not
broaden surface management agencies’
ability to object to the inclusion of
parcels in an oil and gas lease sale,
because lands requiring the consent of
other surface management agencies is
addressed under § 3101.51. This
rulemaking does not introduce new
subjective standards. Language such as
a ‘‘major concern to the public’’ appears
in existing regulations and has not
caused issues.
One commenter stated paragraph (b)
presents potential disruption to the
competitive lease sale process as all
lease conditions or stipulations must be
disclosed prior to a lease sale. The BLM
revised this paragraph to reflect IBLA
decisions, which have stated that if a
lease is issued without prior notice of an
additional stipulation, the stipulation is
not binding on the potential lessee and
is without effect in the absence of the
potential lessee’s acceptance of the
stipulation, see Emery Energy, Inc, 64
IBLA 175 (1982). While this rarely
occurs, the purpose of this section is to
allow the BLM to correct errors made
11 See, e.g., GAO–17–307, https://www.gao.gov/
products/gao-17-307.
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when preparing the Notice of
Competitive Lease Sale. Moreover, the
MLA vests the Secretary with broad
discretion to decide, up until the time
of lease issuance, whether particular
parcels of Federal land ‘‘may be leased’’
for oil and gas development, see 30
U.S.C. 226(a). Under the final rule, the
BLM may decide not to issue a lease if
the modification of a stipulation could
increase the value of a parcel. For
example, if the Notice of Competitive
Lease Sale incorrectly listed a parcel as
subject to a no-surface-occupancy
stipulation, and it is then realized that
the parcel should not have been subject
to that limitation, but this mistake is not
caught until after the sale, this could
increase the value of the lease. To
ensure a fair return to the public, the
BLM would decline to issue the lease
and would offer the parcel in a future
lease sale. The competitive bidding
process would ensure that the BLM
receives the appropriate bid for the
parcel with the modified stipulation.
One comment on paragraph (c)
recommended striking the phrase ‘‘was
inadvertently omitted,’’ and adding ‘‘to
comply with a nondiscretionary legal
requirement, or to address an adverse
effect that was not reasonably
foreseeable at the time of lease issuance
or whose analysis was otherwise
expressly deferred to the site-specific
proposal stage,’’ and changing ‘‘may’’ to
‘‘will’’ in reference to lease cancellation.
These recommendations would
substantially change the meaning of the
paragraph, which was intended to
address situations when the BLM
inadvertently omits a stipulation when
preparing parcels for a lease sale. The
intent of the modified language is to
reflect IBLA decisions on this issue. The
BLM has not made any changes based
on this comment.
Section 3101.21 Public Domain Lands
The BLM did not propose any
changes to the existing § 3101.2–1;
however, the BLM received a comment
stating that the BLM should not only
rely on the section title to convey to
readers that the language in the section
applies to public domain lands (whereas
the next section applies to acquired
lands). The BLM concurs with this
recommendation and inserts in final
paragraph (a) ‘‘on public domain lands.’’
Section 3101.22 Acquired Lands
The BLM did not propose any
changes to the existing § 3101.2–2;
however, the BLM received a comment
stating that the BLM should not only
rely on the section title to convey to
readers that the language applies to
acquired lands. Another comment stated
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30929
that the BLM should specify that the
acquired lands limitation is separate
from, and in addition to, the limitation
for public domain lands. The BLM
concurs with these recommendations
and inserts in final paragraph (a) ‘‘on
acquired lands’’ as well as ‘‘separate
from, and in addition to, the limitation
for public domain lands.’’
Federal Lands Administered by an
Agency Other Than the Bureau of Land
Management
Because of other proposed changes to
part 3100, the BLM proposed to
redesignate and consolidate the
provisions under this heading. The BLM
received several comments suggesting
that the new definition for ‘‘surface
management agency’’ under § 3000.5 of
this chapter, which includes Interior
agencies such as the Fish and Wildlife
Service and the Bureau of Reclamation,
conflicts with and causes confusion
with the provisions under this heading.
The BLM concurs and changes the title
of this heading from ‘‘Federal Lands
Administered by an Agency Outside of
the Department of the Interior’’ to
‘‘Federal Lands Administered by an
Agency Other than the Bureau of Land
Management.’’
Section 3101.51 General Requirements
and Section 3101.52 Action by the
Bureau of Land Management
The BLM received numerous
comments on proposed revisions,
which, collectively, would replicate
several paragraphs in the existing
regulations requiring the BLM to seek
and, in some cases, obtain the consent
of surface management agencies prior to
leasing acquired or public domain lands
into one paragraph. Some comments
supported the change. Several
comments opposed the change,
asserting that it expands the authority of
some surface managing agencies, such
as the Fish and Wildlife Service and the
Bureau of Reclamation, beyond that
which is provided under the applicable
statute.
The BLM disagrees that the proposed
change improperly expands the
authority of certain surface management
agencies, such as the Fish and Wildlife
Service. Instead, this change merely
consolidates and clarifies the BLM’s
duties with respect to prohibitions
provided elsewhere in statute or
regulation. The BLM has a longstanding
practice of consultation with all Federal
surface management agencies before
authorizing subsurface mineral leasing.
For example, the existing regulation at
43 CFR 3101.7–1 recognizes that in
some cases the Secretary may lease over
the objection of the surface management
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agency and in other cases the Secretary
may not. Moreover, even where consent
is statutorily required, such as on Forest
Service lands, the MLA directs that the
Secretary of the Interior the Secretary of
the Interior ultimately must apply their
independent judgement before any
leasing may occur. The proposed
regulation merely supplies the BLM
with the uniform procedures necessary
to facilitate these preexisting
prohibitions and grants of discretion; it
does not enlarge or restrict the BLM’s
authority. The BLM has added a clause
to § 3101.52(b) to clarify that a lack of
consent or concurrence will preclude
leasing only where provided by law.
The BLM has also made certain minor
changes for clarity.
Commentors stated that, under the
MLAAL, 30 U.S.C. 352, only the head of
an executive department has the
authority to consent to leasing covered
by that statute, such that it necessarily
does not embrace ‘‘consent’’ by
subdivisions of the DOI. The BLM
agrees, particularly because the
Department’s sub-agencies ordinarily
enjoy their authority only be virtue of
delegation from the Secretary. As set
forth above, the proposed text does not
alter the balance of authority and
discretion among agencies within the
Department, but instead simply clarifies
that the BLM shall, as a procedural
matter, confer with surface management
agencies.
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Section-by-Section Discussion for
Changes to 43 CFR Subpart 3102
Section 3102.20 Non-U.S. Citizens
The BLM proposed to revise the
existing § 3102.2 to remove the
reference to the outdated term ‘‘alien.’’
The BLM received a comment stating
that this section should be amended to
include more stringent language that
would require prospective, non-U.S.
citizen bidders, lessees, or interest
holders to submit to the BLM a
certification of compliance with Federal
foreign ownership laws and procedures,
including the final rule from the Office
of Investment Security, Department of
the Treasury, implementing the
provisions relating to real estate
transactions in section 721 of the
Defense Production Act of 1950, as
amended by the Foreign Investment
Risk Review Modernization Act of 2018,
prior to the BLM granting such entities
a lease. The BLM declines to adopt this
change, which is unnecessary. In 1982,
the BLM eliminated the requirement for
entities to submit documents
substantiating their qualifications to
hold a lease or an interest in a lease and
now requires entities to certify their
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compliance, including those relating to
foreign investment in Federal land, on
the lease or assignment application. Any
false statements on these documents are
subject to the criminal sanctions in 18
U.S.C. 1001 (see 47 FR 8544, February
28, 1982).
Section 3102.40 Signature
The BLM proposed changes to the
existing § 3102.4 to clarify that it applies
to all applications submitted to the BLM
and to allow for electronic signatures.
The BLM received a comment in
support of the proposal to remove
paragraph (b) from this section. The
commenter also said the BLM erred, as
the submission of three hard copies of
any transfer of record title or operating
rights is required by the MLA. 30 U.S.C.
187a. The BLM agrees and makes the
appropriate changes to the final
§ 3106.41. The BLM declines to reinstate
paragraph (b) in this section to avoid
confusion when the BLM starts
accepting transfers electronically.
Section 3102.51 Compliance
The BLM proposed revising the
existing § 3102.5–1 to clarify who is
entitled to hold a lease and that the
reclamation obligations under the lease
reside with the lessee, operating rights
owners, and operators, and not the
American taxpayer. The BLM received
comments in support of the proposed
changes to this section and a
recommendation in a comment that the
BLM publish and regularly update the
list of entities that are not in
noncompliance with reclamation
requirements of section 17(g) of the
MLA. Many comments opposed the
proposed changes, citing a lack of due
process, fairness, the BLM’s ability to
take enforcement actions to address any
compliance deficiencies, and the need
to provide entities the ability to remedy
any alleged compliance issues before
the BLM turns to cancelling a lease,
among other concerns.
To address the comments, the BLM is
revising the phrase ‘‘will be subject to
cancellation’’ to ‘‘may be subject to
cancellation’’ to clarify that cancellation
is only one of the enforcement tools the
BLM could apply and allows for due
process. As provided under § 3000.40 of
this chapter, any decision issued by the
BLM pursuant to this section would be
subject to appeal. In addition, the BLM
updates the list of ‘‘Entities in
Noncompliance with Reclamation
Requirements of section 17(g) of the
MLA’’ on an as-needed basis, and then
forwards the names of the entities to the
Federal Government’s suspension and
debarment program. SAM.gov is a
publicly available website that contains
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the list of suspended or debarred
entities. Likewise, when a company
returns to compliance, the BLM notifies
the suspension and debarment program
that the entity should be removed from
SAM.gov. The BLM declines to publish
a duplicate list of these entities. Thus,
no further changes are warranted.
Section 3102.52
Compliance
Certification of
The BLM proposed a minor change to
the existing § 3102.5–2: the removal of
the word ‘‘offer’’ to reflect Congress’
elimination of the noncompetitive
leasing process. The BLM received a
comment on this section recommending
additional language to explicitly state
that any false certification is subject to
the criminal penalties contained in 18
U.S.C. 1001. The BLM declines to adopt
this proposal, which is unnecessary.
Section 3000.20 of this chapter already
informs all entities that they are subject
to criminal penalties if they provide
false statements to the BLM. In addition,
the standard forms used by the BLM
under these regulations, such as the bid
form (3000–002), assignment of record
title form (3000–003) and the transfer of
operating rights (3000–003a), and the
lease form (3100–011), all include
similar statements and references to 18
U.S.C. 1001 for any false statements.
5. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3103
Section 3103.1
Fiscal Terms
The BLM removes the proposed
§ 3000.130 from the final rule and
moves the information in that section
into final § 3103.1, since this section
addresses oil and gas fiscal terms and
does not impact other minerals
management programs. Therefore, the
BLM determined that it is more
appropriate to codify this section in
subpart 3103 instead of part 3000. As a
result of this change, the BLM updated
all cross references in the final rule from
§ 3000.130 to § 3103.1.
Based upon the comments received,
the BLM also incorporates additional
updates that include: (1) adding the EOI
filing fee from the IRA to this section
and (2) changing the timeframe that the
BLM will adjust the fees for inflation
from annually to once every 4 years.
First, the BLM moved the new EOI
filing fee, established by the IRA, from
proposed § 3000.120 to final § 3103.1(a).
The BLM cannot update the EOI fee
annually. The MLA at 30 U.S.C.
226(q)(2)(B) states, ‘‘The Secretary shall,
by regulation, not less frequently than
every 4 years, adjust the amount of the
fee under subparagraph (A) to reflect the
change in inflation.’’ Therefore, the final
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rule moves the EOI fee to paragraph (a).
Second, the EOI fee will be adjusted
every 4 years by way of a final rule as
part of the new Fiscal Terms Table. The
BLM also changed the adjustment for
minimum bonus bids and rentals to be
adjusted every 4 years for inflation by
way of a final rule. This change will
allow the final rule to update these
terms to occur at the same time and
minimize the public’s costs for these
inflation adjustments. The BLM also
renamed the title of this section from
‘‘Fiscal terms of new leases’’ to ‘‘Fiscal
terms.’’
One commenter stated that the BLM
should tie all costs and returns
associated with oil and gas leasing to an
inflation index. The BLM did not make
any changes in response to this
comment, as all fees in § 3000.120, the
fiscal terms in § 3103.1, and the
minimum bond amounts are tied to
changes in the Implicit Price Deflator for
Gross Domestic Product, which is
published quarterly by the U.S.
Department of Commerce. Finally, a
comment stated that the BLM should
clarify that the inflation adjustment as
described in this section will include
adjustments for inflation occurring over
any period of multiple years after
August 16, 2022, during which bid and
rental rates were left unchanged despite
inflation. The BLM concurs with this
recommendation, which is reflected in
the existing regulations and its use of
the Implicit Price Deflator for Gross
Domestic Product.
Another commentor stated that the
proposed rule references no authority
that would support annual inflation
adjustments for the rental and bonus as
the IRA precludes the adjustment of
these fiscal terms until after August 16,
2032. The BLM agrees that the rental
and minimum bonus bids must remain
at the current rate until August 16, 2032;
however, after this date, the IRA
changes these amounts to minimums.
Therefore, the BLM proposed and is
implementing inflation adjustments for
rental amounts and minimum bonus
bids after August 16, 2032. To reduce
confusion, the BLM updates paragraph
(a) by adding the sentence, ‘‘Per the
Inflation Reduction Act, the BLM will
not adjust the rental nor the minimum
bonus bids until after August 16, 2032.’’
Section 3103.12 Where Remittance is
Submitted
The BLM proposed to update the
existing § 3103.1–2 to clarify that fees
set out in the fee schedule in § 3000.120
of this chapter and all first-year rentals
and bonuses for leases issued under 43
CFR part 3100 must be paid to the
proper BLM office. This final section
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also removes outdated references to the
former Minerals Management Service
and mailing address for payments. The
BLM received a related comment on
lease reinstatements, in which the
commenter stated that references in the
BLM regulations to rental payments
through the ONRR’s online system
should also acknowledge ONRR’s
continuing practice of accepting nonelectronic rental payments in some
circumstances. The BLM concurs and
changes the language in paragraph (a)(2)
from ‘‘through its online system’’ to
‘‘refer to 30 CFR 1218.51’’ that lists the
methods by which lessees and operators
may submit payments to the ONRR.
Section 3103.21 Rental Requirements
The BLM requested comments on
adding a new requirement for diligent
development obligations.
Comments that supported a diligent
development provision included
recommendations that the BLM: (1)
implement further leasing reforms, such
as increasing production from existing
leases by ensuring diligent
development, implementing specific
diligent operations standards, and
adopting a mechanism to hold private
companies accountable when they fail
to meet the requirements; (2) tie the
diligent development requirement to the
definitions of ‘‘qualified lessee,’’
‘‘responsible bidder,’’ and ‘‘responsible
lessee;’’ and (3) impose a diligent
operator standard with reporting
requirements, and absent a rental rate
increase, clarify what consequences an
operator may face when it fails to
operate diligently including lease
termination. Comments also asserted
that the proposed lease rentals are
insufficient and leases that are not
pursued for development within 5 years
should be permanently revoked and
should not be transferable to another
entity.
Comments that opposed a diligent
development provision included
statements that: (1) failure to act
diligently to develop a lease has no
adverse impacts on the environment; (2)
adding diligent development obligations
would result in additional work for the
BLM and an unnecessary burden on
lessees; (3) the increased rental rates
prescribed by Congress in the IRA and
adopted in the final regulations will
encourage diligent development on their
own and encourage prudent
development or lease surrender; (4) the
diligent development obligations would
impact business decisions that are based
on markets, investment capital, supply
chains, labor and equipment
availability, and other factors; (5)
geophysical exploration does not always
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result in lease development; (6) new
diligent development terms would
impose large cost increases on many
leases and inhibit operator flexibility to
properly evaluate and commence
operations in a responsible
developmental situation and economic
manner consistent with lease
requirements; (7) a diligent
development requirement could
exacerbate the climate crisis; (8) the
BLM should consider delays that are out
of an operator’s control, such as the time
certain Federal processes or lawsuits
can take; (9) the proposed rule’s list of
alternatives is overly lenient and
promotes speculative ventures; and (10)
the BLM should not apply too broad an
interpretation of diligent development.
After careful consideration of the
comments received, the BLM did not
implement a diligent development
requirement with an escalating rental
rate in the final rule. The BLM believes
the existing increasing rental rates
prescribed by Congress in the IRA will
encourage diligent development on their
own by incentivizing lessees and
operators to develop a lease to avoid the
increased costs. The BLM will continue
to assess the oil and gas leasing
program, and if the BLM determines
Congress’ rental rate increases are not as
effective as expected at encouraging
diligent development, the BLM may
consider additional rulemaking. The
BLM further clarifies final paragraph (a)
by adding, ‘‘for that lease’’ after the
words ‘‘total acreage’’ to clarify the basis
for calculating the first-year rental. No
further changes have been made to this
section.
Section 3103.22 Annual Rental
Payments
The BLM proposed changes to the
existing § 3103.2–2 to implement
changes made by Congress in the IRA
and clarify what constitutes a timely
payment of rental by tying the payment
to the lease anniversary date. The BLM
received numerous comments on this
section. The comments encouraged the
BLM to: (1) set out the actual required
rental amounts, as provided by the
current regulations, rather than referring
to the lease terms; (2) set a policy
determining when rental rates should be
higher than the statutory minimums; (3)
implement the regular rate increases;
and (4) further increase the rental rates,
on the theory that the rental rates in the
IRA are too low.
In the IRA, Congress set rentals at $3
per acre, or fraction thereof, for lease
years 1 and 2; $5 per acre, or fraction
thereof, for years 3 through 8; and $15
per acre, or fraction thereof, thereafter.
Ten years after the enactment of the
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IRA, those rental rates become
minimums and are subject to increase,
as discussed in § 3103.1. The BLM
agrees with the comments that the
section in the proposed rule was not
clear and adds the following clause at
the end of paragraph (a) ‘‘the annual
rental for all new leases will be as
specified in 43 CFR 3103.1.’’ 43 CFR
3103.1 sets out the actual required
rental rate, provides details on when the
BLM will increase the rental rate, and
implements a rate increase every 4
years. The BLM cannot increase the
rental until August 16, 2032, based
upon Congress’ direction in the IRA.
Another comment objected to the
application of these rentals to leases
sold before the passage of the IRA but
issued after the IRA was signed into
law. The commenter explained that
companies bid on those parcels relying
on the rental and royalty rates that were
in effect at the time of the lease sale and
contended that lease issuance was only
delayed due to the BLM’s failure to
timely resolve protests.
As explained in the preamble to the
proposed rule, the IRA amended the
rental rate for all new oil and gas leases
issued in the next 10 years. Because the
statute ties the new rates to lease
issuance, the BLM does not have the
authority to exempt leases sold but not
issued prior to the enactment of the IRA
from its terms.
Section 3103.31 Royalty on Production
The BLM proposed changes to the
existing § 3103.3–1 to implement the
requirements of the IRA and received
numerous comments.
Supportive comments recommended
that the final rule address plans, specify
criteria, or include a procedure for
increasing the royalty rate after 2032.
These comments suggested various
ways to implement this
recommendation, including codifying a
higher royalty rate of at least 18.75
percent, or 20 percent; increasing the
royalty rate consistent with the previous
10-years’ worth of inflation, but not
deflation, and indexing the royalty rate
to raise at prescribed intervals; or
adjusting all rates to market levels on a
regular basis to better ensure fair return.
Supportive comments also requested a
termination provision, similar to that for
failure to pay rentals, for the failure to
pay royalties. Other supportive
comments stated that the BLM should
limit changes to just those required by
the IRA, as the new rate could affect the
competitiveness of the U.S. minerals
program.
Comments that opposed the changes
included statements that: (1) higher
royalty rates have consistently led to
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increased revenues without
discouraging oil and gas development
and the new rate of 16.67 percent is still
well below the rate that is charged for
offshore drilling in Federal waters
(18.75 percent) and imposed by leading
oil-and gas-producing States, including
Texas (20–25 percent), Colorado (20
percent), and New Mexico (18.75 to 20
percent); (2) the final rule should refrain
from setting a minimum rate because
the cost of operating on Federal lands is
higher than on State or private lands,
and a higher royalty will make it
uneconomic to operate on most Federal
lands; (3) the higher minimum, and any
increased royalty rate, will
disincentivize operations on Federal
lands, harming small business, local
governments, and States; (4) the BLM
failed to provide a justification for
making the royalty rate the minimum,
and the bureau should consider
establishing 16.67 percent as the
maximum with a mechanism for
determining a lower rate when the 10year statutory requirement expires; (5)
the BLM should not comply with the
IRA’s mandate or adopt a permanent
royalty relief rule for onshore
production; (6) raising oil and gas
royalty rates will directly reduce well
operators’ revenue margins, risking well
closures and deliberate attempts to
devalue oil fields; (7) higher royalty
rates affect long term project economics
by reducing the expected revenue and
making them less financially feasible;
(8) higher rates will deter small
operators from investing in expensive
enhanced oil recovery methods that can
extend the productive life of a well; and
(9) raising the Federal royalty rate
encourages cheating and requires greater
Federal investment in compliance
enforcement at taxpayer expense.
As stated in the proposed rule, the
BLM updated this section to implement
IRA section 50262, which set royalty
rates at 16.67 percent for the 10 years
following the Act’s enactment. Final
paragraph (a)(3) of the regulation states
that for leases issued after the 10-year
period following the passage of the IRA,
the royalty rate will be not less than
16.67 percent, which is the rate
Congress required in the IRA. The BLM
declines to set post-2032 rates now (or
to implement associated procedures) so
far in advance of any authorized
increase. However, the BLM may
consider further adjustments after 2032.
The BLM also declines the suggestion to
implement an automatic termination
provision for the nonpayment of
royalties. The procedures for lease
forfeiture and cancellation are set forth
in section 31(a) of the Act (30 U.S.C.
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188) and § 3108.30(b) of the regulations.
The BLM adopts this section into the
final rule without any further changes.
Section 3103.41 Royalty Reductions
The BLM proposed revising the
existing § 3103.4–1 to clarify that
production in paying quantities is a
prerequisite to obtaining royalty relief
under this section. The BLM also
solicited feedback to improve the
royalty rate reduction section.
Comments recommended that the
BLM: (1) describe the specific
circumstances for justifying a reduction
and clarify that the reductions will
terminate as soon as the conditions
justifying the reduction have passed; (2)
explicitly state that a royalty rate
reduction would transfer to the new
lessee when a lease is assigned; (3)
provide specific criteria for lowering the
rate; (4) set a limit on the lower end of
the reduced rate; (5) limit the period for
the reduction to apply; (6) specify that
reduced royalties transfer to assignees
only on a case-by-case basis; (7) extend
royalty relief to all producers at any
point of production; (8) extend the
royalty relief to any field where
operators are seeking to conduct or are
conducting waterfloods or other
enhanced oil recovery methods; (9) not
set a floor for royalty reductions because
a universal rate, even a low one, cannot
account for the varying productivity
within a formation; (10) determine the
royalty relief by the field productivity
and the crude grade produced; (11)
determine the appropriate royalty rate
reductions based upon a critical review
of the economic data for reasonableness
and clearly enumerate the costs that are
allowed for the economic evaluation to
ensure operators send unbiased data;
(12) closely monitor any approved
royalty reduction; (13) clearly define
under what circumstance/criteria
royalty reduction terminates; (14) revise
the phrase ‘‘royalty reductions at the
discretion of the Secretary’’ to convey
that reductions are the exception, not
the norm; and (15) add language to
require notification to the State when
royalty reductions take place, given the
State’s interest in the royalty rate and
the economic health of the industry and
local communities.
The BLM rarely grants royalty rate
reductions, and after careful review of
the comments, has decided against
making any further changes. The
regulation states that the Secretary may
waive, suspend, or reduce the rental or
royalty upon a ‘‘determination that it is
necessary to promote development or
that the leases cannot be produced in
paying quantities under the terms
provided therein.’’ Thus, the BLM only
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grants a reduction in royalty rate if the
operating costs exceed the gross income.
Otherwise, the BLM would deny the
royalty rate reduction. The regulatory
requirements reflecting these parameters
come directly from the statutory
authorization for royalty reductions at
30 U.S.C. 209. Additionally, if the
operating costs would still exceed the
gross income with a royalty rate
reduction, the BLM must consider
terminating the lease for no longer being
capable of production in paying
quantities under 43 CFR 3107.22.
The factors the BLM considers when
evaluating a reduction are case-specific,
and the BLM must review each
application. Given this and the
exceptional nature of circumstances that
may warrant royalty reductions, the
BLM declines to further specify the
circumstances or specific criteria for
lowering a royalty rate in the regulation
in order to retain the discretion of the
authorized officer to address case
specific situations that may occur. The
BLM is committed to adhering to the
existing rules and policy and will
ensure that they are consistently and
faithfully applied to future royalty relief
applications.
Second, the BLM declines to codify
language stating that a royalty rate
reduction would transfer to a new lessee
when a lessee assigns its lease. The
operating costs for the lease may change
with the new lessee; therefore, the BLM
would need to complete a new review
to determine if the royalty rate
reduction is appropriate.
Third, some commenters opposed and
some supported implementing a lower
limit for royalty reductions, but no
lower limit was proposed. The BLM has
decided not to implement a lower limit
and will instead continue to rely on the
economics of each lease to determine
the appropriate royalty reduction, if
warranted.
Fourth, the BLM will not provide
royalty relief based only upon operators
conducting or seeking to conduct
waterfloods or other enhanced oil
recovery methods. These operations will
return a profit to the operators and in
most cases a royalty reduction would
not be appropriate as the gross income
exceeds the operating costs.
Fifth, the requirements to monitor
royalty rate reductions or to send notice
to States are better suited to be
addressed through policy as these
requirements would apply only to the
BLM and not the regulated community.
The BLM already tracks royalty rate
reductions in MLRS and will continue
to closely monitor reductions. Given
how rare royalty rate reductions are, the
BLM has not established a requirement
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to notify the States. The BLM will
consider whether a notification to the
States should become a matter of policy
in the future.
Sixth, the existing regulations and
Bureau policy reserve the BLM’s right to
terminate a royalty reduction, re-adjust
the amount of reduction, or restore the
royalty rate to the rate required by the
lease terms and/or regulations at any
time for the entire lease or for any
portion thereof. Given that the grant of
a royalty rate reduction is uncommon,
the BLM is declining to add any blanket
provisions to the regulations that would
remove this flexibility. For example, the
BLM may need to terminate relief
retroactively if such relief was based on
manipulation of normal production or
adulteration of oil sold.
Sections 3103.42 Stripper Well
Royalty Reductions and 3103.4–3 Heavy
Oil Royalty Reductions
The BLM proposed to eliminate both
of §§ 3103.4–2 and 3103.4–3 in their
entirety because they are obsolete for
the reasons described below. The BLM
received a comment stating the BLM’s
removal for obsolescence ignores the
fact that over the next decade, the
number of stripper wells on Federal
lands will rise along with necessary oil
exploration and production.
As stated in the proposed rule, the
BLM revised both sections on October 6,
2010 (75 FR 61624), to eliminate these
types of royalty relief, because Congress
enacted separate relief in section 343 of
the Energy Policy Act of 2005 (42 U.S.C.
15903). However, the BLM retained the
regulations because, while these types
of royalty relief were no longer available
for current production, prior production
subject to this relief continued to be
subject to audits. This is no longer the
case; therefore, these provisions serve
no purpose. To the extent relief is
required in the future, the BLM would
promulgate any necessary regulations
under section 343 of the Energy Policy
Act of 2005 rather than relying on these
provisions. In addition, the BLM has the
authority under section 39 of the MLA
to waive, suspend, or reduce the royalty
for a lease.
Section 3103.42 Suspension of
Operations and/or Production
The BLM proposed redesignating this
section from 43 CFR 3103.4–4 to 43 CFR
3103.42 and clarifying how a lease term
will be adjusted once the suspension
ends.
The BLM received a comment on
paragraph (a) stating that the BLM
should broaden the circumstances for
which a lease would be eligible for a
suspension of operations only or a
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30933
suspension of production only beyond
force majeure, or at a minimum should
acknowledge that the BLM’s own delays
constitute such a force majeure for the
purposes of these types of suspensions.
The regulations clarify that a force
majeure is ‘‘matters beyond the
reasonable control of the lessee.’’
Because this encompasses an
administrative delay, the BLM already
takes such delays into consideration
when evaluating a suspension. The BLM
is not revising the regulation to further
specify instances that may be
considered force majeure; BLM Manual
3160–10, Suspension of Operations and
or Production, provides further
examples of acts constituting force
majeure.
Some comments stated that lease
suspensions, whether requested by the
lessee or directed by the BLM, should be
made public as soon as they are
submitted and should be subject to
public review and comment in
accordance with NEPA. The BLM
disagrees with this recommendation.
NEPA is only triggered if there is a
proposal for a major Federal action that
potentially affects the environment.
Although the approval or direction of a
suspension is a Federal action, lease
suspensions are categorically excluded
from NEPA review as administrative
actions taken on an already existing
authorized lease. See the BLM’s
National Environmental Policy Act
Handbook H–1790–1, Appendix 4.12
Some comments stated that the BLM
should clarify that both the suspension
request and the decision by the BLM
must be made in writing and published
on a BLM website, and that the
proposed rule fails to provide the
transparency and public access to
information about lease suspensions
that is guaranteed by the Administrative
Procedure Act. The BLM disagrees with
this comment, as suspension decisions
have always been publicly available
through review of the case file located
in the relevant BLM state offices or
through the BLM’s reporting application
at https://reports.blm.gov/reports/MLRS.
Another comment stated that the BLM
should clarify in paragraph (d) that any
lease production is prohibited while a
suspension of operations and
production is in effect. The BLM agrees,
and it is BLM policy that production
from a lease is prohibited if there is a
suspension of operations and
production. See BLM Manual Section
3160–10, Suspension of Operations
12 https://www.blm.gov/sites/blm.gov/files/
uploads/Media_Library_BLM_Policy_Handbook_
h1790-1.pdf.
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and/or Production.13 The rule provides
that ‘‘if there is any production sold or
removed during the suspension, the
lessee must pay royalty on that
production.’’ This statement covers
instances where there are no operations
or production, but the operator sells
already existing product captured prior
to when the suspension went into effect;
it does not supersede the ordinary bar
on production during suspensions, and
merely ensures the lessees pay royalty
on that sold production.
Multiple commenters stated that the
BLM should: (1) clarify that lease
suspensions are the exception and not
the rule; (2) provide limited and specific
criteria that would justify a suspension;
and (3) offer guidance on how the BLM
plans to deal with existing lease
suspensions. The BLM declines to
modify the regulations as detailed in the
three comments above. The MLA
provides direction, and the BLM has set
guidance on when a lease suspension is
appropriate. First, the BLM currently
has approximately 3,000 suspended
leases of the over 33,000 authorized
onshore oil and gas leases. While
suspensions are not a common
occurrence, the number of lease
suspensions has increased based upon
the large number of leases litigated in
court after lease issuance over the past
decade. Second, the BLM declines to
provide limited and specific criteria in
the regulations. The BLM provides
guidance to its employees in IMs and
MS–3160–10, Suspension of Operations
and/or Production.14 The BLM declines
to make this change at this time to retain
the discretion of the authorized officer
to address unique situations that may
occur. Third, the BLM already
established guidance on how the BLM
plans to deal with existing lease
suspensions in Permanent IM 2019–007,
Monitoring and Review of Lease
Suspensions; 15 therefore, the BLM
declines to add this information into the
regulations. The existing regulations
require evaluation of lease suspensions
on a lease-by-lease basis. Reviews of
existing lease suspensions are currently
addressed in the BLM’s policy IM 2023–
012, Suspension of Operations and/or
Production 16. No changes have been
made in the final rule to avoid limiting
the discretion of the authorized officer
to address unique situations that may
occur. For example, litigation or actions
of Federal or State agencies that prevent
13 https://www.blm.gov/sites/default/files/docs/
2022-03/MS-3160-10%20Rel.%203-150.pdf.
14 https://www.blm.gov/sites/default/files/docs/
2022-03/MS-3160-10%20Rel.%203-150.pdf.
15 https://www.blm.gov/policy/pim-2019-007.
16 https://www.blm.gov/policy/im-2023-012.
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commencement or continuation of
operations may be applied to
suspensions granted under section 17(i)
or section 39 of the MLA depending on
the unique circumstances of the case.
A commenter was concerned that
changing the word ‘‘terminating’’ in
existing paragraph (e) to ‘‘lifting’’ in
final paragraph (g) will be interpreted by
lessees and others to require the BLM to
take affirmative action to end a
suspension. The comment states that a
lease suspension should lift
automatically—without any subsequent
administrative action by the BLM—
when certain regulatory events occur or
as otherwise stated in the approval
letter, and the BLM should avoid any
change that would increase the
administrative burden on the agency.
The BLM disagrees with this comment.
While it is true that, in some cases, the
BLM’s decision to suspend a lease will
document a particular event or action
that will eventually lift a suspension,
the BLM always issues a decision for the
official record when lifting a
suspension, allowing for the expiration
date of the lease to be properly adjusted
and facilitating any reconciliation of the
rental amount that may be due, see C.W.
Trainer, 69 I.D. 81 (1962). A copy of that
decision is sent to ONRR to notify it of
a change in the status of the lease. The
final rule did not change this process.
Based upon a review of the comments
received, the BLM did not make any
changes for this section from the
proposed rule: the process described
above is consistent with the term
‘‘lifting’’ as the term avoids confusion
and leads to an understanding that the
BLM takes an action to end a
suspension.
Section-by-Section Discussion for
Changes to 43 CFR Subpart 3104
In subpart 3104, the BLM proposed to
revise its bonding regulations by
increasing the minimum amount of
bonds, removing nationwide and unit
operator bonds, adding surface owner
protection bonds, and removing letters
of credit (LOCs) and CDs as options that
lessees can use to secure the required
bond amounts. The BLM received
several comments on the proposed bond
amounts. Some comments supported
the higher amounts, with some stating
these amounts do not reflect the full
reclamation costs of oil and gas wells.
Other commenters recommended the
final rule establish a full-liability,
individual lease bond or tie the bond
amount to the number of wells covered
by a bond. The MLA does not require
the BLM to impose full cost reclamation
bonds but does require the Secretary to
ensure the bonding is adequate to
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ensure reclamation. Requiring a full
liability bond would require increased
staffing at the field and state offices to
manage increased workloads for the
review of changing conditions and the
adjudication of additional bond riders to
either raise or reduce the bond amount.
In addition, the BLM’s APD processing
time would slow due to waits for
additional bond riders. The BLM has
opted to keep to a higher minimum
bond amount and depend upon its
policy guidance and future
adjudications for increasing the bond
amount for specific operations that pose
additional risk, which will allow the
BLM to direct its limited resources to
where they can have the most impact.
Comments also recommended that the
BLM review its average costs for
reclaiming orphaned wells, noting that
the States have identified a higher
average cost for their orphaned wells.
The BLM reviewed its costs related to
cleaning up orphaned wells that were
plugged since the BLM calculated the
average cost as part of this rulemaking
effort. Due to the limited number of
additional orphaned wells that have
been plugged in that time, there is not
enough additional data to warrant a
recalculation. Therefore, the BLM did
not adjust the minimum bond amount
based on a new average orphaned well
cost.
Some comments stated the BLM
should not have used the median
number of wells to determine the new
minimum bond amounts but rather
should have considered the probability
of the number of wells to be orphaned.
The BLM is unable to predict whether
any particular well will become an
orphan well due to many factors that
can lead to a well becoming orphaned
(e.g., operator’s revenue stream,
operator’s cost stream, current
regulatory framework within the State,
remaining oil and gas reserves, etc.) and
the lack of data for each of these factors.
Therefore, the BLM lacks the necessary
information to determine the probability
of a well to become orphaned and thus
did not use it as a basis to calculate
bond costs.
Several comments opposed the higher
minimum bond amounts and requested
that the BLM remove the proposed
bonding changes, explaining that the
BLM rarely needs to access a bond to
plug a well. Comments also asserted
that the BLM’s own statistics do not
justify the bonding provisions in light of
the MLA’s requirement for an adequate
bond. As stated in the proposed rule,
the minimum bond amounts have not
been increased since 1951 (for statewide
and nationwide bonds) and 1960 (for
lease bonds), have been repeatedly
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found inadequate by the GAO and the
OIG, and are no longer adequate to
provide the requisite funding for
reclamation when a lessee defaults on
its obligations.
The BLM received several comments
stating that the higher minimum bond
amounts will be a significant financial
burden on operators and small
businesses, because sureties often
require companies to post cash or
security collateral. The BLM disagrees.
The Small Business Administration
(SBA) helps small businesses guarantee
performance bonds issued by certain
surety companies, which allows the
companies to offer surety bonds to small
businesses that might not meet the
criteria for other sureties. The SBA’s
website states that all performance bond
guarantees require small businesses to
pay SBA a fee of 0.6% of the contract
price. The operator would need to make
a payment of $900 for an individual
bond or $3,000 for a statewide bond to
SBA, which would allow the small
entity to obtain a surety bond without
requiring the company to post cash or
security collateral. The BLM encourages
small businesses and operators to reach
out to the resources available to them
including those provided by the SBA
and visit their web page: https://
www.sba.gov/funding-programs/suretybonds.
In addition, the BLM conducted a
review of small entities operating on
Federal oil and gas leases based upon
public data. If these companies paid
sureties 3% of the additional bonding
cost annually, their overall cost-torevenue ratios would increase by less
than one-tenth of one percent. If these
companies instead chose to fund the full
bonding amount out of revenues, their
cost-to-revenue ratio would increase by
at most 1.4% for one year. Based upon
our analysis, the BLM certifies that there
will not be a significant economic
impact on small entities in the RFA;
refer to section V.B. Please also review
the RIA for more information.
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Section 3104.1
Bond Amounts
Based upon the comments received,
the BLM decided to implement inflation
adjustments for minimum bond
amounts. The BLM completed this
action by (1) adding the minimum bond
amounts to this section to provide for
inflation adjustments; (2) moving the
phase-in period for lease and statewide
bonds into this section; (3) providing a
longer implementation for small
operators to increase or replace their
bonds; and (4) providing information to
operators on the penalties they could
incur if they fail to increase or replace
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existing bonds that do not meet the new
minimum bond amounts.
First, the BLM requested comments
on whether it should adjust the
minimum bond amounts to keep up
with inflation. The BLM received
multiple comments recommending the
BLM periodically adjust the minimum
bond amounts to better protect the
taxpayer’s interests in adequate
reclamation. The BLM agrees with these
comments and updates the final rule to
include inflation adjustments to bond
amounts by way of a final rule and titled
this § 3104.1 ‘‘Bond amounts.’’ This
update will allow the BLM to
periodically update bond amounts
based upon the rates of inflation.
Second, the BLM moved the phase-in
period for statewide and individual
bonds from proposed § 3104.90 to final
§ 3104.1(c). The phase-in period for
lessees to replace unit and nationwide
bonds remains in final § 3104.90. This
change allows the BLM to easily update
the phase-in periods for individual or
lease bonds and statewide bonds upon
adjusting the minimum bond amounts
for inflation. The BLM anticipates that
when the minimum bond amounts are
adjusted for inflation in the future, the
phase-in periods will occur over 2 years:
• One year for statewide bonds, and
• Two years for individual bonds.
This phase-in follows the initial
proposed timeframes. The BLM has
calculated the staffing needs required to
process all bond increases for a 1-year
phase-in period and concluded the BLM
will require 2 years to provide sufficient
time to ensure all bonds are brought into
compliance.
Third, the BLM considered comments
regarding the impact to small operators
from increasing the minimum bond
amounts. Larger companies usually hold
nationwide or statewide bonds, while
smaller companies usually hold
individual bonds. Initially, the BLM
proposed to require individual bond
holders to come into compliance with
the new bond amounts first.
Commenters expressed concerns that
the higher minimum bond amounts may
force small operators out of business. To
alleviate some of the concerns expressed
by commenters with respect to the
impact on small operators and given the
large number of individual bonds, the
BLM has revised the final paragraph (c)
to give those with individual bonds
more time by phasing in this
requirement over a 3-year period,
instead of over a 2-year period. The
longer phase-in period for individual
bonds will provide more time for
smaller operators, who predominantly
rely on individual bonds, to research
and obtain the appropriate bond
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amount. When minimum statewide and
individual bond amounts are adjusted
for inflation in the future, the BLM
anticipates the shorter phase-in periods
(2 years for individual bonds) will be
sufficient for all bond holders to come
into compliance because the bond
amount increase will not be as
significant a change.
A comment expressed concern
regarding which penalties could accrue
to lessees who do not increase the bond
amounts within the time allowed. The
BLM reviewed its existing regulations
and added a new paragraph (d) to this
section to address this comment.
Paragraph (d) now refers to the existing
regulations that the BLM may use if an
operator fails to increase or replace an
existing bond as required by the
regulations. The potential penalties
include shut down of operations under
43 CFR 3163.1(a)(3), lease cancellation
under 43 CFR 3108.30, or referral of the
obligor or principal to the Department’s
Suspension and Debarment Program
under 2 CFR part 1400.
The BLM considered shorter
timeframes for inflation adjustments to
the minimum bond amounts, including
annual adjustments, but concluded that
shorter timeframes are unworkable
given the BLM’s workload associated
with possible enforcement. Instead, the
BLM has opted to update the minimum
bond amounts in the final § 3104.1 table
every 10 years. The final rule for the
updated bond amounts in the 3104.1
table will also indicate the new
deadlines for compliance. This 10-year
timeframe will provide sufficient time
for entities to come into compliance, for
adjudication of the financial assurances,
and for the BLM to ensure such
compliance prior to the implementation
of new minimum bond amounts.
The BLM received other comments
related to adjusting the fiscal terms for
inflation. One commenter stated that the
BLM should not attempt to
automatically adjust existing bonds for
inflation without the surety’s consent.
The phase-in periods will provide time
for the bonded principal to work with
the surety to increase the amount or
replace the bond. Another commenter
recommended that the BLM conduct
annual reviews and commit to increases
in line with larger economic trends and
not just inflation. The BLM will move
forward with updating the minimum
bond amounts based upon inflation
every 10 years as part of the final rule;
however, the BLM maintains the right to
conduct reviews of bonds to determine
if additional increases are necessary and
in the public interest.
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Section 3104.10
Bond Obligations
The BLM requested comments on the
proposed revisions to § 3104.1 along
with any supporting information on
whether the final rule should provide
for any other types of financial
arrangements that the BLM should
consider.
The BLM received several comments
stating the BLM should not eliminate
CDs and LOCs from the options
available to satisfy bonding
requirements, reasoning that the
elimination would impose an
unwarranted burden on lessees and
operators, particularly small operators,
and that the BLM should provide more
options to post the bonds rather than
eliminating options.
Based on the comments, the BLM has
decided to reinstate CDs and LOCs as
acceptable forms of security for a
personal bond. To resolve some of the
issues that led the BLM to propose
eliminating the securities, the BLM
made changes to the regulations for CDs
and LOCs. Given that CDs are now
issued electronically by banks, they do
not meet the existing requirement that
Secretarial approval be indicated on the
face of the document. Therefore, the
BLM modifies paragraph (c)(1) for CDs
by inserting ‘‘or through assignment’’ to
provide for Secretarial approval prior to
any redemption.
The BLM modifies paragraph (c)(5) for
LOCs to change ‘‘shall’’ to ‘‘must’’ or
‘‘will’’ as appropriate and consistent
with the similar changes made in the
proposed rule. The BLM also removes
the language ‘‘the deposits of which are
federally insured,’’ as this phrase in the
existing regulation has caused confusion
to both operators submitting a bond and
BLM staff who review bonds and their
associated securities. The $250,000
Federal deposit insurance limit for
deposits that a person may have with a
financial institution does not apply to
LOCs, because the guarantee of payment
under a LOC is made by the financial
institution directly to the BLM by
demand, see 31 CFR part 28.204–3(b).
LOCs are not depositor accounts to
which the Federal Deposit Insurance
Corporation (FDIC) insurance applies.
Therefore, the BLM is not concerned
with FDIC insurance when the amount
of a LOC exceeds the FDIC limit.
Paragraph (c)(5)(ii) is modified to
appropriately reference the types of
bonds as ‘‘an individual lease or
statewide bond,’’ and to change the term
‘‘attachment’’ to ‘‘collection’’ for clarity.
Paragraph (c)(5)(v) is modified to
state, ‘‘In the event the BLM is notified
of the financial institution’s intent not
to renew the letter of credit, the
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principal must extend the letter of credit
or provide an adequate replacement
bond with an assumption of liability
rider. If the BLM does not receive an
adequate notice or replacement bond
with rider, the BLM will collect the
letter of credit within 30 days of the
expiration without further notification
to the obligor.’’ The BLM is including
this language to ease the administrative
burden that results if an entity fails to
maintain the LOC. Previously, when an
entity failed to pay the premiums to the
bank, the BLM, in turn, had to notify the
obligor (the bonded party) to replace the
bond within 60 days; monitor the
timeframes to ensure the LOC is
extended or replaced; adjudicate an
acceptable form of replacement security
or bond; and send a demand to collect
on the letter of credit when all else fails.
The new language will reduce the
BLM’s workload by obviating the initial
notice to the obligor to replace the bond.
To be clear, the BLM will send a
demand to the bank to collect the funds
from the LOC 30 days prior to the
expiration date without further notice of
the action from the BLM when the
obligor fails to take corrective action on
their own accord.
For other types of financial
guarantees, one commenter
recommended that the oil and gas
program review the bonding
requirements and language of the BLM’s
solar and wind energy regulations in 43
CFR 2801.5(b) for consistency,
especially language regarding whether
corporate guarantees are an acceptable
or unacceptable bond instrument.
Another commenter stated that
alternative financial arrangements could
include insurance policies as both an
alternative and to complement surety
bonds such as insurance accounts to
pre-fund decommissioning costs, where
sureties direct a portion of their annual
premiums and payouts could be made
to the operator or the BLM upon default.
The BLM carefully considered the
comments and other forms of financial
assurance to secure bonding and is
declining to include any other forms of
financial assurance because the BLM
believes the current list, with the
retention of LOCs and CDs, is sufficient.
The BLM reviewed BOEM regulations,
which provide for corporate guarantees,
insurance, decommissioning accounts,
and other forms of security approved by
the Regional Director. The BLM also
reviewed the solar and wind energy
regulations, which provide for the same
financial assurances listed in this final
rule as well as insurance. As discussed
below, the BLM has decided not to
allow corporate guarantees and
insurance as means to satisfy the bond
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requirements. The BLM has determined
that corporate guarantees are not an
acceptable form of bond security given
the need to continually confirm the
viability of the corporate guarantee. The
BLM does not have the staff or expertise
to perform this function, and, without
the ability to closely monitor the
financial stability of the corporation
providing the guarantee, there is a risk
the company may default or go bankrupt
during the term of a lease, before
plugging and reclamation of the existing
well(s) and disturbance. To secure a
replacement bond at that time would be
difficult, if not impossible, thereby
potentially leaving the Federal taxpayer
to foot the bill for any necessary
reclamation.
While insurance is an acceptable form
of bond security used in other BLM
programs, the BLM declines to use
insurance for the oil and gas program
given the risks and increased
administrative workload for the
following reasons.
First, the basic principle of insurance
is the transfer of risk. It transfers the risk
of financial losses as a result of
specified but unpredictable events to an
insurer in return for a fee or premium.
While insurance is acceptable for
unforeseen events such as spills or
accidents, the BLM’s performance bond
secures the promise to fulfill a known,
contractual obligation an entity has
undertaken to perform at some point in
the future.
Second, an insurance policy is
usually a written contract between two
parties, the policyholder (the person or
company that gets the policy) and the
insurer (the insurance company). The
BLM would be a third-party beneficiary
under this scheme, and considered
appropriate language to that effect, but
this arrangement is still significantly
different from surety bonds where there
is a contract between three parties (the
BLM, the principal (or bonded party),
and the surety where the BLM is a party
to the agreement). Therefore, the BLM
would hold more risk because it is not
a party to the insurance.
Third, generally, either party to an
insurance contract may cancel the
contract unilaterally. To address this,
the BLM considered regulatory language
stating, e.g., that policy must be noncancellable. However, this could cause
confusion with cancellation of a bond
since existing § 3104 does not provide
for canceling or releasing oil and gas
bonds and the only time a bond is
canceled is by a court order. The
regulations only provide for terminating
the period of liability on the bond.
The BLM believes the revised
regulations provide sufficient options
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for the regulated community to meet the
bonding requirements, and, for all the
reasons stated above, the BLM has
determined not to rely on insurance for
bonding.
As mentioned above, BOEM’s
bonding regulations at 30 CFR 556.900
allow for the provision of ‘‘Another
form of security approved by the
Regional Director.’’ 30 CFR
556.902(e)(3). The BLM recognizes this
option provides a level of flexibility that
is not present in the BLM’s regulations.
However, the BLM has decided to
refrain from including a similar
provision in its regulations because the
BLM does not have staff to implement
such a provision. As of May 1, 2021,
BOEM managed about 2,287 active oil
and gas leases on approximately 12.1
million acres, while the BLM managed
35,871 leases on approximately 24.9
million acres. The BLM manages
significantly more leases and
significantly more bonds with no staff
solely dedicated to bond adjudication.
Instead, the BLM staff adjudicate both
bonds and post-leasing actions.
Therefore, the BLM does not have the
staff nor expertise to implement a
provision similar to 30 CFR 556.900.
The BLM considered
decommissioning, abandonment, or
trust accounts that can only be drawn
upon to cover decommissioning
expenses. Similar to corporate
guarantees, allowing the use of these
types of accounts would require
continual review of constantly changing
conditions and the expertise that BLM
staff lack.
Some comments stated the BLM
should require additional criteria for
surety companies to ensure that bonded
amounts will be available to the
regulator if, and when, the operator
defaults. The commenter recommended
that the BLM should adopt additional
criteria that (1) consider a surety’s
existing aggregate risk when
determining whether that surety
qualifies for certification, and (2)
impose an underwriting limitation on
the aggregate risk of all bonds issued by
a surety. The BLM declines to make this
change because the Department of
Treasury already reviews the
underwriting limitation and requires an
excess risk reinsurance to protect the
Federal Government. Please see
Department of the Treasury Circular 570
for more information.
Section 3104.20 Lease Bond
For the existing § 3104.2, the BLM
proposed changing the specifications
regarding who must post a bond to state
that the operator must be covered by a
bond in its name as principal or obligor.
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The BLM received a comment urging
the BLM to analyze the bonding regime
of the host State jurisdiction and decline
further bond requirements where that
State provides for bonding inclusive of
Federal leases and wells. The BLM
declines to adopt this proposal.
Including such a provision in the BLM’s
rules would require the BLM to execute
separate agreements between the BLM
and the State to allow the BLM to access
any funds available. Moreover, for such
arrangements to work, the State bonding
requirements must, at a minimum, cover
all of the terms and conditions of a
Federal lease, including the amount of
uncollected royalties due to ONRR, plus
the amount of money owed to the BLM,
as the lessor, due to previous violations
remaining outstanding. In the BLM’s
experience, these characteristics are
uncommon. The BLM would be in favor
of such an alternate bonding option if
any State is interested in pursuing
adequate arrangements, but the BLM
cannot make or assume the existence of
such commitments in this rulemaking.
A commenter stated that the BLM
should modify this section because it is
inconsistent with other sections and is
confusing. For example, § 3104.10 states
that, before the start of any surface
disturbing activities, the lessee,
operating rights owner, or operator must
submit a bond, whereas this section
states only that the operator must
provide a bond in its name. The
comment then stated that the BLM’s
primary concern should be that at least
one person post the required financial
assurance for a lease, and should leave
it to the operator, lessee, and operating
rights owner to determine among
themselves who will provide the
required bonding for a particular lease.
The BLM concurs that its primary
concern is that at least one person must
post the required financial assurance for
a lease and that the proposed changes to
this section may cause confusion.
Therefore, the BLM revised final
§ 3104.20 to be consistent with final
§ 3104.10, so that an operator, a lessee,
or an owner of operating rights
(sublessee) must be covered by a bond
in its own name as principal or obligor.
In order to be consistent with existing
§ 3171.9(a), the BLM added the
following sentence to the final rule
§ 3104.20: ‘‘The operator shall be
covered by a bond in his/her own name
as principal, or a bond in the name of
the lessee or sublessee, provided that a
consent of the surety, or the obligor in
the case of a personal bond, to include
the operator under the coverage of the
bond is furnished to the BLM office
maintaining the bond.’’
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30937
One commenter expressed concern
that the proposed rule did not consider
related operators or subsidiaries
operating under a parent company and
could cause a parent company to be
required to provide multiple bonds with
significantly greater total bonding. The
BLM disagrees. Under the existing and
final regulations, the BLM allows for coprincipals to submit a bond or to be
added through bond riders. Bond riders
can accompany the original bond or be
filed subsequent to the acceptance of the
bond. Therefore, the BLM is not making
any changes to the final rule based on
this comment.
A commenter urged the BLM to
require that an individual lease bond be
increased if it is to cover more than two
wells, and, in determining the lease
bond amount to be posted, that the BLM
must take into account a number of
variables including the well depth, the
presence of other resources, the number
of wells, the number of low-producing
or inactive wells, the capability of any
responsible party to carry out the
reclamation, the anticipated condition
of the well site, the extent of
reclamation and remediation to be
required, and compliance with the laws.
The BLM declines to make any changes
based on this comment, which, if
accepted, would require the BLM to
calculate each bond amount based on
constantly changing conditions. That
practice is unworkable given the
number of bonds the BLM is required to
maintain. The BLM already prescribes
when a bond will be increased in
§ 3104.50.
Section 3104.30
Statewide Bonds
In the proposed rule, the BLM
renamed the existing § 3104.3 due to the
proposed elimination of nationwide
bonds and proposed increase in the
amount of statewide bonds to $500,000.
The BLM received numerous comments
suggesting a larger statewide bond
amount if the bond: (a) covers more than
seven wells; (b) is based on a number of
variables; or (c) should be a set amount
for each additional well. Another
commenter recommended eliminating
both nationwide and statewide bonds.
The BLM declines to adopt these
suggestions, which would require the
BLM to calculate each bond amount
based on constantly changing
conditions; that practice is unworkable
given the number of bonds the BLM is
required to maintain. The regulations in
§ 3104.50 already specify when an
increase might be required and provides
the BLM with sufficient authority to
review and ensure bond amounts are
adequate.
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Nationwide Bonds
The BLM proposed to remove
nationwide bonding as an option due to
the administrative burden they impose
on the agency.
The BLM received comments
supporting the removal of nationwide
bonds. Those comments generally
asserted that no nationwide option can
fulfill the purposes of incentivizing
operator reclamation and ensuring
availability of adequate funds.
Comments that opposed the removal of
nationwide bonding stated there are
benefits to continuing the nationwide
tier for companies. Comments asserted
that this change would deprive lessees
and operators of a financial tool
currently available to mitigate bonding
costs by spreading them over a larger
universe of leases and that the BLM’s
analysis that these bonds are
administratively inefficient is not by
itself a reason to remove nationwide
bonds. Commenters pointed to language
in a draft version of the IRA bill that
included nationwide bonds, which
Congress ultimately removed before the
law was enacted.
The majority of the commenters who
wanted the BLM to maintain nationwide
bonds did not understand why the BLM
considered nationwide bonds more
difficult to manage and why the BLM
proposed eliminating nationwide bonds.
As stated in the proposed rule, for bond
adequacy reviews, the BLM state office,
which manages the nationwide bond,
must coordinate with every field and
state office with wells covered by this
type of bond. The BLM administrative
state office will usually contact between
4 (2 field offices and 2 state offices) and
40 (32 field offices and 8 state offices)
offices and request these offices to
conduct a bond adequacy review, which
entails pulling the operator’s well and
inspection records. This is needed as
the environmental and development
situations may vary between offices.
The administrative state office, while
familiar with its field offices, would not
be familiar with field offices in other
administrative state offices. This will
result in staff spending approximately 1
hour per office conducting the bond
adequacy review and the administrative
state office spending approximately 10
hours consolidating the reviews. With
coordination required with between 4
and 40 offices, this would result in
approximately $700 to $2,500 per bond
adequacy review (assuming $50 hourly
cost). Annually, this results in total
costs of $33,740 to $120,500.
With this change, the BLM will no
longer manage nationwide bonds and
instead will have additional statewide
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bonds. The BLM estimates that the 243
nationwide bonds would become
approximately 143 additional statewide
bonds (see the Regulatory Impact
Analysis for more information).17 The
BLM estimates that each administrative
state office would be able to review one
statewide bond using 10 hours of staff
time ($500 per bond adequacy review).
The administrative state office requires
less time to compile the review from the
field offices as there will be fewer field
office reviews to compile, so any time
needed by field offices within the state
office would come out of the assumed
10 hours of staff time. This would result
in an annual cost of $14,300, which is
a reduction of $19,440 to $106,200
annually. Overall, the BLM sees
significant administrative benefits with
the elimination of nationwide bonds.
Additionally, the elimination of
nationwide bonding in favor of the
proposed increase in the amount of the
statewide and lease bonds will allow the
agency to focus on specific areas and
fields to ensure the bonds are adequate
to cover reclamation costs in the event
an operator fails to complete proper
plugging and abandonment. As of
March 1, 2024, the BLM has identified
35 unplugged orphaned wells that were
covered by nationwide bonds. The
bonds covering these wells were
insufficient, so the BLM must seek
funds under the IIJA to plug these wells.
Localized bonding to the individual or
statewide level will allow the agency to
ensure improved bonding reviews,
reduces the administrative burden, and
the BLM anticipates additional
environmental benefits from this
regulatory change. As discussed in the
RIA, the BLM expects that the expedited
timing for reclamation of orphaned
wells from increased bonding could
provide benefits related to wildlife,
vegetation, soil erosion, climate change
(reduced greenhouse gas emissions from
unplugged orphaned wells), visual and
aesthetic resources, ground water, and
allowing the surface land to be utilized
for other uses sooner (for example, for
grazing purposes). The BLM cannot
currently quantify these benefits using
the information available to the BLM.
Finally, the BLM reviewed the
concerns from some commenters that
eliminating nationwide bonds would
deprive lessees and operators of one
financial tool for mitigating bonding
costs. No additional data or support was
provided beyond a statement that
17 The BLM reviewed its bonds and found many
bonds tied to no existing liability or operations. The
BLM expects to terminate the period of liability for
many of the nationwide bonds without liability,
which is why the 243 nationwide bonds would
become approximately 143 statewide bonds.
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nationwide bonds mitigate bonding
costs by spreading these costs over a
larger number of leases. The BLM does
not anticipate a large impact to lessees
and operators from this change, given
the other options available, such as
reinstating CDs and LOCs. The RIA
provides additional details on the
impact of eliminating nationwide
bonds.
Therefore, the BLM does not adopt
the recommendation to reinstate
nationwide bonds and is not making
any further changes to this section. As
stated in the proposed rule, the BLM
will be able to better tailor statewide
bond amounts to the local conditions
and State-specific requirements when
reviewing a bond for adequacy.
Section 3104.4 Unit Operator’s Bond
The BLM proposed eliminating
operator bonds because they are seldom
used and because the bonds are
obsolete. The BLM has been treating and
managing these bonds like statewide
bonds and eliminating them would
create efficiencies in the program. The
BLM received several comments that
supported the elimination of unit
operator bonds for the reasons the BLM
provided. The BLM also received a
comment stating the BLM should keep
unit operator bonds without providing a
reason why these should be kept. The
final rule eliminates unit operator
bonds.
Section 3104.40 Surface Owner
Protection Bond
The BLM proposed adding this new
surface owner protection bond section,
which is cross-referenced to 43 CFR
3171.19, to provide for an additional
type of acceptable bond that can be
submitted when the operator is unable
to reach a surface access agreement with
the surface owner. The BLM requested
comments on whether the BLM should
increase the minimum bond amount.
The BLM received numerous comments
on § 3104.40.
The BLM received comments
opposing the inclusion of this provision
on the basis that it duplicates State law
and should only apply to lands where
the surface is private, or that the BLM
also should address the interplay
between existing § 3171.19(b)(2) that
allows for an ‘‘agreement’’ with the
surface owner in lieu of bonding, noting
such an agreement does not necessarily
require payment of ‘‘compensatory
damages’’ as proposed in § 3104.40.
Comments also stated the BLM should
clarify that such bonds are not intended
to cover reclamation, but rather only
compensate a surface owner for
inadvertent, limited purpose,
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‘‘reasonable and foreseeable damages to
crops and tangible improvements,’’ as
stated in the proposed rule.
Some comments supported the
proposed $1,000 minimum bond
amount, while others stated the
minimum bond amount must be raised
to at least $10,000 per well to support
adequate remediation, plus an
additional $2,000 per acre of disturbed
land, and the impacts covered under the
surface owner protection bond must be
expanded beyond ‘‘the reasonable and
foreseeable damages to crops and
tangible improvements.’’
As stated in the proposed rule, the
BLM promulgated the current
requirements for surface owner
protection bonds through Onshore
Order 1 in 2007 and subsequently
codified these requirements in 43 CFR
subpart 3171. This bond is for the
limited purpose of ensuring a private
surface owner’s crops and other tangible
improvements are protected. In
response to comments, the BLM has
revised final paragraph (a) to remove the
phrase ‘‘to pay compensatory damages
to the surface owner,’’ to clarify the
purpose of these bonds and added the
phrase ‘‘under 43 CFR 3171.19’’ to
encompass the situation where an
agreement is reached with the surface
owner. The BLM reviewed the surface
owner protection bond amount and
determined it appropriate for the narrow
purposes of the bond. This bond covers
‘‘the payment of such damages to the
crops or tangible improvements (i.e.,
agricultural, residential and commercial
improvements, including improvements
made by residential subdividers) of the
entryman or owner.’’ See 43 U.S.C.
299(a). The BLM has not made any
changes to the minimum bond amount.
Paragraph I provides a process to
increase the bond if the surface owner
objects to the sufficiency of the bond.
This mechanism adequately addresses
the unique cases where the minimum
bond amount may need to be increased.
Finally, the BLM declines to
incorporate a provision that requires the
BLM to defer to State bonding
requirements for surface owner
protection bonds. First, not all States
require a surface owner protection bond
if the surface owner and Federal lessee
cannot complete a surface use
agreement for operations. In addition, a
State’s surface owner protection bond
provisions may not provide the same
coverage as required in the BLM’s
surface owner protection bond because
the State bonds are required under the
State’s law and not under Federal law.
See Wyoming Stat Ann. section 30–5–
402, Colorado Code Regs. section 404–
1–704, or New Mexico Stat. section 70–
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12–6. Therefore, the BLM declines to
incorporate a provision that requires the
BLM to defer to State bonding
requirements for surface owner
protection bonds.
Section 3104.50
Bonds
Increased Amount of
Although the BLM did not propose
any changes to the existing § 3104.5, it
did receive the following comments and
recommendations for the BLM to: (1)
require an increase in the bond amount
when the wells covered by the bond
exceeds the number of wells that the
BLM originally used to determine the
new minimum bond amounts; (2)
incorporate the BLM’s bond adequacy
review policy into the regulations; (3)
require a bond review when an operator
temporarily abandons or shuts-in a
Federal well; (4) change or expand the
risk factors described in paragraph (b);
(5) state that an operator may satisfy a
demand for an increased bond amount
by providing another form of security;
(6) state that any person aggrieved by a
decision to increase bond amounts may
seek review of a decision through State
Director review and appeal to the IBLA;
(7) remove ‘‘uncollected royalties due,’’
alleging that the bond amount should
not include amounts demanded,
payment of which is stayed pending
appeals under 30 CFR part 1243; (8)
explicitly state that operators do not
need to provide a full liability bond; and
(9) require bonds from record title and
operating rights holders for unpaid
royalty payments.
The MLA requires the Secretary to
ensure that bonding is adequate, and,
after review of the comments, the BLM
has determined that no changes are
needed to this section at this time. The
BLM’s proposed changes and additions
in 43 CFR 3104.1 and existing
regulations are sufficient to ensure
compliance with the lease terms. Bonds
given to the BLM are performance bonds
to guarantee performance of the lease
requirements. The performance bond
protects the BLM, and ultimately the
taxpayers, from financial loss should the
operator fail to perform and comply
with the regulations and laws governing
lease operations. This financial loss
includes unpaid royalty amounts;
however, the BLM will first use the
funds to address all outstanding
plugging and reclamation costs. The
BLM did not make any changes to the
appeal language that already exists in
the regulations and provides for both
IBLA appeals in 43 CFR 3000.40 and
State Director review when BLM staff
recommend increased bond amounts
pursuant to 43 CFR 3165.3(b).
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30939
In the proposed rule, the BLM
requested comments on whether to
require a bond adequacy review when a
well is temporarily abandoned. The
BLM received comments in support and
opposition to this proposal. After
reviewing the comments, the BLM has
decided not to require a bond adequacy
review for a change in well status,
including temporary abandonment of a
well. The BLM can review the adequacy
of a bond at any time, and the new
reporting and operational requirements
for operators of temporarily abandoned
wells will allow enhanced oversight of
these wells. The BLM considers the
discretionary authority to review a
bond, combined with the new reporting
and operational requirements, sufficient
to effectively manage any risks to the
environment associated with these types
of wells without needing to require a
bond adequacy review.
The BLM declines to change or
expand the risk factors described in
paragraph (b). The BLM considers the
existing risk factors to provide an
adequate basis for reviewing and
identifying the appropriate bond
amount. In addition, the BLM may
consider additional risk factors on a
case-by-case basis due to the language,
which states, ‘‘including, but not
limited to,’’ in the existing regulations
and in the final rule.
Further, the BLM may need to require
an entity to provide a full liability bond.
It is the BLM’s responsibility to take
proactive measures to minimize the
liability associated with high-risk
operators. To mitigate the public’s risk
with a high-risk operator, the BLM may
need to require a full liability bond on
a case-by-case basis; therefore, the BLM
declines to explicitly state that operators
do not need to provide a full liability
bond.
The BLM also declines to require
bonds from record title and operating
rights holders, in addition to operators,
for unpaid royalty payments. The BLM’s
bonds required for operations cover
both environmental liabilities and
unpaid royalty payments. At one point,
the BLM did require bonds from lessees;
however, the BLM moved away from
this practice in the 1980’s due to the
administrative burden related to
requiring lessees and operators to
maintain a bond. The BLM declines to
require bonds from record title and
operating rights holders, in addition to
operators, for unpaid royalty payments.
While the BLM used the median
number of wells to determine the new
minimum bond amounts, an increase to
the bond based solely on the number of
wells is unwarranted. The BLM will
capture the need for any bond increases
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based on its bond adequacy reviews. It
is the BLM’s responsibility to take
proactive measures to minimize the
liability associated with high-risk
operators, which may include full
liability bonding in certain
circumstances. The current BLM policy
outlined in IM 2024–014, Oil and Gas
Bonds Adequacy Reviews,18
supplements the requirements in this
section by directing reviews of existing
Federal bond amounts and requesting
increases to the bond amounts based on
the potential risk or liability posed by
the operators. As stated in the proposed
rule, similar bond adequacy review
policy has been in place for the past
decade, and the BLM has periodically
revised that policy to account for
changing risk factors including,
critically, the status of the well(s) and
the operator’s compliance history. The
BLM declines to incorporate risk factors
into the regulation in order to retain
flexibility in bond reviews and allow it
to adapt guidance more quickly to
changing needs. If the BLM issues a
decision requiring an increase in the
bond amount, the regulations do not
prohibit the operator from satisfying this
by providing another form of security.
Section 3104.70 Default
To improve clarity, the BLM proposed
to divide the existing § 3104.7 into three
separate paragraphs and included
language to address what happens in the
event a party fails to comply with the
requirements. The BLM received a
comment objecting to paragraph (b)(2),
stating that the paragraph effectuates the
equivalent of suspension or debarment
even if the BLM does not pursue that
route—with its corresponding
procedural protections—under
paragraph (b)(3). The BLM is not
proceeding with proposed paragraph
(b)(2), which refers to preventing the
bonded principal from acquiring
additional Federal leases, at this time.
The BLM prefers to continue to address
this situation through policy, as an
operator can still come back into
compliance even after the bond is
collected once all reclamation has been
completed and all monies owed the U.S.
have been paid.
Because the BLM is deleting the
proposed paragraph (b)(2), proposed
(b)(3) is now redesignated as (b)(2) in
the final rule.
Section 3104.80 Termination of Period
of Liability
The BLM did not propose any
changes to existing § 3104.8 but did
receive comments urging the BLM to
18 https://www.blm.gov/policy/im-2024-014.
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revise the section to clarify that any new
bond supersedes and replaces any prior
bonds, and that the liability of the prior
surety is terminated. The current
language addresses this comment by
stating the period of liability for a
previous bond will terminate once the
BLM receives a new bond meeting the
regulatory requirements.
Section 3104.90 Unit Operator and
Nationwide Bonds Held Prior to June
22, 2024
The BLM proposed this new section
to address the elimination of unit
operator and nationwide bonds and to
provide the timeline by which entities
must comply with the new bonding
requirements. The BLM received a
number of comments recommending
that the BLM adjust the minimum bond
amounts for inflation. The BLM has
addressed comments directed at
increasing bond amounts for inflation in
§ 3104.1.
A comment asked how the BLM plans
to terminate the liability of sureties
under unit operator and nationwide
bonds that are being eliminated. After
the final rules goes into effect, the BLM
will send a notice to the principals
maintaining the bond explaining the
new requirement to replace their bond.
Once an acceptable replacement bond is
received, the period of liability will be
terminated on the prior bond under
§ 3104.80. A replacement bond is not
considered acceptable unless it also has
an assumption of liability rider which
assumes any outstanding liability
accrued by the prior bond.
Multiple commenters requested that
the BLM exempt existing operations and
bond amounts as part of the final rule
or provide more time to meet the
increased bond amounts. The BLM
declines to exempt existing bond
amounts. The BLM, GAO, and OIG have
concluded that the BLM’s current bond
amounts are inadequate to protect the
Federal resources. If the BLM were to
exempt those bonds covering existing
operations, the problems identified by
the GAO and the OIG would persist.
The GAO, in report GAO–11–292, Oil
and Gas Bonds: BLM Needs a
Comprehensive Strategy to Better
Manage Potential Oil and Gas Well
Liability,19 recommended that the BLM
develop a strategy to increase the
regulatory minimum bonding amounts
over time and to more clearly define the
conditions that warrant a bond increase
beyond the minimum bond amounts.
The BLM implemented these
recommendations in policy; however,
the GAO, in report GAO–19–615, Oil
19 https://www.gao.gov/products/gao-11-292.
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and Gas: Bureau of Land Management
Should Address Risks from Insufficient
Bonds to Reclaim Wells,20 went on to
recommend that the BLM should take
steps to adjust bond levels, for all
bonds, to more closely reflect expected
reclamation costs. Reading these two
reports, it is clear that the BLM should
not exempt bonds covering existing
operations. Similarly, the OIG, in Report
No. OI–OG–12–0085–I, BLM Oil and
Gas Bonding Procedures,21
recommended that the BLM conduct
and support bond adequacy reviews and
bond increases periodically and do so
before problems arise. If the BLM
exempted the increased bond amounts
for existing operations, the BLM would
not be able to increase the bonds before
problems arise for the existing
operations. Further, increasing the
bonds for all operators maintains a level
playing field.
While the BLM declines to expand the
phase-in periods overall, swapping
them in final § 3104.1 to give individual
bonds the longer phase-in periods will
allow additional time for smaller
operators with individual bonds to
come into compliance. The holders of
nationwide bonds are larger companies,
which have increased staff and can
more easily comply with the updated
phase-in period to convert their
nationwide bonds to statewide and/or
individual bonds. The BLM updated the
phase-in period in the final rule by
requiring lessees and operators that
currently use nationwide and unit
bonds to come into compliance within
1 year of the effective date of the final
rule. This phase-in period provides time
for the BLM and its staff to process the
increased and new bond amounts
expected. The BLM has a total of 3,234
bonds: 975 individual or lease bonds,
1,987 statewide bonds, 19 collective
(unit) bonds, and 253 nationwide bonds.
Upon identifying that the majority of the
bonds are statewide and individual
bonds, the BLM determined that it made
more sense to revise the phase-in period
by requiring current nationwide bonds
to be brought into compliance first and
the others as follows:
• 1 year for nationwide and unit
bonds,
• 2 years for statewide bonds, and
• 3 years for individual bonds.
Specifically, this phase-in period will
provide individual lease bond holders—
the majority of those affected by the
provision of the rule, many of which are
small businesses—more time to prepare
20 https://www.gao.gov/products/gao-19-615.
21 https://www.doioig.gov/sites/default/files/2021migration/BLM%2520Oil%2520and%2520Gas%25
20Bonding%2520Procedures.pdf.
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for compliance, and, likewise, will
allow the BLM to prepare for the
associated workload.
Section-by-Section Discussion for
Changes to 43 CFR Subpart 3105
Communitization Agreements
Section 3105.21 Where Filed
The BLM proposed to remove the
requirement in the existing § 3105.2–1
to file the agreement in triplicate and to
specify the minimum contents for such
an agreement. The BLM received
comments on this section stating that
the BLM should include a fixed filing
fee for CAs. As previously stated, the
BLM considered proposing new fixed
filing fees for Federal CAs but
ultimately declined to add a fee due to
the public benefit of allowing Federal
and State minerals that might otherwise
be wasted to be developed.
A commenter stated that paragraph
(c), which recommends that an
application be submitted at least 90
days prior to first production, overlooks
that CAs are commonly submitted only
after production has been obtained, and
are usually effective retroactively to the
date of first production. The BLM’s
proposed language did consider this
fact, which is why the proposed section
says ‘‘should’’ instead of ‘‘must.’’
The final rule does not make further
changes in response to these comments.
The final rule did remove the acronym
‘‘CA’’ from the final regulatory text and
replace it with ‘‘communitization
agreement’’ for clarity and consistency.
Subsurface Storage of Oil and Gas
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Section 3105.42 Purpose
The BLM revised the existing the
existing § 3105.4–2 to clarify that gas
storage agreement applications must
include a bond. The BLM received a
comment stating that such agreements
should also be subject to a significant
rental fee and bond. No additional
changes are warranted in response to
this comment because this section
already covers the rental and bonding
requirements. A fee is also required in
§ 3105.41.
Section-by-Section Discussion for
Changes to 43 CFR Subpart 3106
The BLM proposed to add one
section, remove two sections, and
update the headings of each section to
remove the outdated question and
answer format that appears in the
existing regulations. The BLM received
a comment on this subpart stating the
BLM should, as a matter of
transparency, codify the policies and
procedures that the authorized officer is
required to follow with regard to
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approving and overseeing lease
transfers. The BLM did not make any
changes to this subpart based on this
comment. The BLM has a handbook, H–
3106–1, Transfers by Assignment,
Sublease, or Otherwise, that provides
the necessary guidance to the BLM to
adjudicate these transfers. The public
may obtain copies of this handbook,
which is not currently available online,
from any BLM state office.
Section 3106.10 Transfers, General
The BLM proposed splitting the
existing § 3106.1 paragraph (a) to
provide clarity, added a new paragraph
(b) clarifying that the BLM will deny a
transfer in certain situations, and added
a new paragraph (c) limiting the transfer
of operating rights. The BLM received a
comment recommending the BLM
address the impact of the severance of
operating rights from record title
interest. The BLM agrees with this
comment. The BLM receives a
multitude of transfers of operating rights
that are unnecessary because those
rights have never been severed from the
record title. The final rule includes a
new paragraph (b) to state that a record
title assignment conveys both record
title and operating rights unless
operating rights have been previously
severed. The remaining paragraphs are
redesignated accordingly.
The BLM received comments on the
proposed paragraph (b), which is final
paragraph (c). The BLM added this
paragraph to state an assignment of a
separate zone, deposit, depth,
formation, specific well, or of part of a
legal subdivision, will be denied. One
commenter supported this language,
while another commenter stated that
wellbore assignments are not
ambiguous, because wellbores have API
numbers that include bottom hole data
and that are within approved drilling
and spacing units specifying the acreage
being drained by the wellbore. Wellbore
rights are private agreements between
private parties and need not be reported
to the BLM. If the intent is to transfer
a specific legal surface area and/or
depth of the operating rights for a lease,
a legal description of that area and
depth is required.
A commenter stated that the language
in the proposed paragraph (c), which is
final paragraph (d), providing that
operating rights interests may only be
divided with respect to legal
subdivisions is ill-advised, as it
implicitly would preclude transfers of
operating rights as to parts of legal
subdivisions. The BLM disagrees with
this comment. The paragraph must be
read in conjunction with paragraph (a)
that specifically states, ‘‘Leases may be
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30941
transferred by assignment or sublease as
to all or part of the acreage in the lease
or as to either a divided or undivided
interest therein.’’ The final rule adopts
the proposed paragraph unchanged.
Section 3106.20 Qualifications of
Assignees and Transferees
The BLM proposed revisions to the
existing § 3106.2 to clarify that entities
to whom record title or operating rights
are being transferred must be qualified
to hold a lease. The BLM received one
comment on this section, requesting that
the BLM revise the section to clarify that
the new bonding requirements apply
only to operators and not all lessees,
assignees, and transferees. The BLM is
not making any changes to the section
in the final rule, because the bonding
requirements may apply to any entity to
whom an interest is being transferred
and not just an operator.
Forms
Section 3106.41 Transfers of Record
Title and of Operating Rights
(Subleases)
The BLM proposed revising the
existing § 3106.4–1 to require the use of
an approved form to accomplish these
transfers and to reduce the required
number of copies the transferee must
file with the BLM from three to two. The
BLM received a comment on this
section stating the BLM could not
change from triplicate to duplicate
filings as laid out in the proposed rule,
because the required number of
originally executed transfer forms is
fixed at three by statute.
The BLM proposed this change in
accordance with the Government
Paperwork Elimination Act (GPEA),
Public Law 105–227. Section 1707 of
the GPEA specifically states, ‘‘Electronic
records submitted or maintained in
accordance with procedures developed
under this title, or electronic signatures
or other forms of electronic
authentication used in accordance with
such procedures, must not be denied
legal effect, validity, or enforceability
because such records are in electronic
form.’’ After reviewing the comment
and 30 U.S.C. 187a, the BLM
determined that it should reinstate the
triplicate filing until the BLM
implements an electronic filing method.
At that time, the BLM would only
require one electronic filing per the
GPEA. Therefore, the BLM reinstated
the triplicate-filing requirement in this
final section; however, the final rule
also states the BLM will not require
triplicate copies of the assignment or
transfer when it is electronically
submitted.
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Section 3106.42 Transfers of Other
Interests, Including Royalty Interests
and Production Payments
The BLM proposed revising the
existing § 3106.4–2 to require transfers
of overriding royalty interest to be
submitted on the BLM’s approved form.
The BLM received a comment asserting
that the use of a BLM-approved form
should not be required, since the
transfer is not subject to BLM approval.
Although transfers of overriding
royalty interest do not require the BLM’s
approval, an overriding royalty interest
is an interest in a Federal oil and gas
lease. By requiring such transfers to be
on an approved BLM form, the
transferee is certifying that they are
qualified to hold the interest. The BLM
adopts this section in the final rule
without further changes.
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Section 3106.60
Bond Requirements
The BLM proposed changes to
existing § 3106.6 to clarify that an entity
to whom an interest in the lease is being
transferred has the requisite level of
bonding. The BLM received a comment
questioning why—if the previous lessee
is only transferring a portion of its
leases—the transferee must maintain the
same level of bonding in cases where
the previous entity had many more
leases and other reasons for an
increased bond amount. A commenter
stated, for example, that the proposed
rule provision would result in a new
lessee, record title owner, or operating
rights owner being required to maintain
a full statewide bond when the assignor
or transferor only transferred a portion
of its Federal wells.
The BLM does not intend to require
such results. Therefore, the final rule
removes the phrase ‘‘(including a
statewide bond)’’ as a statewide bond
may not be necessary. When a lessee or
operating rights owner maintains a bond
for a lease, the BLM expects the
transferee or assignee to maintain the
same level of bonding for operations on
the transferred lease(s). If previous
lessees or operating rights owners held
a statewide bond, the BLM will work
with the new owner to identify the
appropriate level of bonding for that
lease.
The BLM received a comment
recommending a revision to this
provision to include the following
language: ‘‘to the same extent as the
assignor’s or transferor’s bond, or to a
greater amount if deemed necessary
following a bond adequacy review.’’
This addition was recommended to
ensure the adequacy of bonds at the
time of lease transfer. The commenter
also requested that the BLM adopt
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additional requirements expressly
requiring bond adequacy review at the
time of transfer. The comment went on
to state that such a rule should require
the assignor or transferor to furnish the
BLM with information on the number,
type, and depth of all wells existing on
the lease to be transferred, and should
require the BLM to use this
information—and any other relevant
information—to assess whether the
existing bond amount is adequate to
ensure prompt and complete
reclamation of all existing wells and any
new wells that may be drilled by the
assignee or transferee.
The BLM received a comment stating
the BLM should harmonize this section
with § 3104.20, which places the
bonding obligation for a lease on the
operator. The BLM primarily requires
bonds from the operator instead of the
lease interest owners (record title or
operating rights owner). However, the
BLM will require a bond from the
lessees when the operator’s bond is
insufficient.
The BLM received a comment stating
the BLM should include a requirement
that the assignee’s or transferee’s bond
be in place prior to the approval of the
assignment or transfer. The BLM
concurs and already requires the bond
to be in place prior to approving the
assignment or transfer and therefore
sees no need for the change.
The BLM received a comment
recommending that the BLM examine
and certify the transferee’s or assignee’s
financial viability before approving the
transfer or assignment. This
recommendation is not adopted in the
final rulemaking as the BLM does not
currently have the staff or expertise to
perform this function.
Approval of Transfer or Assignment
Section 3106.72 Continuing Obligation
of an Assignor or Transferor
The BLM proposed revising the
existing § 3106.7–2 by removing the
question-and-answer format in the title
and clarifying the responsibilities of the
assignee or transferee. The BLM
received a comment recommending that
the BLM change the language in
paragraph (b) to delete the references to
‘‘operating rights’’ and make it clear that
in the case of the transfer of any interest
in a lease, the transferor must maintain
financial assurances subsequent to the
approval of the transfer and that all
transferors should be required to
maintain financial assurances for a
predetermined suitable period after a
transfer is approved.
The BLM is not making any changes
to the final rule based on this comment,
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as the proposed regulations already
address the concerns expressed by the
commenter. Under § 3104.80, when the
BLM terminates the ‘‘period of liability’’
on a bond, this action sets an exact date
after which no new liability may accrue
under that bond. In addition, the BLM
prefers to keep the phrases ‘‘assignment
or transfer,’’ so it is clear this section
applies to both.
The BLM received a comment on
paragraph (b) requesting clarification on
the obligations described. The BLM has
revised this paragraph in the final rule
to clarify the obligations of the assignor
or transferor once the BLM approves an
assignment or transfer. The last sentence
in paragraph (b) now states ‘‘It also
includes responsibility for plugging
wells drilled and removing facilities
installed or used before the effective
date of the assignment or transfer.’’ The
BLM has added this sentence to provide
a more comprehensive list of lease
obligations; however, this is not a
complete list. The assignor or transferor
will continue to be responsible for other
lease obligations, not limited to the
items enumerated in § 3106.72(b).
Section 3106.73 Lease Account Status
The BLM proposed changes to the
existing § 3106.7–3 to remove the
passive voice and to clarify that the
lease account must be in good standing
with all royalties paid and lease
obligations met. The BLM received a
comment recommending a change to
this provision by providing 60 days to
allow a transferor whose account is
delinquent to remedy the delinquency
before the BLM rejects a transfer.
This recommendation is not adopted
in the final rule. While some state
offices suffer from a backlog of transfers,
the BLM aims to adjudicate transfers
within 60 days as required by the MLA.
Adding the suggested language would
prolong the time it takes the BLM to
adjudicate an assignment or transfer.
The denial of a transfer for this reason
does not preclude the assignor or
transferor from filing a new transfer
with the appropriate filing fee after the
lease account has been brought into
good standing.
Section 3106.76 Obligations of
Assignee or Transferee
The BLM proposed changes to the
existing § 3106.7–6 to remove the
question-and-answer format in the title
and to update the language to be
consistent with other changes being
proposed. The BLM received a comment
stating the regulation should also
mandate the maintenance of financial
assurances by the assignor of record and
the transferor of operating rights for a
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suitable amount of time after the
transfer or assignment to ensure the
continued protection of the Federal
resource: (1) during the transition to a
new lessee or operator; and (2) in the
event of a latent issue that was not
reasonably identified at the time of the
transfer or assignment and for which the
transferee or assignee refuses to accept
responsibility.
No changes to the rule are necessary
because an assignor or transferor
remains liable for reclamation of wells
during the period of liability. The
period of liability is fixed under
§ 3104.80, when the BLM terminates the
‘‘period of liability’’ on a bond. After
this date, which is an exact date, no new
liability may accrue under the bond.
Even if the liability is not apparent at
the time the liability terminates, the
assignor or transferor would remain
liable.
Other Types of Transfers
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Section 3106.81 Heirs and Devisees
The BLM proposed to split the
existing § 3106.8–1 paragraph (a) into
two separate paragraphs for clarity and
included a reference to the new filing
fee in paragraph (b). The BLM received
a comment on the proposed § 3106.81
stating the proposed rule should be
revised to state that the deceased party’s
rights will be assigned or transferred to
the appropriate successors, which
implies an affirmative act—whereas
such a transfer in fact takes place by
operation of law, and so the term
‘‘assignment’’ is misused in this context.
The BLM agrees and has revised the
final paragraph (a) to update the phrase
‘‘their rights will be assigned’’ and
inserts instead ‘‘their rights would be
assigned.’’ The BLM also removed the
word ‘‘assignment’’ from paragraph (b)
and inserted ‘‘transfer’’ instead.
Section 3106.83 Corporate Mergers
and Dissolution of Corporations,
Partnerships, and Trusts
The BLM proposed to revise and
update the title of the existing § 3106.8–
3 and proposed splitting the existing
paragraph into three to improve clarity.
The BLM received a comment on
§ 3106.83 stating the requirement for a
filing fee is noted only as to corporate
mergers, whereas the fee schedule in the
proposed rules under § 3000.120 of this
title lists a fee that covers corporate
merger and corporate dissolution.
The BLM agrees with this comment
and in the final rule has updated the
phrase in paragraph (d) from ‘‘the
processing fee for corporate merger’’ to
‘‘the processing fee for corporate merger
or dissolution of corporation,
partnership, or trust.’’
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9. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3107
Section 3107.10
Extension by Drilling
The proposed rule revised the existing
§ 3107.1 for clarity by splitting the first
paragraph into two and adding a new
paragraph to address directional or
horizontal wells drilled off lease. One
commenter stated language should be
added to confirm that a lease is held by
production from a directional or
horizontal well.
The BLM has not made any changes
based on this comment, because this
application is already clear. As stated in
§ 3107.21, a ‘‘lease will be extended so
long as oil or gas is being produced in
paying quantities.’’ This language is
clear that production on and attributed
to any lease will be held by production
from a directional or horizontal well. In
addition, the BLM’s Handbook H–3107–
1, Continuation, Extension, or Renewal
of Leases, states that ‘‘for a lease to be
continued by production, it must
contain a well capable of producing oil
and/or gas in paying quantities.’’ The
public may obtain copies of this
handbook, which is not currently
available online, from any BLM state
office. This direction will include all
leases that the directional or horizontal
wells drilled into and producing from a
Federal lease.
Production
Section 3107.22
Production
Cessation of
The BLM proposed changes to the
existing § 3107.2–2 in response to IBLA
decisions holding that the section
conflicted with the MLA. In this final
rule, the section now states that a lease
in its extended term expires 60 days
after production ceases, and not after
the lessee receives notice from the BLM.
A comment expressed concern that this
change may cause confusion and
unintended consequences, as the
operator of the well may not be the same
as the record title owner and timely
notice of a cessation of production may
not be received to remedy the nonproduction and preserve the lease.
The BLM understands this concern;
however, as explained in the preamble
to the proposed rule, multiple IBLA
cases have held that the existing
regulation directly conflicts with section
17(i) of the MLA (30 U.S.C. 226(i)).
The BLM received a comment stating
the last sentence in this paragraph
should be amended to clarify this
section. The BLM agrees and has revised
the final rule by inserting the word
‘‘paying’’ prior to ‘‘production’’.
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Extension of Leases Within Agreements
The BLM received a comment stating
that the undesignated center heading
that appeared immediately above
proposed § 3107.31 is misleading and
could easily be interpreted to mean the
extension of agreement terms as
opposed to the extension of leases
within agreements.
The BLM agrees and the final rule
adopts this recommendation and
changes the heading from ‘‘Extension
for Terms of Agreements’’ to ‘‘Extension
of Leases Within Agreements.’’
Section 3107.31 Leases Committed to
an Agreement
The BLM proposed to update the title
of the existing § 3107.3–1, remove a
reference to a provision that is no longer
applicable, and add a new paragraph to
address IBLA decisions pertaining to
production in paying quantities. A
comment stated the rule should clarify
that unitized leases in an extended term
cannot be further extended unless it is
through production. The comment
requested that the BLM clarify that the
mere commitment of a lease to an
agreement would not extend the Federal
lease. No further changes are warranted
to the final rule, because paragraph (a)
already states ‘‘provided, that there is
production of oil or gas in paying
quantities under the agreement prior to
the expiration date of such lease.’’
Finally, the BLM deleted the second
‘‘for’’ to clarify that both conditions
must exist for the leases to continue to
receive the extension. For the leases to
receive this extension, (1) the leases
must be committed to the authorized
unit agreement and (2) the well must
continue to be capable of production in
leasing paying quantities (able to pay
out the operating costs of the well).
Other Extension Types
A comment stated that the
undesignated center heading that
appeared immediately above proposed
§ 3107.71 is meaningless and should be
changed. The final rule adopts this
recommendation and changes the title
from ‘‘Other Types’’ to ‘‘Other Extension
Types.’’
10. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3108
Termination by Operation of Law and
Reinstatement
Section 3108.21 Automatic
Termination
The BLM proposed changes to the
existing § 3108.2–1 to reflect policy
changes by ONRR and to address IBLA
decisions. The changes included adding
a new paragraph (c) clarifying when the
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automatic lease termination would
apply. Some comments supported the
addition of paragraph (c). Other
comments stated the preamble to the
proposed rule included a misleading
example referencing lease suspensions
that may require additional rentals
when they are lifted that could result in
conflict and confusion if left
uncorrected.
That criticism is misplaced for the
reasons discussed in the context of
§ 3103.42 in this preamble. To be clear,
such a notice will depend on the timing
of the lifting of the suspension in
relation to the lease anniversary date.
Consider the following hypothetical
example: A lease is issued effective 7/
1/90 with a five-year primary term, so
it will expire on 6/30/95. The lessee
paid the rental timely for the fourth
lease year which ended on 6/30/94. The
BLM granted a suspension of operations
and production effective 4/1/94. The
suspension was lifted effective 9/1/94.
The revised expiration date of the lease
is therefore 11/30/95, because the lease
is extended an additional five months to
account for the five months in which
the suspension was in place. The rental
paid for the 1993–94 lease year covers
the remaining three-month period of the
fourth lease year from 9/1/94 to 11/30/
94. The prorated rental is to be
requested from the lessee for the seven
months from 12/1/94 through 6/30/95
(to bring the regular rental due date back
to the lease anniversary date). No
changes were made to the final rule
based on this comment.
Section 3108.22 Reinstatement at
Existing Rental and Royalty Rates: Class
I Reinstatements
The BLM proposed changes to the
existing § 3108.2–2 to reflect the fact
that ONRR accepts rental payments
through its online system. The BLM
received a comment on paragraph (a)(2),
asserting the change in this
subparagraph would narrow the
definition of ‘‘reasonable diligence’’ to
include only rental payments made
through ONRR’s online system on or
before the lease anniversary date and
disregards ONRR’s continuing practice
of accepting non-electronic rental
payments in some circumstances that
would effectively eliminate reasonable
diligence as grounds for Class I
reinstatement. The BLM agrees and has
revised the final rule by removing the
phrase ‘‘through its online rental
payment system’’ from paragraph (a)(2).
The BLM received a comment on
paragraph (a)(3) stating that increasing
the filing fee for Class I reinstatements
from $90 to $1,260 is disproportionate
to the administrative fee for Class II
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reinstatements which would remain at
$500. As stated in the preamble to the
proposed rule, the BLM considered
moving the existing fee for Class II
reinstatements to § 3000.120 for
inclusion alongside the other fixed
filing fees, increasing the fee to reflect
the processing costs, and then adjusting
the fee annually for inflation. However,
the MLA, at 30 U.S.C. 188(e),
specifically states for Class II lease
reinstatements that ‘‘[t]he lessee of a
reinstated lease shall reimburse the
Secretary for the administrative costs of
reinstating the lease, but not to exceed
$500.’’ Accordingly, the BLM does not
have the authority to increase this fee.
The BLM also considered reducing the
Class I reinstatement fee to $500 for
parity with the Class II reinstatement fee
and concluded that doing so would be
insufficient to cover the BLM’s
administrative costs.
Section 3108.30
Cancellation
The BLM proposed revising the
existing § 3108.3 to remove language in
paragraph (a) that repeatedly called for
the BLM to provide notice to the lessee
prior to cancellation. The BLM received
a comment stating that a provision
should be added stating leases are
subject to cancellation if the lessee is
found not to be a ‘‘qualified lessee’’ or
a ‘‘responsible lessee.’’ No changes have
been made to the final rule as the BLM
does not have the authority under the
MLA to cancel a lease for these reasons.
30 U.S.C. 188. Further, the existing
requirements at § 3102 would be
applied prior to the issuance of a lease,
and these requirements address this
concern.
11. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3109
Section 3109.15 Compensatory
Royalty Agreement or Lease
The BLM revised the existing
§ 3109.1–5 to align the terms of a lease
issued under a ROW to those for a
competitive lease. A commenter caught
a technical error in subparagraph (c)(1)
of the provisions of 43 CFR part 3100,
where the BLM referenced a regulatory
section number that does not exist
(§ 3101.20). The BLM proposed and is
removing the regulatory section
numbers for headings that have no text
associated with them, which included
§ 3101.2 in the previous regulations, and
changed these sections to undesignated
center headings. Therefore, the final
rule makes a minor technical change to
correct this error. The statement of
‘‘except § 3101.20’’ in paragraph (c)(1)
has changed to ‘‘except §§ 3101.21,
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3101.22, 3101.23, 3101.24, and
3101.25.’’
Sections 3109.21–3109.22 [Reserved]
In the final rule, the BLM removes the
existing reserved §§ 3109.2–1 and
3109.2–2 as these sections do not need
to be reserved. In the previous
regulations, the BLM reserved § 3109.2–
1 for the ‘‘Authority to lease’’ and
§ 3109.2–2 for the ‘‘Area subject to
lease.’’ The BLM incorporated the
authority to lease in 43 CFR 3100.3 and
provides the area to lease in § 3109.20;
therefore, the BLM no longer needs to
reserve these sections in the final rule.
12. Section-by-Section Discussion for
Changes to 43 CFR Part 3110
The final rule removes the existing 43
CFR part 3110 in its entirety. Multiple
commenters expressed support for the
elimination of 43 CFR 3110 to comply
with Congress’ repeal in the IRA of
noncompetitive leasing for Federal
onshore oil and gas minerals.
13. Section-by-Section Discussion for
Changes to 43 CFR Part 3120
The BLM proposed to add two new
sections and remove four sections from
part 3120 to provide clarity and to
ensure these provisions are consistent
with other changes being made. The
BLM received several comments on part
3120. Some comments specifically
requested that the BLM not issue new
leases in certain areas of the country.
Some comments recommended
additional paragraphs such as including
denial criteria based on consideration of
localized conditions and lands already
subject to various types of adverse
impacts. These comments are directed
at the land use planning process, which
is when the BLM evaluates whether
lands should be open or not to leasing.
Because these regulations govern the
leasing and development process, these
comments are outside the scope of this
rulemaking.
Section 3120.11 Lands Available for
Competitive Bidding
The BLM proposed changes to the
existing § 3120.1–1 to reflect Congress’
repeal of noncompetitive leasing in the
IRA and revised the language in the
introductory paragraph such that it
more closely aligns with the Act.
Some comments argued that the
proposed changes give the BLM more
discretion for leasing than granted by
the MLA; however, these arguments
were made in reference to the timing of
holding quarterly lease sales and not
with respect to the BLM’s discretion
regarding what lands may be offered for
lease. The introductory paragraph in
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this section states, ‘‘All lands eligible
and available for leasing may be offered
for competitive auction.’’ The BLM
changed the ‘‘shall’’ to ‘‘may’’ to clarify
that the Secretary retains the discretion
to decide, even after lands have been
determined to be eligible and available,
what lands will ultimately be offered for
lease. Timing of any lease sales is
addressed in final § 3120.12(a) which
was modified to state, ‘‘Each BLM state
office will hold sales at least quarterly
if eligible lands are available for
competitive leasing.’’
One commenter objected to the
addition of the term ‘‘eligible’’ to this
section. The BLM has not made any
changes based on this comment as the
proposed language merely reflects the
language in the MLA at 30 U.S.C 226(a)
and (b).
Another comment recommended that
the BLM consider issuing a protective
lease covering open Federal acreage
located in an existing drilling block to
provide a mechanism for a unit operator
to develop its drilling block, including
the unleased Federal minerals. The BLM
cannot issue a protective lease, as
proposed in the comment, under the
MLA. The BLM may only issue a
protective lease through a competitive
lease sale based upon the law at 30
U.S.C. 226 and due to drainage of the
Federal minerals (see 43 U.S.C. 1457;
see also Attorney General’s Opinion of
April 2, 1941 (Vol. 40 Op. Atty. Gen.
41)). The BLM did not make any
changes to the final rule based on this
comment.
One commenter recommended
removing ‘‘including but not limited to’’
from the introductory paragraph and
inserting a new subparagraph (a) to state
‘‘lands that have been identified as
preferred leasing areas in a current land
use plan as well as lands identified as
exclusion areas in a current land use
plan shall not be available for leasing.’’
The BLM did not make any changes to
this section of the final rule. The BLM
already identifies the lands closed to
leasing or open to leasing in its land use
plans. In addition, the BLM does not
identify ‘‘preferred leasing areas’’ within
its land use plans. Since the BLM did
identify that the lands must be available
for leasing at the beginning of the
statement, the BLM declines to make the
changes proposed by the comment.
Section 3120.12 Requirements
The BLM proposed changes to the
existing § 3120.1–2 to reflect current
practices in holding lease sales via the
internet, a new paragraph (c) to
strengthen and revise the bidding
process, the redesignation of paragraph
(c) to (d), and inclusion of the new
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minimum bid amount. One comment
recommended that the BLM add
language clarifying that the BLM’s
discretion also applies to the timing of
lease sales, and, specifically, that a sale
need not be held if there are no eligible
or available lands. The BLM has not
made any changes to the final rule based
on this comment, because paragraph (a)
already states ‘‘Each BLM state office
will hold sales at least quarterly if
eligible lands are available for
competitive leasing.’’
The BLM received a comment stating
that paragraph (d) should state the
minimum bid amount instead of
referring to the BLM’s website and
changes to the bid amount should be
made through the regulatory process.
The final rule does not adopt this
recommendation, as the minimum is
stated in regulation: the BLM has moved
the minimum bid amount required to
the Fiscal Terms Table at § 3103.1, and
all of the fiscal terms will be adjusted
every 4 years through the regulatory
process. Please note that the BLM will
not adjust the minimum bonus bid until
the amount set by the IRA becomes a
minimum after August 16, 2032.
Section 3120.30
Nomination Process
The BLM requested comments on
whether the formal nomination process
should be retained in regulations and, if
so, what changes to the formal
nomination process should be made.
The BLM received comments
supporting the retention of the
nomination process to promote leasing
in areas with greater potential for fluid
minerals to be produced. The BLM
received comments stating the BLM
should implement a single nominations
process that combines elements of
formal nominations and expressions of
interest. These commenters contended
that, by exercising its authority at the
front end regarding what public lands it
will consider for leasing, the BLM
would reduce land speculation, save
time and resources, and create greater
certainty for all parties. The BLM
received comments supporting the
elimination of § 3120.30 stating this
section is unclear, confusing, would
only be used to limit lease areas, and
that the BLM does not have the level of
technical expertise required to
adequately analyze lands for expected
yields of oil and gas.
The final rule removes the formal
nomination, existing §§ 3120.3 through
3120.3–7 and proposed §§ 3120.30
through 3120.33, which the BLM has
never used and which generally
increases the time and resources
necessary to hold lease sales.
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Expression of Interest
The BLM proposed adding a new
section to address the process for EOIs,
which previously had not been codified
in regulation. The proposed rule also
included the new filing fee requirement
for EOIs in paragraph (d) as required by
Congress in the IRA (see also the Fiscal
Terms Table in final § 3103.1). The final
rule redesignates the citation numbers
throughout this section consistent with
the removal of sections that pertained to
the nomination process. The BLM
received several comments on this
section. Based on the BLM’s review of
the comments, the final rule splits the
proposed § 3120.41 into two new
sections. The first section describes the
requirements for an EOI (proposed
paragraphs (a) through (e), and (g)) and
a new section is created for the
preference criteria (proposed paragraph
(f)).
Section 3120.31
Process
Expression of Interest
The final rule renames the proposed
section from ‘‘Process’’ to ‘‘Expression
of interest process’’ and redesignates
§ 3120.31 from proposed § 3120.41 to
final § 3120.31 as doing so will provide
consistency with the previous
regulations. This section contains
paragraphs (a) through (d) of the
proposed § 3120.41. Proposed paragraph
(g) has been redesignated as paragraph
(e).
One comment objected to the
requirement that, for split estate lands
under paragraph (b)(6), an EOI submitter
must submit the private surface owner’s
name and address, even though there is
no explicit and corresponding statutory
requirement, and even though the
information is often difficult and time
consuming for submitters to obtain. The
BLM has not made any changes to the
regulation based on this comment.
Under section 1835 of the Energy Policy
Act of 2005 (43 U.S.C. 15801), Congress
directed the Secretary of the Interior to
review current policies and practices
with respect to management of Federal
subsurface oil and gas development
activities and their effects on the
privately owned surface. The Split
Estate Report to Congress, submitted in
December 2006, documents the findings
resulting from consultation on the split
estate issue with affected private surface
owners, the oil and gas industry, and
other interested parties. In the Report,
the BLM identified in Issue 4 that
‘‘surface owners would like to be
contacted when the BLM is leasing
Federal mineral estate underlying their
property. Notification is requested when
parcels are nominated and offered on a
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competitive lease sale.’’ As a result of
work done to implement portions of the
Energy Policy Act of 2005 relating to
split estate lands, the BLM asked
individuals submitting EOIs to provide
the name of the private surface owner.
This is outlined in BLM Handbook H–
3120–1, Competitive Leases.22 This
information allows the BLM to notify
the surface owner when the BLM
initiates a lease sale that contains a
parcel with minerals underlying the
owner’s surface. The BLM will require
this information under paragraph (b)(6)
to ensure the BLM provides adequate
outreach to the private surface owners
overlying Federal minerals.
The BLM received a number of
comments on paragraph (d), which
requires payment of the per acre fee
required by Congress in the IRA. Some
commenters recommended that the
BLM should require the fee to be
payable by the winning bidder instead
of the individual that submitted the EOI
or that the fee should be refunded if: (1)
the lands are not included in a sale; (2)
the individual that submitted the EOI
does not obtain the parcel at the lease
sale; or (3) the individual submitted an
EOI covering lands already submitted
on a prior EOI submittal. The BLM
cannot make any of these changes as
Congress did not provide the Secretary
with this discretion in the IRA. That Act
requires the assessment of a
nonrefundable fee payable by any
person submitting an EOI.
In proposed paragraph (e), the BLM
included language allowing the BLM to
include lands in a sale on its own
initiative. The BLM received comments
objecting to the provision, asserting it
would allow the BLM to include lands
it knows to be unattractive and does not
account for the BLM’s policy on
unleased lands within CAs. That policy
directs the BLM to offer such lands for
competitive leasing as soon as possible,
such that the lands should not be
subject to nomination limitations or EOI
criteria set forth in the proposed rule.
After reviewing these comments, the
BLM is removing proposed paragraph
(e) from the final rule. That paragraph
is unnecessary because § 3120.11(f)
already gives the BLM the option to
include lands selected by the authorized
officer in a sale. The removal of
paragraph (e) from this section clarifies
that Bureau motions are not considered
or counted as EOIs for purposes of
calculating the percent of EOI acreage
offered on oil and gas lease sales during
the past year for renewable development
under 43 U.S.C. 3006.
22 https://www.blm.gov/sites/blm.gov/files/
uploads/Media_Library_BLM_Policy_h3120.pdf.
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As a final note, the BLM is clarifying
that it only self-nominates lands to
protect the Federal minerals and the
public interest. The BLM calls selfnominated lands a Bureau motion. The
BLM creates a Bureau motion to protect
the Federal mineral estate from drainage
or when there are unleased Federal
minerals within an approved oil and gas
agreement. The BLM tracks information
on which parcels originate from an EOI
or a Bureau motion within the BLM’s
National Fluid Lease Sale System. As of
December 14, 2023, approximately 92
percent of the lands under review came
from an EOI. The BLM identified that
from the nominations received in
calendar year 2023, the BLM has a total
of 83,917.23 acres of pending lands
under review with only 6,815.36 acres
created from Bureau motions. The
remaining 77,101.87 acres under review
for future oil and gas leasing are created
from EOIs.
The proposed paragraph (g) has been
redesignated to paragraph (e) in the final
rule and reflects the BLM’s longstanding authority to determine which
lands will ultimately be offered for sale.
Therefore, the BLM makes no changes to
this paragraph.
Section 3120.32 Expression of Interest
Leasing Preference
The BLM revised the final rule by
creating new § 3120.32, which had
appeared in proposed § 3120.41(f). Both
the proposed and final sections address
the preference criteria that the BLM may
use when determining whether, when,
and in what order certain lands
specified in an EOI should be processed
and offered in a lease sale. Creating the
new section required certain
redesignations and reorganizations.
The BLM received many comments
on this proposed section. Most of the
comments were generally supportive of
the preference criteria, though some
commenters were opposed to the use of
the criteria. Some comments that
expressed support for the preference
criteria requested additional criteria be
considered or requested an expansion of
the proposed criteria to include greater
specificity. As discussed in Section
III.B.2 and III.B.7 of this preamble, these
comments recommended revising the
criteria to better account for impacts on
GHG emissions and climate change,
environmental justice, the environment
(often suggesting criteria for specific
habitat, natural resource areas, land or
aquatic conditions, species, or other
factors), cultural and Tribal resources,
specific recreational uses, and protected
areas such as special conservation areas,
parks, and wilderness areas.
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Other comments opposed the
consideration of any criteria by: (1)
stating that adding preference criteria to
preliminary leasing decisions will lead
to delays, create uncertainty, and detract
from the predictability of the process;
(2) expressing concern that the
application of the preference criteria
would exclude lands that would be
considered exploratory and that such
exploratory actions benefit the public at
large; and (3) stating that the proposed
criteria process was duplicative of other
statutory processes, such as those under
the Endangered Species Act and
FLPMA.
Many commenters also expressed
views on the proposed process for
considering criteria before offering
parcels. Some comments stated the
application of the criteria is not a
transparent process or could be
subjective. Some commenters expressed
concern that the BLM lacks the
technical expertise and resources
needed to apply some of the preference
criteria and sought clarifying language
to ensure consistent consideration of the
criteria by BLM offices, including
identifying the sources of information
that offices are expected to use.
Specifically, for example, some
comments stated that the proposed rule
does not explain how the criteria will be
used when conflicts between
development and other uses occur or
how the preferences will be weighted.
Commenters offered varied approaches
for how the criteria should be applied.
For example, some comments stated
that lands with a low preference should
be excluded from leasing, and other
commenters suggested that an EOI
should represent compelling evidence
of some potential for development.
Additionally, some comments stated the
preference criteria should not be
applied to lands administered by
another Federal agency.
After careful consideration of the
comments received, the BLM is
clarifying in the regulatory text that the
BLM will consider the preference
criteria as part of the scoping process for
leasing. During the leasing process, the
BLM will apply the criteria after the
conclusion of the scoping process but
before issuing a draft NEPA document
for a lease sale. As such, the BLM has
revised the last sentence in the
introductory paragraph. The BLM is
inserting the phrase ‘‘In evaluating the
lands to be offered, as part of the
scoping process.’’
Applying the preference criteria after
scoping but before publication of the
NEPA document allows the BLM to
consider public comment on the
environmental analysis for the lease sale
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at the outset of the leasing process and
to better manage its workload by
directing its resources towards tracts
that are most likely to be developed.
Since BLM New Mexico’s May 25, 2023,
oil and gas lease sale, the BLM has been
applying the preference criteria in this
way through the BLM’s policy IM 2023–
007, Evaluating Competitive Oil and
Gas Lease Sale Parcels for Future Lease
Sales.23 This process enables the BLM
to conduct preference criteria review
while the public and industry provides
scoping comments, which the BLM will
incorporate into its determination in the
NEPA compliance documentation.
This procedural clarification also
addresses many of the comments
received. First, considering the criteria
at the conclusion of the scoping process
will allow the public to provide input
that the BLM should consider when
applying the criteria to the preliminary
list of lands for a lease sale. Consistent
with § 3120.42, the BLM will provide at
least 30 calendar days for public
comment on the preliminary parcel list
as part of the scoping process. During
this public scoping period, commenters
can raise site-specific considerations
that should be considered in selecting
parcels. These could include many of
the concerns commenters raised as
potential additional criteria, such as the
potential for development,
environmental justice considerations,
and other important uses or resources
like watershed vitality. Public input also
will help ensure that the BLM has the
necessary data and information to
evaluate the criteria. In response to
public input, the BLM will be able to
consider new information raised and
announce its initial conclusions on the
preference criteria in the draft NEPA
document. Second, these steps provide
transparency for the public to see how
the BLM is considering the criteria on
a case-by-case basis. For example, in
some scenarios, it may allow the public
to understand why low preference
parcels are being offered for leasing or
to recognize when there is a conflict
between resources. This increased
transparency and ability for public
input are responsive to the comments
received, including those that urged the
BLM to add additional criteria that
should be considered for the localized
area and those that expressed concern
that the process lacked clarity or
transparency. At the same time, the
BLM will more efficiently manage the
process by applying the criteria before
publishing the draft NEPA document. If
the BLM applied the criteria to the
parcels after publishing the draft NEPA
23 https://www.blm.gov/policy/im-2023-007.
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document, the BLM may need to rework or apply amendments and changes
to both the draft NEPA documents and
the competitive lease sale notice.
The BLM moved the statement ‘‘at
minimum’’ to the end of the final
sentence in § 3120.32. Consistent with
the original wording in the proposed
rule that directed the BLM to consider
‘‘at a minimum’’ the listed criteria, this
language allows the BLM’s authorized
officer to consider other unenumerated
criteria specific to local circumstances,
including those raised in public
comments. As such, the BLM declines
to add, modify, or remove the
preference criteria that were proposed.
On a case-by-case basis, stakeholders
and the public will be able to provide
the BLM with pertinent information on
the criteria or additional criteria to
consider.
In addition, the BLM will not
promulgate a specific weighting for the
different criteria within § 3120.32 as the
weighting will depend on the specific
location and conditions in relation to
local circumstances. Instead, the BLM
will use the scoping process to inform
the weighting for the different criteria.
This will allow the BLM to incorporate
public feedback on the parcels to be
offered on the sale and ensure the BLM
appropriately weighs the critical uses or
resources. This will also allow the BLM
to move forward with parcels that could
be considered exploratory. The operator
for the area can inform the BLM during
the scoping period that it is interested
in exploring for oil and gas in this area,
which would provide for the BLM to
weight the potential development
criteria lower. The BLM disagrees that
consideration of the preference criteria
increases uncertainty or will lead to
delays; rather, considering the criteria at
the beginning of the leasing process will
allow the BLM to more efficaciously
select parcels for which to conduct
environmental analysis and to offer at
the lease sale. Ultimately, this will
increase certainty and efficiency in the
leasing process by decreasing the
number of parcels offered that would
not be leased, and relatedly, the number
of parcels that are leased but never
developed. By considering parcels that
make the most sense to lease in terms
of expected yields of oil and gas, the
BLM is addressing concerns expressed
in GAO’s report, GAO 21–138, Onshore
Competitive and Noncompetitive Lease
Revenues.24 The improved management
of agency workflow will better use the
BLM’s time and resources and will not
result in delay.
24 https://www.gao.gov/products/gao-21-138.
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Additionally, rather than duplicating
provisions under other statutes, the
preference criteria will provide the BLM
with an additional tool, consistent with
the Secretary’s broad discretion to lease
lands for oil and gas development, to
direct leasing and better avoid or
manage conflicting uses of public lands
at the outset of the leasing process.
Because scoping is part of the NEPA
process, application of the criteria will
not be duplicative of the NEPA process.
The MLA vests the Secretary with
broad discretion to decide, up until the
time of lease issuance, whether
particular parcels of Federal land ‘‘may
be leased’’ for oil and gas development,
see 30 U.S.C. 226(a). The MLA does not
specify how and when this decision is
to be made, and courts have consistently
recognized the Secretary’s discretion.
E.g., Udall v. Tallman, 380 U.S. 1, 4
(1965) (‘‘The [MLA] gave the Secretary
of the Interior broad power to issue oil
and gas leases on public lands’’) United
States ex rel. McLennan v. Wilbur, 283
U.S. 414, 419 (1931) (‘‘there is ground
for a plausible, if not conclusive,
argument that so far as it relates to the
leasing of oil lands [the MLA] goes no
further than to empower the Secretary to
execute leases which, exercising a
reasonable discretion, he may think
would promote the public welfare’’).
The preference criteria fit squarely
within this discretion by aiding the
BLM in directing leasing towards areas
that are more likely to produce oil and
gas and that are less likely to have
conflicts with other uses.
Additionally, some comments sought
clarification regarding the BLM’s policy
in IM 2023–007, Evaluating Competitive
Oil and Gas Lease Sale Parcels for
Future Lease Sales.25 The BLM will
continue to use this policy to guide the
BLM’s consideration of the preference
criteria to evaluate parcels for
competitive lease sales. The BLM’s
application of the IM as part of scoping
has worked well for the 13 sales held in
calendar year 2023, which resulted in
over $158 million of total receipts.
During the BLM’s review of the final
rule, the BLM identified an error in the
proposed rule for § 3120.32(c). The
language in the proposed rule described
the evaluation of ‘‘the presence of
historic properties, sacred sites, and
other high value leasing lands, giving
preference to lands that would not
impair the cultural significance of such
resources.’’ In its guidance, however,
the BLM described the evaluation of
‘‘the presence of historic properties,
sacred sites, or other high value cultural
resources, giving preference to lands
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that do not contribute to the cultural
significance of such resources.’’ To
avoid any implication that ‘‘high value
leasing lands’’ were akin to historic
properties, rather than an independent
consideration, ‘‘other high value leasing
lands,’’ the BLM has changed
§ 3120.32(c) to read ‘‘other high value
cultural resources.’’
Finally, the BLM concurs that the
other surface management agencies will
have extensive knowledge on the
relevant parcels and the BLM should
give deference to those agencies.
Therefore, the BLM is not changing the
language in the regulation; however, the
BLM’s policy going forward will be for
the BLM to provide its proposed
application of the preference criteria to
the surface management agency when
requesting consent. The surface
management agency can use the
information provided by the BLM to
determine if it will grant consent. For a
parcel with the surface management
agency’s consent, the BLM may move
forward to offer the parcels on a lease
sale, irrespective of the preference the
BLM would otherwise afford the
parcels. As noted above, the Secretary
retains full authority under the Mineral
Leasing Act to determine which parcels
are offered for sale.
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Section 3120.33
Leasing
Agency Inventory of
The BLM proposed this new § 3120.33
(redesignated from § 3120.42 in the
proposed rule) to address the IRA’s
requirement (section 50265 26) that the
Department offer leases for a certain
amount of land for oil and gas
development as a prerequisite to
permitting any new solar or wind
energy projects. Some of the comments
supported the inclusion of this section,
stating it is essential that the BLM take
this leasing inventory to determine
compliance with the IRA.
Some comments noted the new
provision provides no calculation
method and requested that the BLM
consider codifying some of the
calculation process set forth in IM
2023–006, Implementation of section
50265 in the Inflation Reduction Act for
Expressions of Interest for Oil and Gas
Lease Sales.27 Others requested that the
BLM should not rely upon IM 2023–006
for the calculation method. The BLM
has not made any changes to this
provision in the final rule and will
continue to rely on the policy as set
26 https://www.congress.gov/bill/117th-congress/
house-bill/5376/text.
27 https://www.blm.gov/policy/im-2023-006.
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forth in IM 2023–006 to calculate the
acreage.
Some comments suggested the rule be
revised to require calculations to be
performed on a quarterly basis, rather
than leaving it unclear in the rule when
to run such calculations. These
comments asserted quarterly
calculations would allow the BLM to
determine the amount of public land
acreage needed to be offered to allow
wind and solar ROW permit issuance on
an ongoing basis. Further, the comments
suggested the BLM should only allow
parcels receiving a low preference to be
leased to allow wind or solar ROW
issuance if additional acreage was
needed based on the quarterly
calculations. These calculations are only
required on the day that the BLM would
issue a wind or solar energy right-ofway; therefore, the BLM has not made
any changes to the final rule based on
this comment. The BLM will look at
providing a mechanism for both the
BLM and the public to generate reports
and such calculations on demand.
Multiple comments stated the BLM
should clarify in the final regulation
that ‘‘the 1-year period refers to the year
before the wind or solar energy right-ofway is issued.’’ The final rule adopts
this recommendation and clarified that
the 1-year period refers to the year
before the BLM issues the wind or solar
energy right-of-way in the final rule.
One comment stated the BLM should
require that, before offering any parcel
that receives a low preference
designation for lease, the agency
demonstrate that doing so is necessary
to allow issuance of wind or solar ROW
permits to comply with the IRA’s
provisions. The BLM declines to make
any changes to the final rule based on
this comment as it would needlessly
restrict the BLM’s discretion to
determine which parcels to offer.
Notice of Competitive Lease Sale
The BLM did not receive comments
on its proposal to redesignate the
following two sections based on the
other changes made in the proposed
rule.
Section 3120.42 Posting Timeframes
The BLM proposed changes to the
existing § 3120.4–2 to clarify its process
for identifying parcels for a sale, the
public’s comment opportunities, and
the timing of the BLM’s posting of a
notice prior to a sale.
Some comments recommended that
the rule should: (1) require NEPA
compliance documents to be made
publicly available at the time the Notice
of Competitive Lease Sale is posted; (2)
specify that comment periods close at
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11:59:59 p.m. (local time) on the last
day of the comment period; (3) require
key documents and information be
translated into those languages that are
the primary languages of communities
impacted by the particular lease sale; (4)
revise the rule to provide schedules for
making data and information available
to the public; and (5) require parcels to
be in a format that both geographic
information system (GIS) users and nonGIS users can easily understand. The
BLM does not adopt these
recommendations as these are
provisions best addressed in a handbook
as BLM policy guidance. The BLM will
continue to allow the BLM state offices
to manage the lease sales in a manner
that works best for each office. The BLM
already implements some of these
recommendations and is committed to
posting and making the NEPA
compliance documents publicly
available online. In addition, the BLM is
continuing to develop the MLRS such
that it will be capable of providing
information spatially. Mapped views of
the parcels are also displayed from the
BLM’s internet auction provider.
One commenter stated the key
component of environmental justice is
meaningful involvement of those most
affected by a proposed project, agency
action, or decision, while other
commenters expressed the opinion that
these changes are unwarranted and only
serve to invite additional rounds of
protests further delaying the leasing
process. One commenter stated the BLM
should issue the final NEPA documents
prior to the lease sale to allow protests
to be lodged before leases are sold. The
BLM has not made any changes based
on these comments. The BLM believes
its codification of the opportunities for
public comment on parcels to be
included in a lease will allow for the
meaningful involvement of those
potentially most affected. Rather than
providing for an additional round of
protests, the changes to the regulation
merely codify the BLM’s current policy.
The final rule makes a minor
technical change to include ‘‘or
appeals’’ at the end of paragraph (a),
which is consistent with the text of
paragraph (b), and replaces the acronym
‘‘NEPA’’ with ‘‘National Environmental
Policy Act’’ to assist readability of the
final rule.
Competitive Auction
The final rule redesignated the
following section numbers consistent
with the removal of the nomination
process from the final rule.
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Section 3120.51
Competitive Auction
The BLM proposed changes to the
existing § 3120.5–1 paragraph (a) to
remove references to formal
nominations, and to delete paragraph (c)
for the same reason. The first sentence
in paragraph (a) has been rewritten from
‘‘Parcels shall be offered by oral or
internet-based bidding’’ to ‘‘Parcels will
be offered by competitive auction’’ in
the final rule. One commenter
recommended that the BLM change its
online auction format to allow parcels to
remain open until bidding ceases, as
under the current system the parcel is
awarded to the highest bidder at the
time the parcel times out.
The final rule does not adopt this
recommendation. In the online bidding
process, bidders are given ample time to
review the parcels before a sale period
opens for bidding. The bidding time is
published, which will vary from sale to
sale depending on the number of parcels
offered, however the bid open and close
time is clearly stated throughout the sale
notice and in the auction. In the BLM’s
experience, most of the bidding occurs
in the last few minutes of a parcel
closing regardless of how long the
bidding window is open. The BLM has
found no data to support the assertion
that the BLM will receive higher bids if
the auction is allowed to run longer.
Those bidding have a maximum amount
they are willing to spend for a parcel
and the amount of time allowed for
bidding whether online or in person
does not affect this.
ddrumheller on DSK120RN23PROD with RULES4
Section 3120.52
Payments Required
The BLM proposed changes to the
existing § 3120.5–2 to reflect changes
enacted by Congress in the IRA and to
be consistent with other changes made.
The BLM received a comment
recommending a change to paragraph
(b) to clarify that the authorized officer
can select a date other than the day of
the sale for the payment.
The final rule adopts this
recommendation and moves the phrase
‘‘on the day of the sale for the parcel’’
to earlier in the sentence to provide
clarity. The final paragraph (b) now
reads, ‘‘Each winning bidder must
submit, by the close of official business
hours on the day of the sale for the
parcel, or such other time as may be
specified by the authorized officer.’’
Some comments expressed the belief
that the minimum bid was still too low
or should be at least $20 per acre. The
final rule does not adopt this
recommendation. As previously
explained, the minimum bid was
changed to reflect the IRA, which
requires $10 per acre.
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The final rule makes a technical
change to the cross reference for the
minimum bonus bid in paragraph (b)(1)
consistent with other changes in this
rulemaking.
Section 3120.53 Award of Lease
The BLM proposed changes to the
existing § 3120.5–3 to remove references
to the noncompetitive lease process.
The BLM received a comment
recommending the BLM revise
paragraph (b) to state that a ‘‘lease will
be awarded to the highest responsible
and qualified bidder unless contrary to
the public interest.’’ The final rule does
not adopt this recommendation. The
BLM has historically used a public
interest requirement in its oil and gas
agreements, which require a drilling of
a well into the target formation for a CA
or drilling of the obligation well for an
exploratory unit agreement. Adding a
public interest requirement to this
section may cause confusion related to
the use of this same phrase with
agreements. The Secretary still has the
discretion to consider the public interest
in the ultimate decision of which lands
to lease.
A commenter stated that paragraph
(d) should be revised to state that the
lease will not be issued until all appeals
are resolved in addition to the
resolution of all protests. The final rule
does not adopt this recommendation,
because the MLA requires all leases to
be issued within 60 days following the
payment of any remaining bonus bid
and rentals for the first year.
Comments opposing the inclusion of
paragraph (e) stated that the BLM
should not reject a lease offer without
the bidder’s consent if the protest is not
timely resolved. In this section of the
regulations, the BLM may reject a bid if
the BLM cannot issue the lease within
60 days as required under 30 U.S.C.
226(b)(1)(A). However, the BLM concurs
that it should not reject the bid without
the successful bidder confirming that it
would prefer its bid to be rejected rather
than waiting longer than 60-days for the
lease to be issued. Based on this
comment, the BLM has revised this
section in the final rule by inserting the
phrase ‘‘with the consent of the bidder’’
to clarify the BLM’s intent.
14. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3137
The final rule does not make any
revisions to the section designations or
the headings that appeared in the
proposed 43 CFR subpart 3137
regulations. The BLM did not receive
any comments on these sections and
adopts the proposed changes in the final
rule.
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30949
15. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3138
The final rule does not make any
revisions to the section designations or
the headings from the proposed rule for
the 43 CFR subpart 3138 regulations.
The BLM did not receive any comments
on these sections and adopts the
proposed changes in the final rule.
16. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3140
The final rule does not make any
revisions to the section headings in the
existing 43 CFR subpart 3140
regulations. It does redesignate the
sections to make them conform to
current Office of the Federal Register
(OFR) Document Drafting Handbook
requirements.
Section 3140.13 Exploration Plans
The BLM identified that paragraph (c)
contained a technical error and
referenced an outdated section number
of the regulations. The final rule
corrects the reference to § 3140.23. The
BLM did not receive any comments on
§ 3140.13 and did not make any other
changes to the final rule.
Section 3140.14 Other Provisions
The BLM proposed changes to the
existing § 3140.1–4 to update the rental
and royalty provisions. The BLM
identified that existing paragraph (a)
contained a technical error and
referenced an outdated section of the
regulations. The final rule corrects the
references to 43 CFR 3101.21 and
3101.22. One comment suggested that
the current rule set out the actual
required rental amounts to ensure the
regulations serve as an orderly source
for basic information. The BLM revised
paragraph (b) to provide this reference.
The BLM received a comment on
paragraph (d) referencing the unitization
provisions in 43 CFR part 3180. The
commenter recommended that the BLM
revise the final rule to provide that a
lease, or part of a leasehold, having been
made part of a unitized area will not be
sufficient to extend the primary term of
the entire leasehold and if the lessee
fails to take actions to extend those
portions of the lease outside of the
unitized portion of the leased lands, the
lease should expire as to those excluded
lands. The BLM reviewed this comment
and determined the suggested revision
is unnecessary as it is already addressed
inf 43 CFR 3107.32.
17. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3141
The final rule does not make any
revisions to section headings in the
existing 43 CFR subpart 3141
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regulations. It does redesignate the
sections to make them conform to
current OFR Document Drafting
Handbook requirements.
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Section 3141.8 Other Applicable
Regulations
The BLM did not receive any
comments on the existing § 3141.0–8.
However, when the BLM reviewed the
regulations during drafting of the final
rule, it identified that it needed to
update § 3141.8(a)(1)(ii) to reflect the
provisions in § 3140.14(a). Under 30
U.S.C. 226(b)(2)(A)(iv), ‘‘no lease issued
under this paragraph shall be included
in any chargeability limitation
associated with oil and gas leases.’’
Therefore, the BLM updated this
paragraph after reviewing the law and
the applicable Federal Register notices
that established these two sections of
the regulations. See 48 FR 7420
(February 18, 1983), 47 FR 25720 (June
14, 1982), 47 FR 8734 (March 1, 1982),
and 47 FR 22474 (May 24, 1982).
Paragraph (ii) contained a technical
error as it incorrectly applied the
chargeable acreage and acreage
limitations to combined hydrocarbon
leases. Therefore, the BLM revises
§ 3141.8(a)(1)(ii) in the final rule to
provide that all of 43 CFR 3101 applies
to combined hydrocarbon leases, except
for the chargeability limitation
associated with oil and gas leases.
In addition, the BLM corrected an
incorrect cross reference in proposed
§ 3141.8(a)(1)(iv). This final rule
changes the cross references in this
section to §§ 3103.21, and 3103.31(a),
(b), and (c).
In addition, the BLM updated the
cross reference in § 3141.8(a)(1)(vii)
because the final rule adds another
paragraph, which changed the reference
to § 3106.10(j).
Finally, the BLM updated the cross
reference in § 3141.8(c)(1)(ii) because
the proposed rule referenced an
incorrect citation. The final rule will
correct the references to §§ 3103.31 and
3103.32 instead of § 3103.30.
Section 3141.53 Royalties and Rentals
The BLM proposed changes to the
existing § 3141.5–3 mainly to address
changes required by Congress in the
IRA. One commenter objected to royalty
rate reductions for tar sand leases and
recommended that the royalty rate not
be reduced. The BLM understands the
concern but cannot make this change as
the reduction is allowed by the statute,
see 30 U.S.C. 226(b)(2)(D).
Section 3141.63 Conduct of Sales
The BLM proposed eliminating
paragraph (a) and updating (b) to
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provide a consistent approach for
combined hydrocarbon leases and tar
sand leases. One commenter objected to
the noncompetitive leasing of additional
lands for tar sand development. The
BLM can no longer issue
noncompetitive tar sand leases after the
passage of the IRA 28 and does not
include a provision in the final rule that
provides for noncompetitive leasing;
therefore, the BLM did not make any
changes to the final rule based upon this
comment.
18. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3142
The final rule does not make any
revisions to the numbering or section
headings from the proposed rule for the
43 CFR 3142 regulations. The BLM did
not receive any comments on these
sections and adopts the proposed
changes in the final rule.
19. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3151
The final rule does not revise the
proposed section designations or their
headings in the 43 CFR subpart 3151
regulations.
Section 3151.30 Collection and
Submission of Data
The BLM proposed revising the
existing § 3151.30 to require a permittee
to submit to the BLM all data and
information collected under a
geophysical exploration permit. A
commenter expressed concern related to
the potential release of geophysical
exploration data to competitors through
a Freedom of Information Act (FOIA)
request. The BLM understands the
concern that geologic data be kept
confidential. Geological and geophysical
data is exempt from release under FOIA
pursuant to exemption 9, 5 U.S.C.
552(b)(9). Although exemption 9 under
FOIA would allow this information to
be exempt from release, the BLM also
updated the final regulations to ensure
it is clear that the BLM would not
release this information to the public by
including new paragraph (b), which
adds the statement that all information
submitted under this section ‘‘is
presumptively confidential business
information.’’
The commenter also stated that the
BLM provided no basis for why the
BLM needs this information, how it will
be used, or with whom it will be shared.
Such data will support the BLM’s
review and analysis of oil and gas
agreement applications and oil and gas
28 Inflation Reduction Act, Section 50262(e),
https://www.congress.gov/bill/117th-congress/
house-bill/5376/text.
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leasing decisions. The BLM will use this
data to inform an area’s oil and gas
development potential. In addition, the
geophysical exploration data will allow
the BLM to make better decisions
related to an exploratory unit
agreement’s boundary by ensuring that
the unit area encompasses only those
lands necessary for the proper
development of the unitized resources.
This information is exempt from release
to the public under exemption 9 of
FOIA, and the BLM will respect and
maintain the confidentiality of the
information.
20. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3160
The final rule does not make any
revisions to the section designations or
their headings in the existing 43 CFR
subpart 3160 regulations.
Section 3160.0–5 Definitions
The BLM proposed revising existing
definitions and added some new
definitions. The final rule does not
make any changes from the proposed
rule for the definitions within the
existing § 3160.0–5.
One commenter requested that the
BLM defer to the definitions and
analysis from State regulatory bodies for
what constitutes temporarily abandoned
and shut-in wells, because the proposed
regulations do not match State
standards and could lead to
inconsistency and confusion,
particularly on Federal wells that are
communitized with State or fee leases.
The BLM understands the concern;
however, the BLM declines to adopt this
change because the BLM’s definitions
are in keeping with its statutory
authority. For example, 30 U.S.C. 226(i)
states that a lease will not expire if it
contains a well capable of producing oil
or gas in paying quantities. The BLM’s
proposed definition reflects this
statutory requirement by defining
‘‘temporary abandoned well’’ as ‘‘a
nonoperational well that is not
physically or mechanically capable of
production or injection without
additional equipment or without
servicing the well, but that may have
future beneficial use.’’ Thus, a
temporarily abandoned well would not
be considered capable of production.
This differs from, for example, the
Wyoming Oil and Gas Conservation
Commission’s definition for
‘‘temporarily abandoned’’ that would
not comport with the statutory
framework. That definition is ‘‘a well in
which the completion interval has been
isolated from the wellbore above and
the surface. The completion interval
may be isolated by a retainer, bridge
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plug, cement plug, tubing and packer
with tubing plug, or any combination
thereof.’’ In addition, each State has
different definitions for temporarily
abandoned wells and shut-in wells. If
the BLM deferred to State regulatory
body definitions, the BLM would have
internal inconsistencies related to well
status definitions, which would result
in inconsistent regulatory and policy
implementation based on different
definitions for temporarily abandoned
wells and shut-in wells. Therefore, the
BLM declines to adopt this
recommendation.
A commenter requested that the rule
provide a definition of ‘‘temporarily
abandoned well’’ that includes a
reference to a well that may have
‘‘future beneficial use’’ and provided a
recommended definition of ‘‘a well that
has the potential to produce oil and
natural gas in the future as deemed by
a reasonable operator including after
recompletion, workover, and other
maintenance activities. It also includes
wells that have potential for geothermal,
carbon management, scientific
applications, technological advances, or
other exploration and production
related activities.’’ The BLM declines to
provide the definition as proposed by
the commenter in the final rule and
notes that reuse or conversion of wells
for other purposes is not the subject of
this rule. Moreover, the commenter’s
proposed definition varies significantly
from the BLM’s current policy regarding
whether a well is producing or is
abandoned, as found in Attachment 4 of
IM 2020–006, Idled Well Reviews and
Data Entry,29 which provides guidance
to BLM personnel about whether they
should take any action with respect to
wells that are not currently producing in
an effort to prevent such wells from
becoming orphan wells. Attachment 4
states the BLM ‘‘will consider a well to
have future beneficial use if the operator
will be able to use the well to generate
royalties in lease paying quantities or
will support the operator’s efforts to
generate royalties from other wells on
the lease.’’ Therefore, the BLM did not
make any changes to the definitions
based upon this comment.
Another commenter recommended
that the BLM define idled well,
orphaned well, and inactive wells. The
BLM declines to define these terms
because the BLM does not use these in
the regulations. In addition, the law
defines both idled wells at 42 U.S.C.
15907(a)(2) and orphaned wells at 42
U.S.C. 15907(a)(5).
Finally, a comment recommended
updating the definition of maximum
29 https://www.blm.gov/policy/im-2020-006.
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ultimate economic recovery to include
references to the BLM’s responsibilities
under FLPMA. The BLM declines to
update this definition at this time. The
BLM uses this definition in parts 3160
and 3170 to identify the maximum
amount of oil and gas that could be
produced from the reservoir using
existing technology. This definition
already is used in conjunction with the
FLPMA requirements in part 3160 (see
43 CFR 3162.1(a)). In part 3170, the term
is used to determine if a variance is
appropriate (see 43 CFR 3173.14(b)(4))
and in relation to off-lease
measurement. Based upon a review of
the usage of the maximum ultimate
economic recovery in the regulations,
the BLM determined that it was
unnecessary to include references to the
BLM’s responsibilities under FLPMA as
part of this definition.
21. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3162
The final rule does not make any
revisions to the section designations or
their headings in the existing 43 CFR
3162 regulations.
Section 3162.3–4 Well Abandonment
The BLM received many comments
both in support of and expressing
concern on the proposed revision of the
requirements for operators to monitor,
track, and report on shut-in and
temporarily abandoned wells. After
reviewing the comments, the BLM has
made the following changes:
(1) Reorganized paragraphs (c) and (d)
pertaining to temporarily abandoned
wells to ensure they are easy to read;
(2) Matched the plugging requirement
between shut-in and temporarily
abandoned wells in paragraph (d);
(3) Clarified in paragraph (e) that an
onshore operator will only need to
report a well as shut-in if the well will
be shut-in for 90 consecutive days; and
(4) Required mechanical integrity
tests every 3 years after a well is shutin or temporarily abandoned in
paragraph (f).
For paragraph (b), one commenter
objected to the requirement that ‘‘[a]ll
costs over and above the normal
plugging and abandonment expense will
be paid by the party accepting the water
well.’’ The commenter recommended
that the BLM revise this paragraph to
allow the operator of the well, the State,
a grazing association, or any other nonFederal entity to pay the additional
costs if a well is being conditioned into
a water supply source. The BLM did not
propose any changes to this paragraph
and disagrees with the commenter. If
the operator does not need the water
well and it is not supporting on-lease
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30951
activity, the BLM cannot require the
operator to cover any additional costs
related to setting up the well as a water
well. If the operator of the well, the
State, a grazing association, or any other
non-Federal entity agrees to pay the
additional costs for a well to be
conditioned into a water supply source,
the BLM will work with the funding
entity and the party accepting the water
well. In general, this would be a private
arrangement between the party
accepting the water well and the other
entity. The BLM did not make any
changes to the final rule based upon this
comment.
In reviewing the final rule for clarity,
the BLM identified that the
requirements for temporarily abandoned
wells were included in a single
paragraph at paragraph (c) in the
proposed rule and were difficult to
follow. Therefore, the BLM split
paragraph (c) into two paragraphs (c)
and (d) in the final rule and restructured paragraph (d) to match the
format for the requirements for shut-in
wells in the final rule with the format
for the requirements for temporarily
abandoned wells.
Although a few commenters
expressed support for the 4-year
requirement to plug temporarily
abandoned wells, one commenter
recommended a 2-year requirement, and
other commenters expressed concerns
that the 4 years proposed was too short.
The BLM reviewed these comments and
identified that there are legitimate
reasons why a well may need to remain
temporarily abandoned for longer than 4
years. For example, an operator may be
looking at converting a field for
enhanced recovery. Until the operator
has constructed the infrastructure to
support the operations, multiple wells
may need to be temporarily abandoned
since they will not be used until the
operator starts injections. Based upon
this scenario and other considerations
expressed in the comments, the BLM
updated the final rule in paragraph (d)
(paragraph (c) in the proposed rule) to
match the requirements for shut-in
wells and temporarily abandoned wells
for final abandonment. The final rule
now provides an option to ‘‘provide the
authorized officer with a detailed plan
and timeline for future beneficial use of
the well. If the authorized officer
determines that there is a legitimate
future beneficial use for the well, the
officer may allow the operator to delay
permanent abandonment by an
additional 1 year. The authorized officer
may grant additional delays in 1-year
increments, provided that the operator
confirms the future beneficial use of the
well and is making verifiable progress
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on returning the well to a beneficial
use.’’ This language matches the
requirements for shut-in wells.
In revising the regulation to allow a
well to be temporarily abandoned for
longer than 4 years, the BLM
determined that it needed to ensure that
these nonoperational wells maintain
their mechanical integrity. Therefore,
the BLM added paragraph (f) to require
mechanical integrity tests every 3 years,
after the first mechanical integrity test is
done. This section states, ‘‘All wells that
are temporarily abandoned or shut-in
must have mechanical integrity verified
as required in (d)(1) and (e)(2) and must
ensure that mechanical integrity is
verified every 3 years thereafter. The
operator must submit the results of each
verification of mechanical integrity to
the Authorized Officer within 30 days of
the mechanical integrity test.’’
One commenter requested that a
provision be added to the regulations
that allows recreational access to the
reclaimed locations. Once the lands
have been reclaimed and the BLM has
accepted an abandonment notice, the
public may use the lands for recreation,
provided the applicable RMP allows for
such use.
One commenter expressed concerns
related to the proposed rule’s
requirement that ‘‘no well may be
temporarily abandoned for more than 30
days without the prior approval of the
authorized officer.’’ The commenter
requested that the BLM extend the
temporary abandonment period for
which a notice and prior approval is
required from 30 days to 90 days. The
thirty-day period has been in place
since 1988, and the BLM is unaware of
evidence showing that it or operators
have experienced hardship from the
period. Therefore, the BLM kept the
current requirement of 30 days for
notice and prior approval.
The BLM requested comments on
whether to require a bond adequacy
review when a well is temporarily
abandoned. The BLM received
comments in support and opposition to
this proposal. After reviewing the
comments, the BLM has decided not to
require a bond adequacy review for a
change in well status, including
temporary abandonment of a well. The
BLM can review the adequacy of a bond
at any time, and the new reporting and
operational requirements for operators
of temporarily abandoned wells will
allow enhanced oversight of these wells.
The BLM considers the discretionary
authority to review a bond, combined
with the new reporting and operational
requirements, sufficient to effectively
manage any risks to the environment
associated with these types of wells
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without needing to require a bond
adequacy review.
Commenters expressed concerns that
the extra administrative requirements
related to temporarily abandoned and
shut-in wells will become overly
burdensome for the BLM to administer
and will result in contradictory
guidance and confusion for operators
balancing between State and Federal
regulations. One commenter also
mentioned the number of orphaned
wells that have been identified on
Federal lands. Another commenter
suggested the BLM should not require
operators to report a well status change
to the BLM because ONRR requires
operators to report on ONRR Form-4054
(‘‘OGOR’’) the well status (Well Status
codes 12 (OSI) and 13 (GSI)) beginning
with the last month of drilling and
continuing until the operator abandons
the well. Another commenter stated that
the BLM should accept all sundry
notices for temporarily abandoned or
shut-in wells as prima facia rationale
and timing parameters for these
nonoperational wells. After reviewing
the comments, the BLM identified that
paragraph (d)(1) in the proposed rule
required operators to report whenever a
well is shut-in. The BLM did not intend
for an operator to report each time a
well is shut-in. Instead, the BLM need
only be notified if the well would be
shut-in for 90 consecutive days.
Therefore, the BLM revised this section
to state, ‘‘Notify the authorized officer of
the well’s shut-in status, if the well will
be shut-in for 90 or more consecutive
days, and provide the date the well was
shut-in within 90 days of well shut-in.’’
As for the administrative burden
concerns, the BLM has reduced the
operator’s administrative burden with
this change since the operator would
not need to submit a notice for each
shut-in well. Instead, the operator will
only submit a notice for each well shutin for 90 or more consecutive days. The
final rule will also reduce the BLM’s
burden as the BLM can use the
notifications to update well status
instead of requiring the BLM to inspect
wells or review ONRR or State agency
data on well status. The BLM will
review notification of shut-in or
temporarily abandoned status to
determine if the rationale for shuttingin or temporarily abandoning the well
are supported by the information
provided in the notice. The BLM will
accept the sundry notice and update the
well status in its system; however, the
BLM will not provide a guarantee that
it will consider each sundry notice as
prima facia rationale for the status
change. The BLM has a responsibility to
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the American public to ensure that
unplugged non-operational wells are
still necessary to support lease
operations. If the unplugged nonoperational well will not support future
lease production, then the BLM will
request that the operator plug and
abandon the well.
Finally, the BLM reorganized this
section in the final rule. The BLM
removed the requirements for
temporarily abandoned wells from
paragraph (d) and left the reclamation
requirements for all wells permanently
abandoned within paragraph (c). The
BLM reorganized paragraph (d) for
temporarily abandoned wells to add
subparagraphs and ensure the language
in the final rule was clear. The BLM
redesignated the section for shut-in
wells to paragraph (e). The BLM also
added paragraph (f) to cover the
requirements for mechanical integrity
tests. The BLM makes these changes in
the final rule to more clearly inform the
regulated community of the
requirements.
22. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3164
The final rule does not make any
revisions to the section designations or
their headings in the existing 43 CFR
subpart 3164 regulations.
Section 3164.1 Onshore Oil and Gas
Orders
The BLM changed the existing
paragraph (b) to clarify that there are no
Onshore Oil and Gas Orders currently in
effect. Since the BLM codified the
Onshore Oil and Gas Orders in 43 CFR
part 3170,30 the BLM wants to ensure
the regulated community is aware that
they must follow 43 CFR subpart 3171.
Therefore, the BLM removes the
references to the Onshore Orders in this
section. All of the Onshore Oil and Gas
Orders are now codified in 43 CFR
subparts 3171, 3172, 3176, and 3177.
See 88 FR 39514 (June 16, 2023).
23. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3165
The proposed rule revised the
heading for 43 CFR 3165.1 from ‘‘Relief
from operating and producing
requirements’’ to ‘‘Relief from operating
and/or producing requirements.’’ The
BLM did not receive any comments on
this change and did not make any other
changes in the final rule.
30 Onshore Oil and Gas Operations; Federal and
Indian Oil and Gas Leases; Codification of Onshore
Orders 1, 2, 6, and 7 (88 FR 39514, June 16, 2023).
https://www.federalregister.gov/documents/2023/
06/16/2023-11742/onshore-oil-and-gas-operationsfederal-and-indian-oil-and-gas-leases-codificationof-onshore-orders.
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Section 3165.1 Relief From Operating
and/or Producing Requirements
The BLM revised the existing § 3165.1
to encourage diligent development of
leased lands and to ensure that any
lease suspensions are justified and have
a clearly stated end date. The BLM
received many comments on the
proposed rule related to changes to oil
and gas lease suspensions. The final
rule revises paragraph (c) to add the
word ‘‘only’’ before ‘‘cites’’ and replace
the acronym ‘‘APD’’ with ‘‘application
for permit to drill.’’
A commenter expressed concerns
regarding the proposed changes in light
of the BLM’s own delays in processing
APDs and lease suspensions and with
agency policy against ‘‘premature
suspensions.’’ The commenter asked the
BLM to clarify its intent so that lessees
can clearly understand the appropriate
time by which they should submit any
requests for suspensions. The BLM
agrees and drafted paragraph (c) to
specify the timeframe for a submission
of an APD such that a lessee could seek
a suspension based upon a pending
APD. The BLM does not believe any
other changes are necessary.
For paragraphs (a) and (b), one
commenter recommended that the final
rule should require the ‘‘full statement’’
to include a showing of leaseholder
diligence, 2and absent a showing of
diligence, the BLM would be required to
deny the request for relief. The BLM’s
existing policy in Manual Section 3160–
10, Suspension of Operations and/or
Production,31 already suggests the BLM
ensures that a lessee is diligently
developing its lease prior to granting a
suspension. The manual states,
‘‘Suspension of operations may be
directed or consented to by the
authorized officer in cases where a
lessee is prevented from operating on
the lease, despite the exercise of care
and diligence, by reason of force
majeure, that is, by matters beyond the
reasonable control of the lessee.’’
(Emphasis added). The manual has
similar guidance for suspensions of
production. In addition, the BLM also
not infrequently grants suspensions
when litigation precludes development
on an undeveloped lease. In these cases,
the lessee could not provide a showing
of leaseholder diligence when
requesting a lease suspension because
the BLM recently issued the lease.
Therefore, the BLM did not make any
changes in the final rule further
specifying requirements for the full
statement.
31 https://www.blm.gov/sites/default/files/docs/
2022-03/MS-3160-10%20Rel.%203-150.pdf.
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One commenter stated that the BLM
should not add paragraph (c) into the
final regulations, but instead leave the
substance of the paragraph in guidance.
Additionally, multiple commenters
claimed that the authorized officer
should have flexibility to approve a
lease suspension in spite of the timing
of the APD, if the officer believes it
would be appropriate given the
circumstances. The commenter then
stated that the BLM should not push the
operator towards diligent development,
as the submission of an APD is a
business decision based on markets,
investment capital, supply chains, labor
and equipment availability, and other
factors and that the failure to act
‘‘diligently’’ to develop a lease has no
adverse impacts on the environment.
This is outlined in existing policy at
Instruction Memorandum 2023–012,
Suspensions of Operations and/or
Production,32 and the BLM agrees that
the submission of an APD is a business
decision for the lessee. The BLM has
opted to incorporate this requirement in
regulation, however, to ensure that BLM
offices apply this requirement in the
same way to promote fairness to all
operators. The proposed changes
provide definitive notice to operators
and the BLM’s authorized officers on
processing these types of lease
suspension, and therefore, the BLM did
not make any changes based upon this
comment.
Other commenters stated that the 90day threshold proposed by the BLM is
arbitrary, because there is no recorded
evidence that the BLM can approve an
APD in 90 days. The BLM proposed the
90 days based upon the BLM’s average
processing time for an APD across all
BLM offices. The BLM provided this
information in the preamble. In fiscal
year 2022, the BLM’s average processing
time did increase to 162 days; however,
the BLM decided to keep with the 90day limit as it represents an average
over a period of 3 years.
The commenters also recommended
that instead of a set timeframe, the BLM
should deny suspension requests based
on a proposed action necessitating
NEPA analysis, which cannot
reasonably be completed prior to the
lease expiration date; based on events
the lessee could have and should have
foreseen or avoided; and based on
unknown, speculative, and or future
events. Finally, the commenters
recommended that the BLM should
deny suspensions based upon adjacent
unleased lands as the commenter
considered these types of suspensions
ripe for abuse and mismanagement. The
30953
BLM declines to make any changes to
the rule based on these
recommendations given the existing
discretion of the authorized officer. For
example, if the operator nominates
adjacent unleased lands that are needed
for development and are scheduled to
be offered on an upcoming lease sale
within the few months, the BLM does
not see this as an unreasonable request.
Comments demonstrated confusion
with the application of paragraph (c),
seemingly believing that the APD
submission requirement applies to all
suspensions. This provision only
applies when the applicant cites the
pending APD as the sole basis for the
suspension. If a lease needs to be
suspended in the interest of
conservation or for force majeure due to
reasons other than a pending APD, then
the BLM will not require an APD to be
filed at least 90 calendar days prior to
the expiration date of the lease. To
remove the confusion, the BLM
modifies the final rule by inserting the
word ‘‘only’’ prior to the word ‘‘cites.’’
In addition, to increase readability, the
BLM replaced the acronym ‘‘APD’’ with
the words ‘‘application for permit to
drill’’ as the BLM has not defined the
acronym ‘‘APD’’ in part 3160.
In addition, one commenter stated
that approving suspensions for only 1
year is arbitrary. The 1-year time frame
ensures that suspensions are not granted
for a longer period than necessary, and
it provides a clear and easily trackable
timeframe for both the BLM and lessees,
which allows both parties to ensure
compliance with applicable lease terms,
such as the resumption of paying rentals
or royalties. The BLM implemented an
annual review of lease suspensions in
Permanent Instruction Memorandum
2019–007, Monitoring and Review of
Lease Suspensions,33 after receiving
GAO’s recommendations in report
GAO–18–411, Oil and Gas Lease
Management: BLM Could Improve
Oversight of Lease Suspensions with
Better Data and Monitoring
Procedures.34 The BLM determined the
1-year timeframe was appropriate in this
rulemaking because it conforms with
BLM’s existing policy. If, after a year,
there is still a valid need for a
suspension, a lessee may request a
further extension.
Other commenters supported
approving suspensions for 1 year;
however, they also recommended that
the BLM modify the final regulations to
allow for only one extension to an oil
and gas lease suspension. One
commenter stated that the BLM should
33 https://www.blm.gov/policy/pim-2019-007.
32 https://www.blm.gov/policy/im-2023-012.
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34 https://www.gao.gov/products/gao-18-411.
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only grant additional suspensions in
those situations where the lessee or
operator is prevented from operating or
producing due to force majeure. The
BLM declines to accept this suggestion
to limit suspensions to those based on
force majeure because the MLA allows
for suspensions of operations and
production in the interest of
conservation. The BLM will evaluate
requests for suspension extensions to
ensure the bases for the suspension
remain valid, the operator has met any
diligence requirements or other
conditions of approval in the original
approval, and the suspension is
authorized by the MLA.
The BLM received several comments
on paragraph (e) urging the BLM to
modify this provision to only allow a
directed suspension to last 1 year. The
commenters claimed that long-term
suspensions do not further the public
interest or properly conserve natural
resources and instead encumber public
lands by making them unavailable for
other uses and for other potential
leaseholders, as well as fail to provide
taxpayers with a fair return for the lease
of public lands. The BLM declines to
make this change. Given the reasons for
which the BLM is authorized to issue a
directed suspension, such as a court
order, the suspension must remain in
effect until the court allows operations.
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24. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3171
The final rule does not make any
revisions to the section designations or
their headings in the existing 43 CFR
subpart 3171 regulations.
Section 3171.14 Valid Period of
Approved APD
The BLM received many comments
on the proposed rule related to changing
the term of an approved APD from the
current 2 years with an optional 2-year
extension to a 3-year term without
extensions. The BLM received
comments both in support and with
concerns related to the proposed
changes. After reviewing the comments,
the BLM has made the following
changes: (1) omitted the word
‘‘ordinarily’’ from paragraph (a); (2)
clarified that the APD term in the
regulations only applies to APDs
approved after the effective date of the
final rule; (3) clarified that the well
must be drilled to total measured depth
in paragraph (b); (4) clarified that
paragraph (b)(1) includes wells drilled
to approximate total measured depth
and not yet completed; (5) stated that
paragraph (b)(3) will only apply if the
operator set the surface casing for the
well and submits a plan to finish
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drilling and complete the well; (6)
provided that the plan in paragraph
(b)(3) must include the timeframe for
continuously drilling and completing
the well and any extenuating
circumstances that may delay the
continuous drilling and completion of
the well; (7) specified that earthwork for
reclamation must be completed within 6
months of the approved APD’s
expiration; and (8) added paragraph (e)
to provide for the extension of an APD’s
term when the underlying lease is
suspended.
Many commenters supported the
BLM’s proposal to extend the initial
term of an approved APD from 2 to 3
years; however, multiple commenters
recommended that the BLM establish a
4-year term for approved APDs.
Commenters stated that a 4-year term for
an approved APD would enable the
BLM to process APDs efficiently and
would provide consistency for industry.
The BLM rejected this change, since
approximately 95 percent of the
approved APDs drilled under the
existing regulations have been drilled
within 3 years from the date of
approval. By providing a set term
without the option to extend, the BLM
is providing more certainty for the
industry to allow it to properly plan any
operations. The remaining five percent
may submit a new APD. Given the small
percentage of operators who do not
normally drill a well within 3 years of
approval of an APD, the BLM believes
the administrative burden on an
operator of filing a new APD is justified
in light of the BLM’s interest in ensuring
the public lands subject to an oil and
gas lease are diligently developed.
One commenter encouraged the BLM
to modify the rule and keep the current
2-year period for an approved APD with
allowable extensions, stating the rule
would have negative effects by
increasing the BLM’s administrative
burden and requiring additional
environmental review. The BLM
disagrees. Currently, the BLM spends
approximately 3,800 hours annually on
processing APD extension requests. In
some cases, the NEPA analysis is stale,
and the BLM must complete a new
analysis on the APD to verify that the
impacts identified have not changed.
This rule will reduce the administrative
burden on both the BLM and the
operator as extension requests would no
longer be needed. The burden on the
BLM would be further reduced by
obviating the need for any potential
additional NEPA analysis to support an
extension. In addition, the 3 years in
which to use an APD will provide
sufficient time for 95 percent of the
operators. Therefore, the BLM did not
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make any changes based upon this
comment.
A commenter stated that changing the
term of an approved APD from 2 years
to 3 years without the possibility of an
extension would kill many oil and gas
projects before they ever get off the
ground. The commenter supported this
statement citing the length of time
required to comply with NEPA. Without
recourse to an extension, an operator is
left without any means to maintain a
lease. Often an operator is prevented
from drilling due to circumstances
completely out of their control. The
comment encouraged the BLM to
examine the negative effects the rule
will have in this regard. The BLM
believes the comment is confusing oil
and gas lease suspensions and approved
APD extensions. The BLM will still
grant lease suspensions, which will
allow an operator to maintain its lease
if the suspension requirements are met,
and which toll the running of the term
of any previously issued permit to drill.
This provision only addresses
extensions for APDs. Moreover, even if
a well is not drilled within the 3-year
time period, as noted above, an operator
can submit a new APD.
Another commenter recommended
that the BLM omit the word
‘‘ordinarily’’ from paragraph (a) to avoid
confusion. The comment stated that
since ‘‘ordinarily’’ implies there is an
exception, it is unnecessary with the
‘‘notwithstanding’’ clause, which is
already addressed in paragraph (b). The
BLM concurred with this
recommendation and deleted the word
‘‘ordinarily’’ from paragraph (a).
In addition, one commenter requested
that any change in terms to approved
APDs only apply to the APDs approved
and issued subsequent to the
publication of a final rule. The BLM
concurs with this recommendation. The
BLM modified the final rule to clarify
that the 3-year term only applies to
APDs approved after the effective date
of the rule. Consistent with general
principles of retroactivity, any APD
approved prior to the effective date of
this rule will be eligible for a 2-year
extension in accordance with the
regulations in place when the BLM
approved the APD.
For paragraph (b), a commenter
requested that the rule specify either
total vertical depth or total measured
depth in the final rule. The BLM
specifies total measured depth in the
final rule as measured depths matches
the requirements in an approved APD.
A horizontal well drilled to total vertical
depth would likely not be productive in
paying quantities and would not meet
the plans in the approved APD.
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For paragraph (b)(1), a commenter
requested that the BLM specify in the
regulations that drilling, but not
completing, would provide for the APD
approval to remain valid. The BLM
intended as much and has clarified the
final rule by adding the statement
‘‘including wells drilled to approximate
total measured depth and not yet
completed’’ to paragraph (b)(1).
For paragraphs (b)(1) and (b)(2), a
commenter recommended that the BLM
set a time limit of one-year for any
extensions beyond the initial term of the
APD based on the criteria outlined in
the proposed regulation. The BLM
declines to provide for a further
extension of an APD under either (b)(1)
or (b)(2). In both of these scenarios, a
well has already been drilled to the
approximate total measured depth as
authorized by the APD. Instead, the
BLM will administer the wells as shutin or temporarily abandoned if the well
is not yet producing at the expiration of
the APD. This allows the BLM to track
and manage these wells under 43 CFR
3162.3–4. Therefore, there is no need to
set a limit of one-year for paragraphs
(b)(1) and (b)(2) in this section.
The BLM received multiple comments
on paragraph (b)(3). Some commenters
considered the requirement for the plan
to be vague and that the regulatory
language leaves the authorized officer
with no guidance for approving such a
plan. A separate comment
recommended that the BLM accept
reasonable plans to complete drilling
any well to total depth if the operator
has set surface casing prior to the APD
expiring. The BLM reviewed the many
comments on the plan required by this
section and recognized that more
information on the plan should be
added to the regulations. Based on these
comments, the BLM has revised
paragraph (b)(3) to specify that the
‘‘plan must include the timeframe for
continuously drilling and completing
the well and any extenuating
circumstances that may delay the
continuous drilling and completion of
the well.’’
In addition, multiple commenters
encouraged the BLM to delete paragraph
(b)(3). They asserted that paragraph
(b)(3) would allow APD extensions
based only on submission of a drilling
plan to the BLM, with no requirement
that on-the-ground activity have taken
place, undermining the goal of diligent
development. They further contended it
may risk further waste of public lands
and resources. The BLM concurs that
the operator should be pursing diligent
development with a showing of on-theground activity. The BLM modified
paragraph (b)(3) to require that on-the-
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ground activity has taken place to
ensure the operator has started
development under the APD. For the
final rule, the BLM updated paragraph
(b)(3) to require the operator to have set
the surface casing for the well and to
have submitted a plan. This will ensure
the operator is working towards
developing its lease with a real effort to
begin development. In addition, as
noted above, one comment
recommended the BLM accept
reasonable plans to complete drilling
any well to total depth if the operator
has set surface casing prior to the APD
expiring. Therefore, the BLM considered
requiring surface casing for the BLM to
consider a plan as a reasonable
approach for paragraph (b)(3).
For paragraph (c), a commenter
expressed concern that an operator may
not be able to submit an APD to finish
drilling the well during the time
allowed under the proposed regulations,
and the regulations would then require
the operator to immediately comply
with all applicable plugging,
abandonment, and reclamation
requirements. This was not the intent in
the proposed rule; therefore, the BLM
updated the final rule to provide two
options for an expired APD. The
‘‘operator or lessee must either comply
with all applicable plugging,
abandonment, and reclamation
requirements or submit a new APD
covering the existing disturbance.’’
The BLM received a comment on
paragraph (d) suggesting that the BLM
should specify the timeframe by which
reclamation must start once an APD
expires. The BLM’s existing regulations
require earthwork for reclamation to
begin within 6-months of well
completion or well plugging under 43
CFR 3171.25(b)(2). To be consistent
with 43 CFR 3171.25(b)(2), the final rule
updates paragraph (d) to state,
‘‘Earthwork for reclamation must be
completed within 6 months of APD
expiration (weather permitting).’’
Multiple commenters expressed
concern that the BLM proposes to no
longer grant extensions to an APD’s
term. Some commenters expressed a
concern that the lack of an APD
extension would disadvantage project
proponents in situations where drilling
was delayed for a variety of on-theground reasons and there is not a way
to seek an APD extension. Another
commenter mentioned the need for
extensions when there is litigation
challenging the NEPA compliance for
the lease or APD because the BLM
cannot take any action on an APD when
there is ongoing litigation. Upon review
of the comments, the BLM recognizes
that there is a valid concern related to
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litigation challenging the issuance of
leases; therefore, the BLM added
paragraph (e), which will allow the BLM
to adjust an APD’s term when the lease
is suspended. The new paragraph (e)
states, ‘‘The valid period for an
approved APD on a lease suspended
under subpart 3103 will be adjusted to
account for the suspension. Beginning
on the date the suspension is lifted, the
valid period of the approved APD will
be extended by the time that was
remaining on the term of the approved
APD on the effective date of the
suspension.’’ This addition will allow
the BLM to extend the term of an
approved APD based upon an oil and
gas lease suspension of operations and/
or production. The BLM will not grant
general extensions as the 3-year APD
term will provide sufficient time for the
Federal operator to drill a well under an
approved APD.
25. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3181
The BLM identified that 43 CFR
3181.5 should be updated to recognize
the changes to royalty made by the IRA.
The BLM has revised the existing
§ 3181.5 in the final rule to reflect the
increased royalty rate.
Finally, the rule will not make any
revisions to the section designations or
their headings in the existing 43 CFR
subpart 3181 regulations.
Section 3181.5 Compensatory Royalty
Payment for Unleased Federal Land
During the public comment period,
the BLM discovered that § 3181.5 of the
current regulations still references a
royalty rate of 12.5 percent. As
discussed earlier, in the IRA, Congress
changed the royalty rate for onshore
Federal oil and gas leases to 16.67
percent, a rate that will last until August
2032, at which time, the royalty rate
becomes not less than 16.67 percent and
subject to further increases. Therefore,
the BLM is replacing the 12.5 percent
royalty in § 3181.5 with the language
‘‘the current royalty percentage for
leases offered on onshore oil and gas
lease sales.’’ This will allow BLM offices
to enter the appropriate royalty rate
based upon the latest onshore oil and
gas lease sales for the area.
26. Section-by-Section Discussion for
Changes to 43 CFR Subpart 3186
During the comment period, BLM
employees identified that a section in
the model onshore unit agreement for
unproven areas should be updated to
recognize the changes Congress made to
royalty rates in the IRA.
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Section 3186.1 Model Onshore Unit
Agreement for Unproven Areas
Section 17(b) of the model onshore
unit agreement for unproven areas still
references the old royalty rate of 12.5
percent. Because Congress changed the
royalty rate in the IRA for onshore
Federal oil and gas leases to 16.67
percent, the BLM is replacing the 12.5
percent royalty in Section 17(b) of the
model onshore unit agreement for
unproven areas with the language
‘‘(current royalty for leases offered on
onshore oil and gas lease sales).’’ This
will allow BLM offices to enter the
appropriate royalty rate based upon the
latest onshore oil and gas leases.
The BLM is republishing the revised
model onshore unit agreement for
unproven areas in the final rule in its
entirety because the OFR is unable to
make a piecemeal edit to the document.
The document is not regulatory and, in
conformance with current OFR
Document Drafting Handbook
requirements, cannot be given section
numbers. Instead, the model onshore
unit agreement for unproven areas must
be redesignated in the final rule as
Appendix A to Part 3180. The BLM uses
this model form to identify where new
unit agreements do not match the model
form and ensures any differences from
the model form are in the public
interest.
Likewise, at the direction of the OFR,
the BLM is redesignating four other
models and exhibits that comprise the
remainder of existing subpart 3186.
These items will appear in the final rule
as follows: (1) § 3186.1–1 Model
‘‘Exhibit A’’ will appear as Appendix B
to Part 3180; (2) § 3186.1–2 Model
‘‘Exhibit B’’ will appear as Appendix C
to Part 3180; (3) § 3186.3 Model for
designation of successor unit operator
by working interest owners will appear
as Appendix D to Part 3180; and (4)
§ 3186.4 Model for change in unit
operator by assignment will appear as
Appendix E to Part 3180. The final rule
does not revise the contents of
Appendices B through E.
Cross refences in §§ 3107.10(a),
3181.1 and 3183.4(a) are revised in the
final rule to reflect the redesignated
appendices.
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Procedural Matters
A. Regulatory Planning and Review
(E.O. 12866, E.O. 14094, E.O. 13563)
E.O. 12866, as amended by E.O.
14094, provides that the Office of
Information and Regulatory Affairs
(OIRA) within the Office of Management
and Budget (OMB) will review all
significant rules. OIRA has determined
that this final rule constitutes a
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‘‘significant regulatory action’’ within
the scope of section 3(f)(1) of E.O.
12866, as amended by E.O. 14094.
During the comment period for the
proposed rule, some commenters
suggested that the proposed rule would
cause adverse effects on the economy,
the energy sector of the economy, and
all communities that rely on fluid
mineral development as their major
economic driver. Commenters pointed
to the language in the preference criteria
for leasing under § 3120.42, asserting it
could severely restrict the amount of oil
and gas leasing on Federal lands. The
BLM disagrees. Codifying the preference
criteria will ensure that oil and gas
leasing on public lands focuses
development where there is the most
potential for recovery and allows the
agency to manage public lands for other
uses. The BLM completed an RIA and
determined that the net costs to the
economy range from a cost of $8.0
million to a cost of $13.2 million,
depending on the cost of bonds (1
percent or 2 percent) and the number of
wells the BLM reclaims (15 wells or 24
wells). As discussed in the RIA, the
BLM expects that the expedited timing
for reclamation of orphaned wells from
increased bonding could provide
benefits related to wildlife, vegetation,
soil erosion, climate change (reduced
greenhouse gas emissions from
unplugged orphaned wells), visual and
aesthetic resources, ground water, and
allowing the surface land to be utilized
for other uses sooner (for example, for
grazing purposes). The BLM cannot
currently quantify these benefits using
the information available to the BLM.
Other benefits of the final rule include
ensuring that costs reside with oil and
gas lessees, operating rights owners, and
operators, and not the American public.
This includes adjusting the BLM’s cost
recovery mechanisms so that project
applicants provide a more equitable
share of the BLM’s up-front costs for
processing these applications. Finally,
the BLM implements several changes to
provide a transparent leasing process
that focuses leasing on areas with a
greater likelihood of being developed
with fewer resource conflicts and
ensuring transparency in these
processes. Overall, shifting the financial
responsibility for leasing to industries
and ensuring transparency in the
decision-making process will result in a
more effective, fair, and accountable
regulatory framework that benefits both
businesses and society as a whole.
E.O. 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,
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most innovative, and least burdensome
tools for achieving regulatory ends. The
E.O. 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.
This final rule replaces the BLM’s
current rules governing oil and gas
leasing, which are contained in 43 CFR
3100 through 3140, and revises some
regulations governing oil and gas
operations, which are contained in 43
CFR 3150 through 3171.
For any regulatory action that OIRA
determines is a significant regulatory
action under section 3(f)(1) of E.O.
12866, section 6(a)(3)(C) of E.O. 12866
requires Federal agencies to provide an
assessment, including the underlying
analysis, of costs and benefits of
potentially effective and reasonably
feasible alternatives to the planned
regulation, identified by the agencies or
the public (including improving the
current regulation and reasonably viable
non-regulatory actions), and an
explanation why the planned regulatory
action is preferable to the identified
potential alternatives. 58 FR 51735,
51741. The BLM developed this final
rule in a manner consistent with the
requirements in E.O. 12866 and E.O.
13563.
For more detailed information on the
BLM’s analysis, as required by the
referenced Executive Orders, see the
RIA prepared for this final rule. The RIA
has been posted in the docket for the
final rule on the Federal eRulemaking
Portal: https://www.regulations.gov. In
the Searchbox, enter ‘‘RIN 1004–AE80’’,
click the ‘‘Search’’ button, open the
Docket Folder, and look under
Supporting Documents.
B. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA)
(5 U.S.C. 601 et seq.) requires that
Federal agencies prepare a regulatory
flexibility analysis for rules subject to
the notice-and-comment rulemaking
requirements under the Administrative
Procedure Act (5 U.S.C. 500 et seq.), if
the rule would have a significant
economic impact, whether detrimental
or beneficial, on a substantial number of
small entities. See 5 U.S.C. 601–612.
Congress enacted the RFA to ensure that
government regulations do not
unnecessarily or disproportionately
burden small entities. Small entities
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include small businesses, small
governmental jurisdictions, and small
not-for-profit enterprises.
The BLM reviewed the Small
Business Administration’s (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 number of small businesses in
States where there are existing Federal
oil and gas leases is estimated to be
20,975 for the Crude Petroleum
Extraction and Natural Gas Extraction
industries (North American Industry
Classification System (NAICS) codes
211120 and 21130, respectively). 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 final rule will likely
affect a substantial number of small
entities.
In addition, the rule will have a
distributional and positive impact on
the Direct Property and Casualty
Insurance Carriers Industry (NAICS
524126). Additional premiums will be
paid by lessees in the oil and natural gas
extraction industries to surety
companies who will be providing the
coverage to meet the proposed bonding
requirements. The number of small
businesses in the oil and gas industry in
States where there are existing Federal
oil and gas leases is estimated to be
476,687. This is because the SBA
defines a small business for purposes of
the Crude Petroleum Extraction and
Natural Gas Extraction industries
(NAICS codes 211120 and 21130,
respectively) as one which has 1,250 or
fewer employees.
Finally, the BLM received multiple
comments expressing concerns related
to impacts that the proposed rule would
have on small entities. Specifically, the
comments stated that: (1) the BLM
should have included the changes from
the IRA in its analysis for the Regulatory
Flexibility Act (RFA); (2) the BLM
should have mailed notification of the
proposed rule to the affected small
businesses under the RFA; (3) the BLM
should have considered alternatives as
required by the RFA; and (4) this rule
requires the preparation of an initial and
final Regulatory Flexibility Analysis.
The BLM reviewed the final rule and
has determined that, although the final
rule will likely affect a substantial
number of small entities, that effect will
not be significant. The basis for this
determination is explained in more
detail in the RIA.
Because the increased royalty
amounts, bonus bids, and rentals, and
the EOI fee, are non-discretionary, the
BLM is not required to include these
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increases in its evaluation of the
impacts on small businesses. Congress
passed the RFA ‘‘to establish as a
principle of regulatory issuance that
agencies shall endeavor, consistent with
the objectives of the rule and of
applicable statutes, to fit regulatory and
informational requirements to the scale
of the businesses, organizations, and
governmental jurisdictions subject to
regulation. To achieve this principle,
agencies are required to solicit and
consider flexible regulatory proposals
and to explain the rationale for their
actions to assure that such proposals are
given serious consideration.’’ Public
Law 96–354, section 2(b), 94 Stat. 1164
(1980). The RFA requires agencies to
analyze alternatives to their rules with
an eye towards minimizing significant
impacts on small entities. 5 U.S.C.
603(c), 604(a)(6). In this case, the BLM
cannot consider alternatives to
mandatory instructions in the IRA. The
nondiscretionary changes include the
increased minimum bonus bid, rental,
and royalty rate, and the new EOI fee.
The only discretionary cost increases at
issue in this final rule are the increased
bonding amounts and filing fees, which
are fully analyzed. Aside from assessing
alternatives to the statutorily mandated
provisions of this rule, however, the
BLM has provided the analysis the RFA
requires.
Based on the BLM’s review of the
costs associated with the increased
bonding, the BLM has determined that
the incremental costs that a company
must pay to meet the increased bonding
amounts are unlikely to deter a
company from obtaining a lease and
developing it. As discussed in the RIA,
sureties offer both new and existing
operators the ability to cover the
increased bond amount at an estimated
cost of only 1 to 2 percent per year of
the additional bond amount.
While there were multiple comments
stating that small operators will be
forced to shut in wells, will be at higher
risk of going bankrupt, or will go
bankrupt due to the increased costs, the
comments did not provide the well- or
lease-level financial information needed
to support these claims. The BLM
reviewed available data and reported
statistics on the sensitivity of lowproducing wells to changes in wellhead
prices and concluded that, given the
range of recent and expected oil prices,
even low-producing wells generate
sufficient revenue to fund the increased
level of bonding. The economic data
provided from the public comment
period did not provide the necessary
detail to support a more detailed
analysis. For example, one commenter
provided a report on the economic
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benefits of oil and gas leasing. This
report supported our baseline in the
RIA; however, it did not change the
BLM’s estimates of the impacts from
this rule.
Notably, the BLM has only limited
access to financial data of the small
businesses themselves, since most of
those small businesses are privately
held and are not required to report their
financial information to the BLM or any
other public forum. Even if a company
is public, those covered under the
NAICS codes for Crude Petroleum and
Natural Gas Extraction are often
partnerships or limited liability
companies, which frequently merge and
split, making it difficult to determine if
a firm composed of partners and
subsidiaries are sufficiently affiliated to
be considered small businesses or if
they are functionally a subsidiary of a
larger firm. Even when financial
statements are available for review,
those statements are designed to
standardize overall reporting of an
entity’s finances and do not specify
income and expenditures associated
with production from Federal wells. Nor
is it possible to obtain the requisite
information on both Federal production
volume and the production costs of this
Federal production from any Federal
database. For example, ONRR reports
production volumes but not production
costs. Constructing the needed data on
Federal production and financial costs
requires cross-referencing several data
sources that are not readily available.
Therefore, based on the BLM’s review,
the BLM lacks the data to determine
whether the rule will impact small
businesses in the manner the
commenters assert. Nor is such
information reasonably available to the
BLM such that it could undertake such
analysis. The BLM has, nevertheless,
reaffirmed its finding that the rule will
not have a significant impact on a
substantial number of small entities for
the reasons described above in this
section.
In summary, the per-entity,
annualized compliance costs associated
with this final rule are estimated to
represent only a small fraction of the
annual net incomes of the companies
likely to be impacted. Because the final
rule will not have a ‘‘significant
economic impact on a substantial
number of small entities,’’ neither an
initial nor a final regulatory flexibility
analysis is required.
The Secretary of the Interior certifies
under 5 U.S.C. 605(b) that this rule will
not have a significant economic impact
on a substantial number of small
entities.
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C. Congressional Review Act
The Congressional Review Act (5
U.S.C. 804(2)) requires certain
procedures for ‘‘any rule that the
Administrator of the Office of
Information and Regulatory Affairs of
the Office of Management and Budget
finds has resulted in or is likely to result
in—
a. an annual effect on the economy of
$100 million or more;
b. a major increase in costs or prices
for consumers, individual industries,
Federal, State, or local government
agencies, or geographic regions;
c. significant adverse effects on
competition, employment, investment,
productivity, innovation, or the ability
of United States-based enterprises to
compete with foreign-based enterprises
in domestic and export markets.
DOI will report to Congress on the
promulgation of this rule prior to its
effective date. The report will state that
the Office of Information and Regulatory
Affairs has determined that this rule
meets the criteria set forth in 5 U.S.C.
804(2).
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D. Unfunded Mandates Reform Act
(UMRA)
The final rule will not have a
significant or unique effect on State,
local, or Tribal governments or the
private sector. The rule contains no
requirements that apply to State, local,
or Tribal governments. The rule revises
requirements that otherwise apply to the
private sector participation in a
voluntary Federal program. The
compliance costs associated with the
rule are below the monetary threshold
established at 2 U.S.C. 1532(a). The rule
updates the BLM’s existing regulations
to reflect the IRA’s changes to lease
terms. Those provisions (which became
effective with the enactment of the IRA
and which the BLM has no discretion to
modify) will result in additional transfer
payments made from the private sector
to the U.S. Treasury, which then
distributes portions to State
governments and various funds, such as
the Land and Water Conservation Fund.
The BLM estimates the transfer
payments will total $210 million per
year, but these payments are not a result
of action taken by the BLM and are
instead Congressionally mandated.
Since the discretionary provisions of the
rule impose compliance costs that are
below the $100,000,000 threshold
established at 2 U.S.C. 1532(a), a
statement containing the information
required by the Unfunded Mandates
Reform Act (UMRA) (2 U.S.C. 1531 et
seq.) is not required for the final rule.
This final rule is also not subject to the
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requirements of section 203 of UMRA
because it contains no regulatory
requirements that might significantly or
uniquely affect small governments,
because it contains no requirements that
apply to such governments, nor does it
impose obligations upon them. In any
event, this rule and the accompanying
Regulatory Impact Analysis provide all
the information the UMRA requires.
E. Governmental Actions and
Interference With Constitutionally
Protected Property Right—Takings (E.O.
12630)
This final rule will not effect a taking
of private property or otherwise have
taking implications under E.O. 12630;
therefore, a takings implication
assessment is not required. The final
rule replaces the BLM’s current rules
governing oil and gas leasing, which are
contained in 43 CFR 3100 through 3140,
and some governing oil and gas
operations, which are contained in 43
CFR 3160 and 3171. Therefore, the rule
will impact future leases on Federal
land; however, it will not impact
current leases. All other terms in the
regulations are not considered a taking
of private property as such operations
are subject to the existing lease terms
which expressly require that subsequent
lease activities be conducted in
compliance with subsequently adopted
Federal laws and regulations.
This final rule conforms to the terms
of the existing leases and applicable
statutes and, as such, the rule is not a
government action capable of interfering
with constitutionally protected property
rights. Therefore, the BLM has
determined that the rule will not cause
a taking of private property or require
further discussion of takings
implications under E.O. 12630.
F. Federalism (E.O. 13132)
Under the criteria in section 1 of E.O.
13132, this final rule does not have any
federalism implications to warrant the
preparation of a federalism summary
impact statement.
The final rule will not have a
substantial direct effect on the States, on
the relationship between the Federal
Government and the States, or on the
distribution of power and
responsibilities among the levels of
government. It does not apply to States
or local governments or State or local
governmental entities. The rule will
affect the relationship between
operators, lessees, and the BLM, but it
does not directly impact the States.
Therefore, in accordance with E.O.
13132, the BLM has determined that
this final rule does not have sufficient
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federalism implications to warrant
preparation of a Federalism Assessment.
Several commenters suggested that
the BLM should make substantial
changes to the rule to allow for better
cooperation with States and local
governments when their jurisdictions
overlap. For example, one comment
stated that the BLM must respect local
governments’ regulatory authority over
State, private, and trust mineral and
water resources within each State.
Another comment stated that the
proposed rule would have significant
direct impacts on the States and local
communities, and that, if the BLM does
not offer Federal lands for lease, that
omission will prevent State and private
lessees from developing their leases due
to the mixed ownership for horizontal
wells. Some comments stated the rule is
inconsistent with State laws that
expedite the processing, granting, and
streamlining of mineral and energy
leases and permits.
The BLM developed this rule based
on its statutory authority to offer
federally owned lands and minerals for
oil and gas leasing and development.
The BLM has evaluated the federalism
implications of this rule as required by
E.O. 13132. Although the final rule will
affect the relationship between
operators, lessees, and the BLM, it will
not directly impact the States’ leasing
ability. Local governments and the
public may submit information to the
BLM on how the development of
nominated lands may affect the
development of adjacent non-Federal
lands when the BLM is considering
lands for leasing. This could occur
either when the EOI is submitted or
during the scoping and public comment
periods for the lease sales.
G. Civil Justice Reform (E.O. 12988)
This final rule complies with the
requirements of E.O. 12988. More
specifically, this final rule meets the
criteria of section 3(a), which requires
agencies to review all regulations to
eliminate errors and ambiguity and to
write all regulations to minimize
litigation. This final rule also meets the
criteria of section 3(b)(2), which
requires agencies to write all regulations
in clear language with clear legal
standards.
H. Consultation and Coordination With
Indian Tribal Governments (E.O. 13175
and Departmental Policy)
The Department strives to strengthen
its government-to-government
relationship with Indian Tribes through
a commitment to consultation with
Indian Tribes and recognition of their
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right to self-governance and tribal
sovereignty.
The BLM evaluated this final rule
under the Department’s consultation
policy and under the criteria in E.O.
13175 to identify possible effects of the
rule on federally recognized Indian
Tribes. Since the changes to leasing only
apply to Federal lands, the final rule
will not impact the leasing of Indian
minerals. The final rule could impact
Tribal minerals as the BLM will require
operators on both Federal and Tribal
minerals to comply with the
requirements within Parts 3160 and
3170, including the changes for shut-in
and temporarily abandoned wells and
approved APDs.
In August of 2021, the BLM sent a
letter to each registered Tribe informing
them of certain rulemaking efforts,
including the development of this final
rule. The letter offered Tribes the
opportunity for individual governmentto-government consultation regarding
the rulemaking.
In June 2023, the BLM sent another
letter to each registered Tribe informing
them of the proposed rule. During the
comment period for the proposed rule,
a commenter, who is not from a Tribe,
stated that the BLM should fulfill its
Federal trust obligation to Tribes to
protect their interest and further the
government-to-government
relationships with Tribes. The BLM
concurs and worked to inform the
Tribes of the changes proposed in this
rulemaking. The BLM did receive
comments from a Tribe as previously
discussed in Section III.B.4. and III.B.8.
of this preamble.
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I. Paperwork Reduction Act
The Paperwork Reduction Act (PRA)
(44 U.S.C. 3501–3521) generally
provides that an agency may not
conduct or sponsor, and not
withstanding any other provision of
law, 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 any request or requirement that
persons obtain, maintain, retain, or
report information to an agency, or
disclose information to a third party or
to the public (44 U.S.C. 3502(3) and 5
CFR 1320.3(c)).
This final rule contains informationcollection requirements that are subject
to review by OMB under the PRA. OMB
has generally approved the existing
information collection requirements
contained in the regulations that will be
affected by this final rule under the
following OMB Control Numbers:
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• 43 CFR 3100, 3120, and subpart
3162—OMB Control Number 1004–
0185;
• 43 CFR 3106—OMB Control
Number 1004–0034;
• 43 CFR part 3130—OMB Control
Number 1004–0196;
• 43 CFR 3150—OMB Control
Number 1004–0162; and
• 43 CFR 3160—OMB Control
Number 1004–0137.
The BLM plans to transfer the
information collection requirements
contained in 43 CFR 3106 from OMB
control number 1004–0034 to OMB
Control Number 1004–0185 in order to
keep similar information collections
requirements together under the same
OMB Control Number. Additionally, the
BLM plans to transfer information
collection requirements contained in 43
CFR 3160 from OMB Control Number
1004–0137 to a new OMB Control
Number. Once approved by OMB, the
new OMB Control Number will be
1004–0220. The new and revised
information collection requirements are
discussed as follows, along with the
resulting changes in public burdens.
1. Changes Impacting Information
Collections Previously Under OMB
Control Number 1004–0137
The final rule will result in new
information collection requirements that
will require OMB approval under a new
OMB control number (previously, 1004–
0137). This final rule is estimated to
result in 33,621 annual responses,
260,928 annual burden hours,
$35,400,000 non-hour cost burdens
under this new OMB Control Number.
The new information collection
requirements are described as follows.
43 CFR 3162.3–4 Well Abandonment.
The final rule requires that no well may
be abandoned for more than 30 days
unless the operator provides adequate
and detailed justifications and
verification of the mechanical integrity
of the wells and isolation of the
perforations. The new information
collection requirements include:
• Justification for Temporary Well
Abandonment—43 CFR 3162.3–4(d);
• Reporting Shut-in Status—43 CFR
3162.3–4(e);
• Verification of Mechanical
Integrity—43 CFR 3162.3–4(e)(2) and
3162.3–4(f); and
• Plan and Timeline for Future
Beneficial Use—43 CFR 3162.3–
4(e)(3)(iii).
The BLM believes these new
requirements with yearly interval
checks will help operators stay on top
of shut-in wells, thus preventing them
from becoming orphaned in the future.
The addition of these information
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collection requirements will result in an
addition of 5,500 annual responses,
52,000 annual burden hours.
Currently, there are 301,663 annual
responses, 1,835,888 annual burden
hours, and $31,080,000 annual nonhour cost burdens inventoried under the
OMB Control Number 1004–0137. This
final rule will create a new OMB
Control Number and moves 28,121
annual responses, 208,298 annual
burden hours, and $31,080,000 annual
non-hour cost burdens inventoried
under OMB Control Number 1004–0137
into this OMB Control Number.
In addition, there is an adjustment of
$4.3 million in annual non-hour cost
burdens (from $31 million to 35.4
million). This adjustment results from
the annual inflation adjustment of filing
fees and do not result from the final
rule. The resulting new estimated total
burdens for this new OMB Control
Number are provided as follows.
Title of Collection: Onshore Oil and
Gas Operations and Production (43 CFR
parts 3160 and 3170).
OMB Control Number: 1004–0220.
Form Numbers: BLM Form 3160–003;
BLM Form 3160–004; and BLM Form
3160–005 (these forms will not change).
Type of Review: Revision of a
currently approved collection of
information.
Respondents/Affected Public: Oil and
gas operators on public lands and some
Indian lands.
Total Estimated Number of Annual
Respondents: 7,500.
Total Estimated Number of Annual
Responses: 33,621.
Estimated Completion Time per
Response: Varies from 4 to 32 hours,
depending on activity.
Total Estimated Number of Annual
Burden Hours: 260,928.
Respondent’s Obligation: Required to
obtain or retain a benefit.
Frequency of Collection: On occasion;
One-time; and Monthly.
Annual Burden Cost: $35,400,000.
2. Changes Impacting OMB Control
Number 1004–0162
Currently, there are 68 annual
responses, 26 annual burden hours, and
$25 annual non-hour cost burdens
inventoried under OMB Control
Number 1004–0162. It is not anticipated
that the final rule will change the results
to the annual responses, annual burden
hours, or non-hour cost burdens under
this OMB Control Number. The revised
information collection requirement is
described as follows.
43 CFR 3151.30—Collection and
submission of data. The final rule adds
a new requirement for the permittee to
provide the BLM with all data and
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information obtained in carrying out the
exploration plan, matching the
requirement for geophysical exploration
permits in Alaska. This does not change
the existing burden for what applicants
to submit to the BLM.
Title of Collection: Onshore
Geophysical Exploration (43 CFR part
3150 and 36 CFR parts 228 and 251).
OMB Control Number: 1004–0162.
Form Number: BLM 3150–4/FS 2800–
16; BLM 3150–5/FS 2816a (these forms
will not change).
Type of Review: Revision of a
currently approved collection of
information.
Respondents/Affected Public: The
respondents for this collection of
information are businesses that seek to
conduct geophysical exploration on
Federal lands.
Respondent’s Obligation: Required to
Obtain or Retain a Benefit.
Frequency of Collection: On occasion.
Estimated Completion Time per
Response: Varies from 20 minutes to 1
hour, depending on activity.
Number of Respondents: 68.
Annual Responses: 68.
Annual Burden Hours: 26.
Annual Burden Cost: $1,150.
3. Changes Impacting OMB Control
Number 1004–0185
Currently, there are 9,132 annual
responses, 37,695 annual burden hours,
and $751,415 annual non-hour cost
burdens inventoried under OMB
Control Number 1004–0185. This final
rule is estimated to result in 16,340
annual responses, 29,410 annual burden
hours, $3,766,184, non-hour cost
burdens under this OMB Control
Number. The final rule will result in
new, revised, and removed information
collection requirements. Additionally,
as discussed earlier, the BLM will also
be transferring certain information
collection requirements, along with the
associated burdens from OMB Control
Number 1004–0034 to OMB Control
Number 1004–0185. These changes are
discussed blow.
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Revised Information Collection
Requirements
43 CFR 3100.31(b)—Option
Enforceability. The final rule revises this
requirement to clarify that a statement
of the number of acres and the type and
percentage of interest to be conveyed
and retained by the parties to the
option. This does not change the burden
requirement. The existing regulation
already states the interest to be
conveyed and retained in exercise of the
option. The BLM needs to understand if
the type of interest is referring to record
title or operating rights and the
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percentage to be conveyed and retained
by the option holder.
43 CFR 3105.21—Where to File
Communitization Agreements. The final
rule removes the triplicate filing
requirement. The final rule adds a new
paragraph (b) to this section to require
that all applications to form a CA be
filed with a statement as to whether the
proposed CA deviates from the BLM’s
current model CA form, and a
certification that the applicant received
the required signatures. Further, all
applications to form a CA shall include
an Exhibit A displaying a map of the
agreement and the separate agreement
tracts and all applications to form a CA
shall include an Exhibit B displaying
the separate tracts and ownership. The
new paragraph (c) states that all
applications to form a CA should be
submitted at least 90 calendar days prior
to first production to ensure correct
reporting to the ONRR. These
requirements codify existing policy
requirements and does not change the
existing burden for what applicants to
submit to the BLM. The information is
needed to understand all the parties that
share in the production of a well due to
State spacing orders.
43 CFR 3105.31—Where filed.
(Operating, Drilling or Development
Contracts). The final rule removes the
requirement for five copies of an
operating, drilling or development
contract to be submitted when these
contracts are submitted to the BLM for
approval. This reduces the burden to
respondents.
43 CFR 3105.41—Where filed.
(Subsurface storage application
(previously, 3105.5)). The final rule
designates the existing 43 CFR 3105.5
for gas storage agreements to the
redesignated 43 CFR 3105.41. This
redesignation is due to the elimination
of the section on the combination for
joint operations or for transportation of
oil. The final rule updates paragraph (a)
to include designation of successor
operators for gas storage agreements
among the applications to be filed in the
proper BLM office. The final rule
updates paragraph (b) to remove the
requirement for five copies of a gas
storage agreement to be submitted when
these are filed with the BLM. A new
paragraph (c) requires that all
applications for a gas storage agreement
or a designation of a successor operator
must include the new processing fee
found in the fee schedule in 43 CFR
3000.120. The new processing fee is
intended to reimburse the BLM for
processing the applications.
43 CFR 3105.50—Consolidation of
Leases (formerly, 3105.6). Leases may be
consolidated upon written request of the
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lessee filed with the proper BLM
identify each lease involved by serial
number and shall explain the factors
that justify the consolidation and
requires that each request for a
consolidation of leases the processing
fee found in the fee schedule in 43 CFR
3000.120. The final rule splits the single
paragraph under this section into
several paragraphs for clarity, however
these are not new requirements and
does not change the existing burden.
43 CFR 3106.81—Heirs and devisees.
The updates this information collection
requirement to state that the lease
interest will be transferred to the heirs,
devisees, executor or administrator of
the estate, as appropriate, upon the
filing of a court order, death certificate,
or other legal document demonstrating
that transferee is to be recognized as the
successor of the deceased. These
requirements codify existing policy
requirements and does not change the
existing burden for what applicants
currently submit to the BLM to show
proof on how the lease interest
transferred to another party.
43 CFR 3106.82—Change of name.
The current regulation requires a notice
of the name change to be accompanied
by a list of the serial numbers of the
leases affected by the name change. This
requirement is removed as it is outdated
and unenforceable. This lessens the
burden to respondents. In practice, the
BLM generates a report of the leases
affected by the name change and returns
that list to the lessee with a notice that
recognizes the name change that
occurred through operation of law. This
section is updated to require that, for a
corporate name change, the request
should include the Secretary of State’s
Certificate of Name Change along with
the Articles of Incorporation, or
Amendment, if available. This is
consistent with the BLM’s current
approach for processing these types of
documents. These requirements codify
existing policy requirements and does
not change the existing burden for what
applicants currently submit to the BLM
to show proof on how the lease interest
transferred to another party.
43 CFR 3106.83—Corporate mergers
and dissolution of corporations,
partnerships and trusts. The final rule
updates the title of this section from
‘‘Corporate merger’’ to ‘‘Corporate
mergers and dissolution of corporations,
partnerships and trust’’. The goal of the
renaming of this section is to
incorporate these other types of
transfers that have the same process.
The current regulation requires a
notification of merger to be
accompanied by a list of the serial
numbers of the leases affected by the
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merger. This requirement is eliminated
as it is outdated and unenforceable. This
lessens the burden to respondents. In
practice, the BLM does not rely on a list
of leases provided by a lessee and
instead generates its own report of the
leases affected by the merger. The BLM
returns that list to the lessee with a
notice that recognizes the merger that
occurred through operation of State law.
This section is updated to require that,
for a merger, the request should include
the Secretary of State’s Certificate of
Merger along with the Articles of
Incorporation, or Amendment, if
available. This is consistent with the
BLM’s current approach for processing
these types of documents. These
requirements codify existing policy
requirements and does not change the
existing burden for what applicants
currently submit to the BLM to show
proof on how the lease interest
transferred to another party.
43 CFR 3108.23—Reinstatement at
higher rental and royalty rates: Class II
reinstatements. The final rule eliminates
the existing paragraph (b)(1) in its
entirety. This provision addresses the
timeliness of Class II reinstatement
petitions for leases that terminated on or
before August 8, 2005, and is no longer
applicable. This does not change an
existing burden since a petition to
reinstate a lease that terminated on or
before August 8, 2005, would have
already been received by an applicant.
43 CFR 3109.12—Application. The
final rule also adds a new requirement
that the applicant must include a map
of the applicable lands which will
support the bidding process related to
the lease or compensatory royalty
agreement. These requirements codify
existing policy requirements and does
not change the existing burden for what
applicants to submit to the BLM.
New Information Collection
Requirements
43 CFR 3106.84—Sheriff’s sale/deed.
The final rule adds a new section under
other types of transfers to include
sheriff’s sales. The BLM accepts these
types of transfers to recognize lease
interests transferred to other parties
through foreclosure actions. The final
rule states that where a notice of sale of
the leasehold interest is published
pursuant to State law applicable to the
execution of sales of real property, the
purchaser shall submit a copy of the
Sheriff’s Certificate of Sale after any
redemption period has passed to the
proper BLM office. Additional
paragraphs under this new section
include a filing fee requirement, a
qualification statement, and bonding
requirements. These requirements are
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consistent with the BLM’s current
approach for processing these types of
documents. These documents are
already submitted and recognized by the
BLM when changes in ownership of
interests in Federal oil and gas leases
occur without any intention by the
holder of interest to assign or transfer
interest. The addition of this
information collection will result in an
addition of 1 annual response, 1 annual
burden hour, and $55.80 annual nonhour cost burdens.
43 CFR 3120.31—Expression of
Interest (EOI) Process. The final rule
adds a new section titled ‘‘Expression of
Interest’’ to codify the current process of
receiving EOIs for competitive leasing to
the BLM’s online leasing system. An
EOI is a description of lands that an
applicant seeks to include in a
competitive auction. The expression
must provide a description of the lands
identified by legal land description and
identify the U.S. mineral ownership
percentage. This information collection
will result in an addition of 395 annual
responses (average of 1,000 acres per
response), 3,160 annual burden hours,
and $1,975,000 annual non-hour cost
burdens (calculated by average acreage
per response).
Removed Information Collection
Requirements
43 CFR 3101.2–6—Ad Hoc Acreage
Statement. At any time, the BLM may
require a lessee or operator to file a
statement showing as of the specified
date, the serial number and the date of
each lease in which the lessee or
operator has any interest, in the
particular State, setting forth the acreage
covered thereby. The BLM uses the
information to determine whether or not
a lessee is in compliance with the law
with respect to statutory acreage
limitations. This revision results in the
reduction of 1 response and 1 burden
hour, annually.
43 CFR 3105.4—Combination for joint
operations or for transportation of oil.
The final rule eliminates the section on
the combination for joint operations or
for transportation of oil. These
provisions are not used by the BLM or
operators and are outdated. This
revision results in the reduction of 1
response and 1 burden hour, annually.
43 CFR 3107.8—Renewal leases. The
final rule eliminates the provisions on
renewal leases in their entirety because
they are outdated. Renewal leases that
had an expiration date after November
15, 1990, were eligible for one last
renewal under the provisions of the
November 15, 1990, Act, i.e., for 10
years, and for so long thereafter as oil
and gas is produced in paying
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30961
quantities. If a lease was renewed after
the 1990 amendment and was not
producing oil or gas at the end of its 10year renewal term, the lease expired
with no further option for renewal. The
removal of this information collection
will result in a reduction of 1 annual
response, 1 annual burden hour, and
$475 annual non-hour cost burdens.
Class III reinstatement petition (43
CFR 3108.2–4). The requirement is
removed from the final rule resulting in
a reduction of one annual response and
one burden hour as well as $651 in nonhour cost burden.
Information Collection Requirements
Transferred From OMB Control Number
1004–0034
The following two information
collections will be moved into OMB
Control Number 1004–0185 to keep
information collection requirements in
subpart 3106 under the same OMB
Control Number:
1. 43 CFR 3106.41, Transfers of record
title and of operating rights (subleases)
and 3106.42, Transfers of other
interests, including royalty interests and
production payments. This transfer will
result in 3,852 annual responses, 1,926
annual burden hours, and $404,460
non-hours cost burdens being added to
this OMB Control Number.
2. 43 CFR 3106.43 Mass transfers.
This transfer will result in 4,944 annual
responses, 2,472 annual burden hours,
and $519,120 non-hours cost burdens
being added to this OMB Control
Number.
The resulting new estimated total
burdens for OMB Control Number
1004–0185 are provided as follows.
Title of Collection: Onshore Oil and
Gas Leasing, and Drainage Protection
(43 CFR parts 3100, 3120, and 3150, and
subpart 3162).
OMB Control Number: 1004–0185.
Form Number: None.
Type of Review: Revision of a
currently approved collection of
information.
Respondents/Affected Public: Holders
of onshore oil and gas lease and public
lands and Indian lands (except on the
Osage Reservation), operators of such
leases, and holders of operating rights
on such leases.
Respondent’s Obligation: Required to
Obtain or Retain a Benefit.
Frequency of Collection: Varies from 1
hour to 24 hours per response,
depending on activity.
Number of Respondents: 16,339.
Annual Responses: 16,340.
Annual Burden Hours: 29,410.
Annual Burden Cost: $3,766,184.
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4. Changes Impacting OMB Control
Number 1004–0196
Currently, there are there are 21
annual responses and 220 annual
burden hours associated with this OMB
control number. There are also no nonhours cost burden currently associated
with this OMB control number. The
final rule is not projected to result in
any new annual responses. The
additional requirements in 43 CFR
3170.80(b) include description of the
anticipated PA(s) size and define the
proposed PAs in the unit designation
agreements required by 43 CFR 3137.21,
and 3137.23 is not projected to result in
additional burden for that information
collection.
43 CFR 3000.120 introduces new
filing fees for the following information
collections, resulting in a new total
estimated annual non-hour burden cost
of $1,320;
• $120 for Statement of change of unit
operator (43 CFR 3137.61); and
• $1,200 for Application for storage
agreement (43 CFR 3138.11);
Additionally, the existing 43 CFR
3137.86, New information
demonstrating that the participating
area should be larger or smaller than
previously determined, contains the
following three information collection
requirements for which the burden has
not been previously captured in this
OMB control number:
• Information demonstrating that a
participating area should be larger than
previously determined (43 CFR
3137.86(a)(1));
• Application to enlarge participating
area outside of existing boundaries (43
CFR 3137.86(a)(2)); and
• Statement for additional committed
tract or tracts are added to the unit
under paragraph (a)(2) (43 CFR
3137.86(a)(3)).
The resulting new estimated total
burdens for OMB Control Number
1004–0196 are provided as follows.
Title of Collection: Oil and Gas
Leasing: National Petroleum Reserve—
Alaska (43 CFR part 3130).
OMB Control Number: 1004–0196.
Form Number: None.
Type of Review: Revision of a
currently approved collection of
information.
Respondents/Affected Public:
Participants within the oil and gas
leasing program within the National
Petroleum Reserve—Alaska.
Respondent’s Obligation: Required to
Obtain or Retain a Benefit.
Frequency of Collection: On occasion.
Estimated Completion Time per
Response: Varies from 15 minutes to 80
hours, depending on activity.
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Number of Respondents: 24.
Annual Responses: 24.
Annual Burden Hours: 223.
Annual Burden Cost: $1,320.
If you want to comment on the
information-collection requirements in
this rule, please send your comments
and suggestions on this informationcollection request within 30 days of
publication of this final rule in the
Federal Register to OMB at
www.reginfo.gov. Click on the link,
‘‘Currently under Review—Open for
Public Comments.’’
J. National Environmental Policy Act
The BLM received comments on this
section. One commenter stated the BLM
properly issues the rule pursuant to a
categorical exclusion. Other comments
recommended that the BLM use an
environmental assessment for the rule.
Commenters stated the rule affects
decisions in RMPs, because the
preference criteria would guide the
BLM’s decision making and direct oil
and gas leasing to appropriate locations.
Another commenter stated that the
economic burden that the proposed rule
would cause for oil and gas operators
and State economies would require the
BLM to perform a NEPA analysis on the
portions of the proposed rule that are
beyond the scope of changes required by
Congress in the IRA. As previously
stated, this rule does not close
additional lands for oil and gas leasing
and the MLA has vested the Secretary
with broad discretion to decide, up until
the time of lease issuance, whether
particular parcels of Federal land ‘‘may
be leased’’ for oil and gas development,
see 30 U.S.C. 226(a). The BLM
completed an RIA and an extraordinary
circumstances review and determined
that the BLM can issue this rule under
the applicable Departmental categorical
exclusion.
A detailed environmental analysis
under NEPA is not required, because the
final rule is covered by a categorical
exclusion (see 43 CFR 46.205). This
final rule meets the criteria set forth at
43 CFR 46.210(i) for a Departmental
categorical exclusion in that this final
rule is ‘‘of an administrative, financial,
legal, technical, or procedural nature.’’
The BLM also has determined that the
final rule does not involve any of the
extraordinary circumstances listed in 43
CFR 46.215 that would require further
analysis under NEPA.
K. Actions Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use (E.O. 13211)
Under E.O. 13211, agencies are
required to prepare and submit to OMB
a Statement of Energy Effects for
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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 E.O. 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 E.O. 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 OIRA as a
significant energy action.’’
The BLM believes that the final rule
may affect the locations that operators
choose for future oil or gas development
but will have little impact on an entity’s
decision to invest in energy
development, the size of that
development, or the production from
that development. As a result of this
rule, an entity holding existing
nonproducing leases may choose to shift
more future development to those
existing leases or to develop nonFederal acreage instead of securing new
Federal leases, and some entities may be
relatively less likely to choose a new
Federal lease to a comparable nonFederal lease. Also, any incremental
changes in oil or gas production
estimated to result from the rule’s
enactment would constitute a small
fraction of total U.S. gas production, and
any potential and temporary deferred
production of oil would likewise
constitute a small fraction of total U.S.
oil production. Some commenters
disagreed and pointed to the preference
criteria as increasing the risk for
litigation, which could shift
development off Federal land and
increase the cost to produce gas or oil.
The BLM disagrees. The preference
criteria under § 3120.32 support the
BLM’s existing policy and direction to
make a public interest determination,
which has existed at least since 1988.
See 53 FR 22828 (June 17, 1988) (‘‘It is
Bureau policy prior to offering the lands
to determine whether leasing will be in
the public interest and to identify
stipulation requirements, obtain surface
management agency leasing
recommendations and consent where
applicable and required by law’’). It will
not have the impact stated in these
comments. For these reasons, we do not
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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 E.O. 13211.
VI. Authors
The principal authors of this final rule
include: Peter Cowan, Senior Mineral
Leasing Specialist in BLM Headquarters;
Jennifer Spencer, Mineral Leasing
Specialist in BLM Headquarters;
William Lambert, Petroleum Engineer in
BLM Headquarters; Natalie Eades,
Attorney Advisor in DOI Office of the
Solicitor. Technical support provided
by: Scott Rickard, Economist in BLM
Headquarters; Travis Kern, Program
Analyst in BLM Headquarters; and Erik
Vernon, Air Resources Program Lead in
BLM Utah State Office. Assisted by:
Duane Spencer, Deputy State Director of
Minerals and Land in BLM Wyoming
State Office; JulieAnn Serrano,
Supervisory Land Law Examiner in
BLM New Mexico State Office; and
Darrin King, Senior Regulatory Analyst
in BLM Headquarters.
List of Subjects
43 CFR Part 3000
Public lands-mineral resources,
Reporting and recordkeeping
requirements.
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 3110
Government contracts, Oil and gas
exploration, Public lands-mineral
resources, Reporting and recordkeeping
requirements.
43 CFR Part 3120
Government contracts, Oil and gas
exploration, Public lands-mineral
resources, Reporting and recordkeeping
requirements.
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43 CFR Part 3130
Alaska, Government contracts,
Mineral royalties, Oil and gas
exploration, Oil and gas reserves, Public
lands-mineral resources, Reporting and
recordkeeping requirements, Surety
bonds.
§ 3000.5
43 CFR Part 3150
Administrative practice and
procedure, Alaska, Oil and gas
exploration, 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 landsmineral resources, Reporting and
recordkeeping requirements.
43 CFR Part 3170
Administrative practice and
procedure, Flaring, Immediate
assessments, Indians-lands, Mineral
royalties, Oil and gas exploration, Oil
and gas measurement, Public landsmineral resources, Reporting and record
keeping requirements, Royalty-free use,
Venting.
43 CFR Part 3180
Government contracts, Mineral
royalties, Oil and gas exploration,
Public lands-mineral resources,
Reporting and recordkeeping
requirements.
For the reasons set out in the
preamble, the Bureau of Land
Management amends 43 CFR parts 3000,
3100, 3110, 3120, 3130, 3140, 3150,
3160, 3170, and 3180 as follows:
■
1. Revise part 3000 to read as follows:
PART 3000—MINERALS
MANAGEMENT: GENERAL
Sec.
3000.5 Definitions.
3000.10 Nondiscrimination.
3000.20 False statements.
3000.30 Unlawful interests.
3000.40 Appeals.
3000.41 Severability.
3000.50 Limitations on time to institute suit
to challenge a decision of the Secretary.
3000.60 Filing of documents.
3000.70 Multiple development.
3000.80 Management of Federal minerals
from reserved mineral estates.
3000.90 Enforcement actions under the
United States Code.
3000.100 Fees in general.
3000.110 Processing fees on a case-by-case
basis.
3000.120 Fee schedule for fixed fees.
43 CFR Part 3140
PART 3000—MINERALS
MANAGEMENT: GENERAL
Government contracts, Hydrocarbons,
Mineral royalties, Oil and gas
exploration, Public lands-mineral
resources, Reporting and recordkeeping
requirements.
Authority: 16 U.S.C. 3101 et seq.; 30
U.S.C. 181 et seq., 301–306, 351–359, and
601 et seq.; 31 U.S.C. 9701; 40 U.S.C. 471 et
seq.; 42 U.S.C. 6508; 43 U.S.C. 1701 et seq.;
and Pub. L. 97–35, 95 Stat. 357.
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30963
Definitions.
As used in 43 CFR parts 3000 and
3100, the term:
Acquired lands means lands which
the United States obtained by deed
through purchase or gift, or through
condemnation proceedings, including
lands previously disposed of under the
public land laws including the mining
laws.
Acreage for which expressions of
interest have been submitted means
acreage that is identified in an
expression of interest received by the
BLM, that has not been proposed for
leasing in any pending sale or other
expression of interest pending BLM
disposition, and for which the BLM may
lawfully issue an oil and gas lease.
Acres offered for lease means all acres
that the BLM has offered for oil and gas
lease, regardless of whether those acres
are acreage for which expressions of
interest have been submitted.
Act or MLA means the Mineral
Leasing Act of 1920, as amended and
supplemented (30 U.S.C. 181 et seq.).
Anniversary date means the same day
and month in succeeding years as that
on which the lease became effective.
Authorized officer means any BLM
employee authorized to perform the
duties described in parts 3000 and 3100.
BLM or Bureau means the Bureau of
Land Management.
Director means the Director of the
Bureau of Land Management.
Gas means any fluid, either
combustible or noncombustible, which
is produced in a natural state from the
earth and which maintains a gaseous or
rarefied state at ordinary temperatures
and pressure conditions.
Interest means ownership in a lease,
or prospective lease, of all or a portion
of the record title, working interest,
operating rights, overriding royalty,
payments out of production, carried
interests, net profit share or similar
instrument for participation in the
benefit derived from a lease. An interest
may be created by direct or indirect
ownership, including options. Interest
does not mean stock ownership,
stockholding or stock control in an
application, offer, competitive bid or
lease, except for purposes of acreage
limitations in 43 CFR 3101.20 and
qualifications of lessees in 43 CFR
subpart 3102.
Oil means all nongaseous
hydrocarbon substances other than
those substances leasable as coal, oil
shale or gilsonite (including all veintype solid hydrocarbons).
ONRR means the Office of Natural
Resources Revenue.
Party in interest means a party who is
or will be vested with any interest under
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the lease as defined in this section. No
one is a sole party in interest with
respect to an application, offer,
competitive bid or lease in which any
other party has an interest.
Person means any individual, firm,
corporation, association, partnership,
consortium, or joint venture.
Proper BLM office means the Bureau
of Land Management state office having
jurisdiction over the lands subject to the
regulations in parts 3000 and 3100.
(See 43 CFR 1821.10 for office
location and area of jurisdiction of
Bureau of Land Management offices.)
Properly filed means a document or
form submitted to the proper BLM office
with all necessary information and
payments, as provided in 43 CFR
subpart 1822.
Public domain lands means lands,
including mineral estates, which never
left the ownership of the United States,
lands which were obtained by the
United States in exchange for public
domain lands, lands which have
reverted to the ownership of the United
States through the operation of the
public land laws and other lands
specifically identified by the Congress
as part of the public domain.
Secretary means the Secretary of the
Interior.
Surface managing agency means any
Federal agency, other than the BLM,
having management responsibility for
the surface resources that overlay
federally owned minerals.
§ 3000.10
Nondiscrimination.
Any person acquiring a lease under
this chapter must comply fully with the
equal opportunity provisions of
Executive Order 11246 dated September
24, 1965, as amended, and the rules,
regulations and relevant orders of the
Secretary of Labor (41 CFR part 60 and
43 CFR part 17).
§ 3000.20
False statements.
As provided in 18 U.S.C. 1001, it is
a crime punishable by imprisonment or
a fine, or both, for any person
knowingly and willfully to submit or
cause to be submitted to any agency of
the United States any false or fraudulent
statement(s) as to any matter within the
agency’s jurisdiction.
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§ 3000.30
Unlawful interests.
No member of, or delegate to,
Congress, or Resident Commissioner,
and no employee of the Department of
the Interior, except as provided in 43
CFR part 20, is allowed or entitled to
acquire or hold any Federal lease, or
interest therein. (Officer, agent or
employee of the Department—see 43
CFR part 20; Member of Congress—see
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R.S. 3741; 41 U.S.C. 22; 18 U.S.C. 431–
433.)
§ 3000.40
Appeals.
Except as provided in 43 CFR
3000.120, 3101.53(b), 3103.1, 3165.4,
and 3427.2, any party adversely affected
by a decision of the authorized officer
made pursuant to the provisions of 43
CFR parts 3000 or 3100 has a right of
appeal pursuant to 43 CFR part 4.
§ 3000.41
Severability.
If a court holds any section or its
paragraphs of the regulations in parts
3000 through 3180 or their applicability
to any person or circumstance invalid,
the remainder of these rules and their
applicability to other persons or
circumstances will not be affected.
§ 3000.50 Limitations on time to institute
suit to challenge a decision of the
Secretary.
No action challenging a decision of
the Secretary involving any oil or gas
lease (including decisions on offers or
applications to lease) can be maintained
unless such action is commenced or
taken within 90 days after the final
decision of the Secretary relating to
such matter.
§ 3000.60
Filing of documents.
All necessary documents must be
filed in the proper BLM office.
Documents may be submitted to the
BLM using hard-copy delivery services,
in-person delivery, or by electronic
filing. When using hard-copy delivery
services or in-person delivery, the
document will be considered filed only
when received during regular business
hours in the proper BLM office. See 43
CFR part 1820, subpart 1822.
§ 3000.70
Multiple development.
The granting of a permit or lease for
the prospecting, development or
production of deposits of any one
mineral does not preclude the issuance
of other permits or leases for the same
lands for deposits of other minerals with
suitable stipulations for simultaneous
operation, nor the allowance of
applicable entries, locations or
selections of leased lands with a
reservation of the mineral deposits to
the United States.
§ 3000.80 Management of Federal minerals
from reserved mineral estates.
Where nonmineral public land
disposal statutes provide that in
conveyances of title all or certain
minerals are reserved to the United
States together with the right to prospect
for, mine and remove the minerals
under applicable law and regulations as
the Secretary may prescribe, the lease or
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sale, and administration and
management of the use of such minerals
will be accomplished under the
regulations of 43 CFR parts 3000 and
3100. Such mineral estates include, but
are not limited to, those that have been
or will be reserved under the authorities
of the Small Tract Act of June 1, 1938,
as amended (43 U.S.C. 682(b)) and the
Federal Land Policy and Management
Act of 1976 (43 U.S.C. 1701 et seq.).
§ 3000.90 Enforcement actions under the
United States Code.
The United States Department of
Justice is the agency responsible for the
enforcement actions described in 30
U.S.C. 195, which makes it unlawful for
any person to organize or participate in
any scheme, arrangement, plan, or
agreement to circumvent or defeat the
provisions of the MLA or its
implementing regulations; or to seek to
obtain or to obtain any money or
property by means of false statements of
material facts or by failing to state
materials facts concerning the:
(a) Value of any lease or portion
thereof issued or to be issued under the
MLA;
(b) Availability of any land for leasing
under the MLA;
(c) Ability of any person to obtain
leases under the MLA; or
(d) Provisions of the MLA and its
implementing regulations.
§ 3000.100
Fees in general.
(a) Setting fees. Fees may be
statutorily set fees, relatively nominal
filing fees, or processing fees intended
to reimburse the BLM for its reasonable
processing costs. For processing fees,
the BLM takes into account the factors
in section 304(b) of the Federal Land
Policy and Management Act of 1976
(FLPMA) (43 U.S.C. 1734(b)) before
deciding a fee. The BLM considers the
factors for each type of document when
the processing fee is a fixed fee and for
each individual document when the fee
is decided on a case-by-case basis, as
explained in § 3000.110.
(b) Conditions for filing. The BLM will
not accept a document that the
applicant submits without the proper
filing or processing fee amounts except
for documents where the BLM sets the
fee on a case-by-case basis. Fees are not
refundable except as provided for caseby-case fees in § 3000.110. The BLM
will keep the fixed filing or processing
fee as a service charge even if the BLM
does not approve the application or the
applicant withdraws it completely or
partially.
(c) Periodic adjustment. The BLM will
periodically adjust fees established in
this subchapter according to changes in
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the Implicit Price Deflator for Gross
Domestic Product, which is published
quarterly by the U.S. Department of
Commerce. Because the fee
recalculations are simply based on a
mathematical formula, the BLM will
change the fees in final rules without
opportunity for notice and comment.
(d) Timing of fee applicability. (1) For
a document that the BLM received
before June 22, 2024, the BLM will not
charge a fixed fee or a case-by-case fee
under this subchapter for processing
that document, except for fees
applicable under then-existing
regulations.
(2) For a document that the BLM
receives on or after June 22, 2024, the
applicant must include the required
fixed fees with the documents filed, as
provided in § 3000.120(a) of this
chapter, and the applicant is subject to
case-by-case processing fees as provided
in § 3000.110 and under other
provisions of this chapter.
§ 3000.110 Processing fees on a case-bycase basis.
(a) Fees in this subchapter are
designated either as case-by-case fees or
as fixed fees. The fixed fees are
established in this subchapter for
specified types of documents. However,
if the BLM decides at any time that a
particular document designated for a
fixed fee will have a unique processing
cost, such as the preparation of an
Environmental Impact Statement, the
BLM may set the fee under the case-bycase procedures in this section.
(b) For case-by-case fees, the BLM
measures the ongoing processing cost
for each individual document and
considers the factors in section 304(b) of
FLPMA on a case-by-case basis
according to the following procedures:
(1) The applicant may request the
BLM’s approval to do all or part of any
study or other activity according to
standards the BLM specifies, thereby
reducing the BLM’s costs for processing
the document, in accordance with all
other applicable laws and regulations.
(2) Before performing any case
processing, the BLM will give the
applicant a written estimate of the
proposed fee for reasonable processing
costs after the BLM considers the
FLPMA section 304(b) factors.
(3) The applicant may comment on
the proposed fee.
(4) The BLM will then give the
applicant the final estimate of the
processing fee amount after considering
the applicant’s comments and any BLMapproved work that the applicant will
do.
(i) If the BLM encounters higher or
lower processing costs than anticipated,
the BLM will re-estimate the reasonable
processing costs following the
procedure in paragraphs (b)(1) through
(4) of this section, but the BLM will not
stop ongoing processing unless the
applicant does not pay in accordance
with paragraph (b)(5) of this section.
(ii) If the fee the applicant would pay
under this paragraph (b)(4) is less than
the BLM’s actual costs as a result of
consideration of the FLPMA section
304(b) factors, and the BLM is not able
to process the document promptly
because of the unavailability of funding
or other resources, the applicant will
have the option to pay the BLM’s actual
costs to process the document.
(iii) Once processing is complete, the
BLM will refund to the applicant any
money that the BLM did not spend on
processing costs.
(5)(i) The BLM will periodically
estimate what its reasonable processing
costs will be for a specific period and
will bill the applicant for that period.
Payment is due to the BLM 30 days after
the applicant receives its bill. The BLM
will stop processing the document if the
applicant does not pay the bill by the
date payment is due.
30965
(ii) If a periodic payment turns out to
be more or less than the BLM’s
reasonable processing costs for the
period, the BLM will adjust the next
billing accordingly or make a refund. Do
not deduct any amount from a payment
without the BLM’s prior written
approval.
(6) The applicant must pay the entire
fee before the BLM will issue the final
document.
(7) The applicant may appeal the
BLM’s estimated processing costs in
accordance with the regulations in 43
CFR part 4, subpart E. The applicant
may also appeal any determination the
BLM makes under paragraph (a) of this
section that a document designated for
a fixed fee will be processed as a caseby-case fee. The BLM will not process
the document further until the appeal is
resolved, in accordance with paragraph
(b)(5)(i) of this section, unless the
applicant pays the fee under protest
while the appeal is pending. If the
appeal results in a decision changing
the proposed fee, the BLM will adjust
the fee in accordance with paragraph
(b)(5)(ii) of this section.
§ 3000.120
Fee schedule for fixed fees.
(a) The table in this section lists the
services that require payment of fixed
fees to the BLM. The fixed fee amounts
are posted on the BLM website (https://
www.blm.gov) and published in a
Federal Register notice. These fees are
nonrefundable and must be included
with documents filed under this
chapter. Fees will be adjusted annually
according to the change in the Implicit
Price Deflator for Gross Domestic
Product since the previous adjustment
and will subsequently be posted on the
BLM website (https://www.blm.gov) and
announced annually in the Federal
Register before October 1 each year.
Revised fees are effective each year on
October 1.
TABLE 1 TO PARAGRAPH (a)—PROCESSING AND FILING FEE TABLE
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Document/action
Oil & Gas (parts 3100, 3110, 3120, 3130, 3150, 3160, and 3180):
Competitive lease application
Leasing and compensatory royalty agreements under right-of-way pursuant to subpart 3109.
Lease consolidation
Assignment and transfer of record title or operating rights
Overriding royalty transfer, payment out of production
Name change; corporate merger; sheriff’s deed; dissolution of corporation, partnership, or trust; or transfer to heir/devisee
Lease reinstatement, Class I
Geophysical exploration permit application—all states
Renewal of exploration permit—Alaska
Final application for Federal unit agreement approval, Federal unit agreement expansion, and Federal subsurface gas storage application
Designation of successor operator for all Federal agreements, except for contracted unit agreements that contain no Federal lands.
Geothermal (part 3200):
Noncompetitive lease application
Competitive lease application
Assignment and transfer of record title or operating rights
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TABLE 1 TO PARAGRAPH (a)—PROCESSING AND FILING FEE TABLE—Continued
Document/action
Name change, corporate merger or transfer to heir/devisee
Lease consolidation
Lease reinstatement
Nomination of lands
plus per acre nomination fee
Site license application
Assignment or transfer of site license
Coal (parts 3400, 3470):
License to mine application
Exploration license application
Lease or lease interest transfer
Leasing of Solid Minerals Other Than Coal and Oil Shale (parts 3500, 3580):
Applications other than those listed below
Prospecting permit application amendment
Extension of prospecting permit
Lease modification or fringe acreage lease
Lease renewal
Assignment, sublease, or transfer of operating rights
Transfer of overriding royalty
Use permit
Shasta and Trinity hardrock mineral lease
Renewal of existing sand and gravel lease in Nevada
Public Law 359; Mining in Powersite Withdrawals: General (part 3730):
Notice of protest of placer mining operations
Mining Law Administration (parts 3800, 3810, 3830, 3860, 3870):
Application to open lands to location
Notice of location *
Amendment of location
Transfer of mining claim/site
Recording an annual FLPMA filing
Deferment of assessment work
Recording a notice of intent to locate mining claims on Stockraising Homestead Act lands
Mineral patent adjudication
Adverse claim
Protest
Oil Shale Management (parts 3900, 3910, 3930):
Exploration license application
Application for assignment or sublease of record title or overriding royalty
Onshore Oil and Gas Operations and Production (parts 3160, 3170):
Application for Permit to Drill
* To record a mining claim or site location, this processing fee along with the initial maintenance fee and the one-time location fee required by
statute 43 CFR part 3833 must be paid.
(b) The amount of a fixed fee is not
subject to appeal to the Interior Board of
Land Appeals pursuant to 43 CFR part
4, subpart E.
■
2. Revise part 3100 to read as follows:
PART 3100—OIL AND GAS LEASING
Subpart 3100—Oil and Gas Leasing:
General
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Drainage
3100.21 Compensation for drainage.
3100.22 Drilling and production or
payment of compensatory royalty.
Enforceability.
Effect of option on acreage.
Option statements.
Public availability of information.
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Lease Terms and Conditions
3101.11 Lease form.
3101.12 Surface use rights.
3101.13 Stipulations and information
notices.
3101.14 Modification, waiver, or exception.
Acreage Limitations
Sec.
3100.3 Authority.
3100.5 Definitions.
3100.9 Information collection.
3100.10 Helium.
Options
3100.31
3100.32
3100.33
3100.40
Subpart 3101—Issuance of Leases
3101.60 State’s or charitable organization’s
ownership of surface overlying federally
owned minerals.
Subpart 3102—Qualifications of Lessees
3102.10
3102.20
3102.30
3102.40
Who may hold leases.
Non-U.S. Citizens.
Minors.
Signature.
3101.21 Public domain lands.
3101.22 Acquired lands.
3101.23 Excepted acreage.
3101.24 Excess acreage.
3101.25 Computation.
3101.30 Leases within unit areas, joinder
evidence required.
3101.40 Terminated leases.
Compliance, Certification of Compliance and
Evidence
Federal Lands Administered by an Agency
Other Than the Bureau of Land Management
Payments
3101.51 General requirements.
3101.52 Action by the Bureau of Land
Management.
3101.53 Appeals.
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3102.51
3102.52
3102.53
Compliance.
Certification of compliance.
Evidence of compliance.
Subpart 3103—Fees, Rentals, and Royalty
3103.1
Fiscal terms.
3103.11
3103.12
Form of remittance.
Where remittance is submitted.
Rentals
3103.21
3103.22
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Rental requirements.
Annual rental payments.
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3106.84
Royalties
3103.31 Royalty on production.
3103.32 Minimum royalties.
Production Incentives
3103.41 Royalty reductions.
3103.42 Suspension of operations and/or
production.
Subpart 3104—Bonds
3104.1 Bond amounts.
3104.10 Bond obligations.
3104.20 Lease bond.
3104.30 Statewide bonds.
3104.40 Surface owner protection bond.
3104.50 Increased amount of bonds.
3104.60 Where filed and number of copies.
3104.70 Default.
3104.80 Termination of period of liability.
3104.90 Unit operator and nationwide
bonds held prior to June 22, 2024.
Subpart 3105—Cooperative Conservation
Provisions
3105.10 Cooperative or unit agreement.
Communitization Agreements
3105.21 Where filed.
3105.22 Purpose.
3105.23 Requirements.
3105.24 Communitization agreement terms.
Operating, Drilling, or Development
Contracts
3105.31 Where filed.
3105.32 Purpose.
3105.33 Requirements.
Subsurface Storage of Oil and Gas
3105.41 Where filed.
3105.42 Purpose.
3105.43 Requirements.
3105.44 Extension of lease term.
3105.50 Consolidation of leases.
Subpart 3106—Transfers by Assignment,
Sublease, or Otherwise
3106.10 Transfers, general.
3106.20 Qualifications of assignees and
transferees.
3106.30 Fees.
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Forms
3106.41 Transfers of record title and of
operating rights (subleases).
3106.42 Transfers of other interests,
including royalty interests and
production payments.
3106.43 Mass transfers.
3106.50 Description of lands.
3106.60 Bond requirements.
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Extension of Leases Within Agreements
3107.31 Leases committed to an agreement.
3107.32 Segregation of leases committed in
part.
3107.40 Extension by elimination.
Extension of Leases Segregated by
Assignment
3107.51 Extension after discovery on other
segregated portions.
3107.52 Undeveloped parts of leases in
their extended term.
3107.53 Undeveloped parts of producing
leases.
3107.60 Extension of reinstated leases.
Other Extension Types
3107.71 Payment of compensatory royalty.
3107.72 Subsurface storage of oil and gas.
Subpart 3108—Relinquishment,
Termination, Cancellation
3108.10 Relinquishment.
Termination by Operation of Law and
Reinstatement
3108.21 Automatic termination.
3108.22 Reinstatement at existing rental
and royalty rates: Class I reinstatements.
3108.23 Reinstatement at higher rental and
royalty rates: Class II reinstatements.
3108.30 Cancellation.
3108.40 Bona fide purchasers.
3108.50 Waiver or suspension of lease
rights.
Subpart 3109—Leasing Under Special Acts
Rights-of-Way
3109.11 Generally.
3109.12 Application.
3109.13 Notice.
3109.14 Award of lease or compensatory
royalty agreement.
3109.15 Compensatory royalty agreement or
lease.
3109.20 Units of the National Park System.
3109.30 Shasta and Trinity Units of the
Whiskeytown-Shasta-Trinity National
Recreation Area.
Subpart 3100—Onshore Oil and Gas
Leasing: General
§ 3100.3
Other Types of Transfers
3106.81 Heirs and devisees.
3106.82 Change of name.
3106.83 Corporate mergers and dissolution
of corporations, partnerships, and trusts.
19:33 Apr 22, 2024
Production
3107.21 Continuation by production.
3107.22 Cessation of production.
3107.23 Leases capable of production.
Authority: 25 U.S.C. 396d and 2107; 30
U.S.C. 189, 306, 359, and 1751; 43 U.S.C.
1701 et seq.; and 42 U.S.C. 15801.
Approval of Transfer or Assignment
3106.71 Failure to qualify.
3106.72 Continuing obligation of an
assignor or transferor.
3106.73 Lease account status.
3106.74 Effective date of transfer.
3106.75 Effect of transfer.
3106.76 Obligations of assignee or
transferee.
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Sheriff’s sale/deed.
Subpart 3107—Continuation and Extension
3107.10 Extension by drilling.
Authority.
(a)(1) Public domain. Oil and gas in
public domain lands and lands returned
to the public domain under 43 CFR part
2370 are subject to lease under the
Mineral Leasing Act of 1920, as
amended and supplemented (30 U.S.C.
181 et seq.), by acts, including, but not
limited to, section 1009 of the Alaska
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National Interest Lands Conservation
Act (16 U.S.C. 3148).
(2) Exceptions. The following lands
are not subject to lease.
(i) Units of the National Park System,
including lands withdrawn by section
206 of the Alaska National Interest
Lands Conservation Act, except as
provided in paragraph (g)(4) of this
section;
(ii) Indian reservations;
(iii) Incorporated cities, towns and
villages;
(iv) Naval petroleum and oil shale
reserves;
(v) Lands north of 68 degrees north
latitude and east of the western
boundary of the National Petroleum
Reserve—Alaska;
(vi) Lands recommended for
wilderness allocation by the surface
managing agency;
(vii) Lands within the BLM’s
wilderness study areas;
(viii) Lands designated by Congress as
wilderness study areas, except where oil
and gas leasing is specifically allowed to
continue by the statute designating the
study area;
(ix) Lands within areas allocated for
wilderness or further planning in
Executive Communication 1504, NinetySixth Congress (House Document
numbered 96–119), unless such lands
are allocated to uses other than
wilderness by a land and resource
management plan or have been released
to uses other than wilderness by an Act
of Congress;
(x) Lands within the National
Wilderness Preservation System, subject
to valid existing rights under section
4(d)(3) of the Wilderness Act (16 U.S.C.
1133) established before midnight,
December 31, 1983, unless otherwise
provided by law;
(xi) Subject to valid existing rights,
lands within the National Wild and
Scenic Rivers System and that
constitute the bed or bank or are
situated within one-quarter mile of the
bank of any river designated as a wild
river under the Wild and Scenic Rivers
Act (16 U.S.C. 1280), lands within the
National Wild and Scenic Rivers System
that constitute the bed or bank or are
situated within one-quarter mile of the
bank of certain rivers designated as
scenic or recreational, and in some
cases, designating legislation may apply
a different boundary extent. Lands
within the National Wild and Scenic
Rivers System that constitute the bed or
bank or are situated within one-half
mile of the bank of any river designated
a wild river by the Alaska National
Interest Lands Conservation Act (16
U.S.C. 3148); and
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(xii) Wildlife refuge lands, which are
those lands embraced in a withdrawal of
lands of the United States for the
protection of all species of wildlife
within a particular area. Sole and
complete jurisdiction over such lands
for wildlife conservation purposes is
vested in the Fish and Wildlife Service
even though such lands may be subject
to prior rights for other public purposes
or, by the terms of the withdrawal order,
may be subject to mineral leasing. No
expressions of interest covering wildlife
refuge lands will be considered for oil
and gas leasing, except as provided by
applicable law.
(b)(1) Acquired lands. Oil and gas in
acquired lands are subject to lease under
the Mineral Leasing Act for Acquired
Lands of August 7, 1947, as amended
(30 U.S.C. 351 et seq.).
(2) Exceptions. The following lands
are not subject to lease.
(i) Units of the National Park System,
except as provided in paragraph (g)(4) of
this section;
(ii) Incorporated cities, towns and
villages;
(iii) Naval petroleum and oil shale
reserves;
(iv) Tidelands or submerged coastal
lands within the continental shelf
adjacent or littoral to lands within the
jurisdiction of the United States;
(v) Lands acquired by the United
States for development of helium,
fissionable material deposits or other
minerals essential to the defense of the
country, except oil, gas and other
minerals subject to leasing under the
Act;
(vi) Lands reported as excess under
the Federal Property and Administrative
Services Act of 1949;
(vii) Lands acquired by the United
States by foreclosure or otherwise for
resale;
(viii) Lands recommended for
wilderness allocation by the surface
managing agency;
(ix) Lands within the BLM’s
wilderness study areas;
(x) Lands designated by Congress as
wilderness study areas, except where oil
and gas leasing is specifically allowed to
continue by the statute designating the
study area;
(xi) Lands within areas allocated for
wilderness or further planning in
Executive Communication 1504, NinetySixth Congress (House Document
numbered 96–119), unless such lands
are allocated to uses other than
wilderness by a land and resource
management plan or have been released
to uses other than wilderness by an Act
of Congress;
(xii) Lands within the National
Wilderness Preservation System, subject
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to valid existing rights under section
4(d)(3) of the Wilderness Act (16 U.S.C.
1133) established before midnight,
December 31, 1983, unless otherwise
provided by law;
(xiii) Subject to valid existing rights,
lands within the National Wild and
Scenic Rivers System and that
constitute the bed or bank or are
situated within one-quarter mile of the
bank of any river designated as a wild
river under the Wild and Scenic Rivers
Act (16 U.S.C. 1280), lands within the
National Wild and Scenic Rivers System
that constitute the bed or bank or are
situated within one-quarter mile of the
bank of certain rivers designated as
scenic or recreational, and in some
cases, designating legislation may apply
a different boundary extent. Lands
within the National Wild and Scenic
Rivers System that constitute the bed or
bank or are situated within one-half
mile of the bank of any river designated
a wild river by the Alaska National
Interest Lands Conservation Act (16
U.S.C. 3148); and
(xiv) Wildlife refuge lands, which are
those lands embraced in a withdrawal of
lands of the United States for the
protection of all species of wildlife
within a particular area. Sole and
complete jurisdiction over such lands
for wildlife conservation purposes is
vested in the Fish and Wildlife Service
even though such lands may be subject
to prior rights for other public purposes
or, by the terms of the withdrawal order,
may be subject to mineral leasing. No
expressions of interest for wildlife
refuge lands will be considered except
as provided in applicable law.
(c) National Petroleum Reserve—
Alaska is subject to lease under the
Department of the Interior
Appropriations Act, Fiscal Year 1981
(42 U.S.C. 6508).
(d) Where oil or gas is being drained
from lands otherwise unavailable for
leasing, there is implied authority in the
agency having jurisdiction of those
lands to grant authority to the BLM to
lease such lands (see 43 U.S.C. 1457;
also Attorney General’s Opinion of
April 2, 1941 (Vol. 40 Op. Atty. Gen.
41)).
(e) Where lands previously
withdrawn or reserved from the public
domain are no longer needed by the
agency for which the lands were
withdrawn or reserved and such lands
are retained by the General Services
Administration, or where acquired
lands are declared as excess to or
surplus by the General Services
Administration, authority to lease such
lands may be transferred to the
Department in accordance with the
Federal Property and Administrative
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Services Act of 1949 and the Mineral
Leasing Act for Acquired Lands, as
amended.
(f) The Act of May 21, 1930 (30 U.S.C.
301–306), authorizes the leasing of oil
and gas deposits under certain rights-ofway to the owner of the right-of-way or
any assignee.
(g)(1) Certain lands in Nevada. The
Act of May 9, 1942 (56 Stat. 273), as
amended by the Act of October 25, 1949
(63 Stat. 886), authorizes leasing on
certain lands in Nevada.
(2) Lands patented to the State of
California. The Act of March 3, 1933 (47
Stat. 1487), as amended by the Act of
June 5, 1936 (49 Stat. 1482) and the Act
of June 29, 1936 (49 Stat. 2026),
authorizes leasing on certain lands
patented to the State of California.
(3) National Forest Service Lands in
Minnesota. The Act of June 30, 1950 (16
U.S.C. 508(b)) authorizes leasing on
certain National Forest Service Lands in
Minnesota.
(4) Units of the National Park System.
The Secretary is authorized to permit
mineral leasing in the following units of
the National Park System if the
Secretary finds that such disposition
would not have significant adverse
effects on the administration of the area
and if lease operations can be conducted
in a manner that will preserve the
scenic, scientific and historic features
contributing to public enjoyment of the
area, pursuant to the following
authorities:
(i) Lake Mead National Recreation
Area—The Act of October 8, 1964 (16
U.S.C. 460n et seq.).
(ii) Whiskeytown Unit of the
Whiskeytown-Shasta-Trinity National
Recreation Area—The Act of November
8, 1965 (79 Stat. 1295; 16 U.S.C. 460q
et seq.).
(iii) Ross Lake and Lake Chelan
National Recreation Areas—The Act of
October 2, 1968 (82 Stat. 926; 16 U.S.C.
90 et seq.).
(iv) Glen Canyon National Recreation
Area—The Act of October 27, 1972 (86
Stat. 1311; 16 U.S.C. 460dd et seq.).
(5) Shasta and Trinity Units of the
Whiskeytown-Shasta-Trinity National
Recreation Area. Section 6 of the Act of
November 8, 1965 (Pub. L. 89–336; 79
Stat. 1295), authorizes the Secretary of
the Interior to permit the removal of
leasable minerals from lands (or interest
in lands) within the recreation area
under the jurisdiction of the Secretary of
Agriculture in accordance with the
Mineral Leasing Act of February 25,
1920, as amended (30 U.S.C. 181 et
seq.), or the Acquired Lands Mineral
Leasing Act of August 7, 1947 (30 U.S.C.
351 et seq.), if the Secretary finds that
such disposition would not have
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significant adverse effects on the
purpose of the Central Valley project or
the administration of the recreation
area.
(h) Under the Recreation and Public
Purposes Act, as amended (43 U.S.C.
869 et seq.), all lands within Recreation
and Public Purposes leases and patents
are subject to lease under the provisions
of this part, subject to such conditions
as the Secretary deems appropriate.
(i)(1) Coordination lands are those
lands withdrawn or acquired by the
United States and made available to the
States by cooperative agreements
entered into between the Fish and
Wildlife Service and the game
commissions of the various States, in
accordance with the Fish and Wildlife
Coordination Act (16 U.S.C. 661), or by
long-term leases or agreements between
the Department of Agriculture and the
game commissions of the various States
pursuant to the Bankhead-Jones Farm
Tenant Act (50 Stat. 525), as amended,
where such lands were subsequently
transferred to the Department of the
Interior, with the Fish and Wildlife
Service as the custodial agency of the
United States.
(2) Representatives of the BLM and
the Fish and Wildlife Service will, in
cooperation with the authorized
members of the various State game
commissions, confer for the purpose of
determining by agreement those
coordination lands which will not be
subject to oil and gas leasing.
Coordination lands not closed to oil and
gas leasing may be subject to leasing on
the imposition of such stipulations as
are agreed upon by the State Game
Commission, the Fish and Wildlife
Service and the BLM.
(j) No lands within a refuge in Alaska
open to leasing will be available until
the Fish and Wildlife Service has first
completed compatibility
determinations.
ddrumheller on DSK120RN23PROD with RULES4
§ 3100.5
Definitions.
As used in this part, the term:
Actual drilling operations includes
not only the physical drilling of a well,
but also the testing, completing or
equipping of such well for production.
Assignment means a transfer of all or
a portion of the lessee’s record title
interest in a lease.
Bid means an amount of remittance
offered as partial compensation for a
lease equal to or in excess of the
national minimum acceptable bonus bid
set by statute or by the Secretary,
submitted by a person for a lease parcel
in a competitive lease sale. For leases or
compensatory royalty agreements issued
under 43 CFR subpart 3109, ‘‘bid’’
means an amount or percent of royalty
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or compensatory royalty that the owner
or lessee must pay for the extraction of
the oil and gas underlying the right-ofway.
Competitive auction means an inperson or internet-based bidding
process where leases are offered to the
highest bidder.
Exception means (as used for lease
stipulations) a limited exemption, for a
particular site within the leasehold, to a
stipulation.
Lessee means a person holding record
title in a lease issued by the United
States.
Modification means (as used for lease
stipulations) a change to the provisions
of a lease stipulation for some or all
sites within the leasehold and either
temporarily or for the term of the lease.
National Wildlife Refuge System
Lands means lands and water, or
interests therein, administered by the
Secretary as wildlife refuges, areas for
the protection and conservation of fish
and wildlife that are threatened with
extinction; wildlife management areas;
or waterfowl production areas.
Oil and gas agreement means an
agreement between lessees and the BLM
to govern the development and
allocation of production for existing
leases and unleased lands, including,
but not limited to, communitization
agreements, compensatory royalty
agreements, unit agreements, secondary
recovery agreements, and gas storage
agreements.
Operating right (working interest)
means the interest created out of a lease
authorizing the holder of that right to
enter upon the leased lands to conduct
drilling and related operations,
including production of oil or gas from
such lands in accordance with the terms
of the lease. Operating rights include the
obligation to comply with the terms of
the original lease, as it applies to the
area or horizons for the interest
acquired, including the responsibility to
plug and abandon all wells that are no
longer capable of producing, reclaim the
lease site, and remedy environmental
problems.
Operating rights owner means a
person holding operating rights in a
lease issued by the United States. A
lessee also may be an operating rights
owner if the operating rights in a lease
or portion thereof have not been severed
from record title.
Operator means any person,
including, but not limited to, the lessee
or operating rights owner, who has
stated in writing to the authorized
officer that it is responsible under the
terms and conditions of the lease for the
operations conducted on the leased
lands or a portion thereof.
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30969
Primary term of lease subject to
section 4(d) of the Act prior to the
revision of 1960 (30 U.S.C. 226–1(d))
means all periods of the life of the lease
prior to its extension by reason of
production of oil and gas in paying
quantities; and
Primary term of all other leases means
the initial term of the lease, which is 10
years.
Qualified bidder means any person in
compliance with the laws and
regulations governing a bid.
Qualified lessee means any person in
compliance with the laws and
regulations governing the BLM issued
leases held by that person.
Record title means a lessee’s interest
in a lease, which includes the obligation
to pay rent and the ability to assign and
relinquish the lease. Record title
includes the obligation to comply with
the lease terms, including requirements
relating to well operations and
abandonment. Overriding royalty and
operating rights are severable from
record title interests.
Responsible bidder means any person
who has not defaulted on the payment
of winning bids for BLM-issued oil and
gas leases, is capable of fulfilling the
requirements of onshore BLM oil and
gas leases, and is in compliance with
statutes and regulations applicable to oil
and gas development or with the terms
of a BLM-issued oil and gas lease. The
term ‘‘responsible bidder’’ does not
include persons who bid with no
intention of paying a winning bid or
persons who default on a winning bid.
Responsible lessee means any person
who has not defaulted on previous
winning bids, is capable of fulfilling the
requirements of onshore Federal oil and
gas leases, and is in compliance with
statutes applicable to oil and gas
development or the terms of a BLMissued oil and gas lease.
Sublease means a transfer of a nonrecord title interest in a lease, i.e., a
transfer of operating rights is normally
a sublease, and a sublease also is a
subsidiary arrangement between the
lessee (sublessor) and the sublessee, but
a sublease does not include a transfer of
a purely financial interest, such as
overriding royalty interest or payment
out of production, nor does it affect the
relationship imposed by a lease between
the lessee(s) and the United States.
Transfer means any conveyance of an
interest in a lease by assignment,
sublease or otherwise. This definition
includes the terms: Assignment and
Sublease.
Unit operator means the person
authorized under the unit agreement
approved by the Department of the
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§ 3100.9
§ 3100.21
Information collection.
(a) Authority: 44 U.S.C. 3501–3520
(b)(1) Purpose. The Paperwork
Reduction Act of 1995 generally
provides that an agency may not
conduct or sponsor, and
notwithstanding any other provision of
law, a person is not required to respond
to a collection of information, unless the
collection displays a currently valid
Office of Management and Budget
(OMB) Control Number. This part
displays OMB control numbers assigned
to information collection requirements
contained in the BLM’s regulations at 43
CFR part 3100. This section aids in
fulfilling the requirements of the
Paperwork Reduction Act to display
current OMB Control Numbers for these
information collection requirements.
Interested persons should consult
https://www.reginfo.gov for the most
current information on these OMB
control numbers; including among other
things, the justification for the
information collection requirements,
description of likely respondents,
estimated burdens, and current
expiration dates.
(2) Table 1 to Paragraph (b)—OMB
control number assigned pursuant to the
Paperwork Reduction Act.
43 CFR part or section
ddrumheller on DSK120RN23PROD with RULES4
§§ 3100, 3103.41, 3120, and
Subpart 3162 ....................
§§ 3106, 3135, and 3216 ......
Part 3130 ..............................
Subpart 3195 ........................
§ 3150 ...................................
§§ 3160,* 3171, 3176, and
3177 ..................................
§§ 3172, 3173, 3174, 3175 ...
§§ 3162.3–1, 3178.5, 3178.7,
3178.8, 3178.9 and Subpart 3179 * .........................
OMB control
No.
1004–0185
1004–0034
1004–0196
1004–0179
1004–0162
1004–0220
1004–0137
1004–0211
* Information collection requirements for onshore oil and gas operations are generally accounted for under OMB Control Number
1004–0220; however, information collection requirements pertaining to particular to waste
prevention, production subject to royalties, and
resource conservation are accounted for under
OMB Control Number 1004–0211.
§ 3100.10
Helium.
The ownership of and the right to
extract helium from all gas produced
from lands leased or otherwise disposed
of under the Act have been reserved to
the United States.
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§ 3100.32
Drainage
Interior to conduct operations within
the unit.
Waiver means (as used for lease
stipulations) a permanent exemption
from a lease stipulation.
Compensation for drainage.
Upon a determination by the
authorized officer that lands owned by
the United States are being drained of
oil or gas by wells drilled on adjacent
lands, the authorized officer may
execute agreements with the owners of
adjacent lands whereby the United
States and its lessees will be
compensated for such drainage. Such
agreements must be made with the
consent of any lessee affected by an
agreement. Such lands may also be
offered for lease in accordance with 43
CFR part 3120.
§ 3100.22 Drilling and production or
payment of compensatory royalty.
Where lands in any leases are being
drained of their oil or gas content by
wells either on a Federal lease issued at
a lower rate of royalty or on non-Federal
lands, the lessee must both drill and
produce all wells necessary to protect
the leased lands from drainage. In lieu
of drilling necessary wells, the lessee
may, with the consent of the authorized
officer, pay compensatory royalty in
accordance with 43 CFR 3162.2–4.
Options
§ 3100.31
Enforceability.
(a) No option to acquire any interest
in a lease is enforceable if entered into
for a period of more than 3 years
(including any renewal period that may
be provided for in the option).
(b) No option or renewal thereof is
enforceable until a signed copy or notice
of the option has been filed in the
proper BLM office. Each such signed
copy or notice must include:
(1) The names and addresses of the
parties thereto;
(2) The serial number of the lease to
which the option is applicable;
(3) A statement of the number of acres
and the type and percentage of interests
to be conveyed and retained by the
parties to the option, including the date
and expiration date of the option.
(c) The signatures of all parties to the
option or their duly authorized agents.
The signed copy or notice of the option
required by this paragraph must contain
or be accompanied by a signed
statement by the holder of the option
that entity is the sole party in interest
in the option; if not, the entity must set
forth the names and provide a
description of the interest therein of the
other interested parties, and provide a
description of the agreement between
them, if oral, and a copy of such
agreement, if written.
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Effect of option on acreage.
The acreage to which the option is
applicable will be charged both to the
grantor of the option and the option
holder. The acreage covered by an
unexercised option remains charged
during its term until notice of its
relinquishment or surrender has been
filed in the proper BLM office.
§ 3100.33
Option statements.
Each option holder must file in the
proper BLM office within 90 days after
June 30 and December 31 of each year
a statement showing:
(a) Any changes to the statements
submitted under § 3100.31(b); and
(b) The number of acres covered by
each option and the total acreage of all
options held in each State.
§ 3100.40
Public availability of information.
(a) All data and information
concerning Federal and Indian minerals
submitted under this part 3100 and
parts 3120 through 3190 of this chapter
are subject to 43 CFR part 2, except as
provided in paragraph (c) of this
section. 43 CFR part 2 includes the
regulations of the Department of the
Interior covering the public disclosure
of data and information contained in
Department of the Interior records.
Certain mineral information not
protected from public disclosure under
43 CFR part 2 may be made available for
inspection without a Freedom of
Information Act (FOIA) (5 U.S.C. 552)
request.
(b) When you submit data and
information under this part 3100 and
parts 3120 through 3190 of this chapter
that you believe to be exempt from
disclosure to the public, you must
clearly mark each page that you believe
includes confidential information. The
BLM will keep all such data and
information confidential to the extent
allowed by 43 CFR 2.26.
(c) Under the Indian Mineral
Development Act of 1982 (IMDA) (25
U.S.C. 2101 et seq.), the Department of
the Interior will hold as privileged
proprietary information of the affected
Indian or Indian Tribe—
(1) All findings forming the basis of
the Secretary’s intent to approve or
disapprove any Minerals Agreement
under IMDA; and
(2) All projections, studies, data, or
other information concerning a Minerals
Agreement under IMDA, regardless of
the date received, related to:
(i) The terms, conditions, or financial
return to the Indian parties;
(ii) The extent, nature, value, or
disposition of the Indian mineral
resources; or
(iii) The production, products, or
proceeds thereof.
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(d) For information concerning Indian
minerals not covered by paragraph (c) of
this section:
(1) The BLM will withhold such
records as may be withheld under an
exemption to FOIA when it receives a
request for information related to tribal
or Indian minerals held in trust or
subject to restrictions on alienation;
(2) The BLM will notify the Indian
mineral owner(s) identified in the
records of the Bureau of Indian Affairs
(BIA) and give them a reasonable period
of time to state objections to disclosure,
using the standards and procedures of
43 CFR 2.28, before making a decision
about the applicability of FOIA
exemption 4 to:
(i) Information obtained from a person
outside the United States Government;
when
(ii) Following consultation with a
submitter under 43 CFR 2.28, the BLM
determines that the submitter does not
have an interest in withholding the
records that can be protected under
FOIA; but
(iii) The BLM has reason to believe
that disclosure of the information may
result in commercial or financial injury
to the Indian mineral owner(s) but is
uncertain that such is the case.
Subpart 3101—Issuance of Leases
Lease Terms and Conditions
§ 3101.11
Lease form.
A lease will be issued only on the
standard form approved by the Director.
ddrumheller on DSK120RN23PROD with RULES4
§ 3101.12
Surface use rights.
A lessee will have the right to use
only so much of the leased lands as is
necessary to explore for, drill for, mine,
extract, remove and dispose of all the
leased resource in a leasehold subject to
applicable requirements, including
stipulations attached to the lease,
restrictions deriving from
nondiscretionary statutes, and such
reasonable measures as may be required
and detailed by the authorized officer to
mitigate adverse impacts to other
resource values, land uses or users,
federally recognized Tribes, and
underserved communities. Such
reasonable measures may include, but
are not limited to, relocation or
modification to siting or design of
facilities, timing of operations,
specification of interim and final
reclamation measures, and specification
of rates of development and production
in the public interest. At a minimum,
modifications that are consistent with
lease rights include, but are not limited
to, requiring relocation of proposed
operations by up to 800 meters and
prohibiting new surface disturbing
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operations for a period of up to 90 days
in any lease year.
§ 3101.13
notices.
Stipulations and information
(a) The BLM may consider the
sensitivity and importance of
potentially affected resources and any
uncertainty concerning the present or
future condition of those resources and
will assess whether a resource is
adequately protected by stipulation
while considering the restrictiveness of
the stipulation on operations.
(b) The authorized officer may require
stipulations as conditions of lease
issuance. Stipulations will become part
of the lease and will supersede
inconsistent provisions of the standard
lease form. Any party submitting a bid
under part 3120 will be deemed to have
agreed to stipulations applicable to the
specific parcel as indicated in the
Notice of Competitive Lease Sale
available from the proper BLM office.
(c) The BLM may attach an
information notice to the lease. An
information notice has no legal
consequences, except to give notice of
existing requirements, and may be
attached to a lease by the authorized
officer at the time of lease issuance to
convey certain operational, procedural
or administrative requirements relative
to lease management within the terms
and conditions of the standard lease
form. Information notices may not be a
basis for denial of lease operations.
(d) Where the surface managing
agency is the Fish and Wildlife Service,
leases will be issued subject to
stipulations prescribed by the Fish and
Wildlife Service as to the time, place,
nature and condition of such operations
in order to minimize impacts to fish and
wildlife populations and habitat and
other refuge resources on the areas
leased. The specific conduct of lease
activities on any refuge lands will be
subject to site-specific stipulations
prescribed by the Fish and Wildlife
Service.
§ 3101.14 Modification, waiver, or
exception.
(a) If the authorized officer determines
that a change to a lease term or
stipulation is substantial or a stipulation
involves an issue of major concern to
the public, except for changes to
stipulations governing time of year
restrictions (such as those related to
protected species) supported by data
showing that the restrictions are
unnecessary, the changes will be subject
to public review for at least 30 calendar
days.
(b) Prior to lease issuance, if the BLM
determines that an additional
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30971
stipulation will be added to the lease or
a modification to an existing stipulation
is required, the potential lessee must be
given an opportunity to accept the
additional or modified stipulation. If the
potential lessee does not accept the
additional or modified stipulation, the
BLM may reject the bid, and may
include the lands in the next Notice of
Competitive Lease Sale. If the change in
stipulation(s) increases the value of the
parcel, the BLM will reject the bid, and
will include the lands in the next Notice
of Competitive Lease Sale.
(c) After lease issuance, if a lessee
does not accept an additional or
modified stipulation, that additional or
modified stipulation is not binding on
the lessee and is without effect. When
a stipulation is required by the relevant
Resource Management Plan, or surface
management agency land management
plan, and was inadvertently omitted, a
lessee’s failure to sign and accept
changes in the stipulations when
requested by the authorized officer may
subject the lease to cancellation.
(d) A stipulation included in an oil
and gas lease will be subject to
modification, waiver, or exception if the
authorized officer determines, in
conjunction with the applicable surface
management agency, that the factors
leading to its inclusion in the lease have
changed sufficiently to make the
specific protections provided by the
stipulation no longer justified.
Acreage Limitations
§ 3101.21
Public domain lands.
(a) No person may take, hold, own or
control more than 246,080 acres of
Federal oil and gas leases on public
domain lands in any one State at any
one time. No more than 200,000 acres of
such acres may be held under option.
(b) In Alaska, the acreage that can be
taken, held, owned or controlled is
limited to 300,000 acres in the northern
leasing district and 300,000 acres in the
southern leasing district, of which no
more than 200,000 acres may be held
under option in each of the two leasing
districts. The boundary between the two
leasing districts in Alaska begins at the
northeast corner of the Tetlin National
Wildlife Refuge as established by
section 302(8) of the Alaska National
Interest Lands Conservation Act, at a
point on the boundary between the
United States and Canada, then
northwesterly along the northern
boundary of the refuge to the left limit
of the Tanana River (63°9′38″ north
latitude, 142°20′52″ west longitude),
then westerly along the left limit to the
confluence of the Tanana and Yukon
Rivers, and then along the left limit of
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the Yukon River from said confluence to
its principal southern mouth.
§ 3101.22
Acquired lands.
Separate from, and in addition to, the
limitation for public domain lands, no
person may take, hold, own or control
more than 246,080 acres of Federal oil
and gas leases on acquired lands in any
one State at any one time. No more than
200,000 acres of such acres may be held
under option. Where the United States
owns only a fractional interest in the
mineral resources of the lands involved
in a lease, only that part owned by the
United States will be charged as acreage
holdings. The acreage embraced in a
future interest lease will not be charged
as acreage holdings until the lease for
the future interest becomes effective.
§ 3101.23
Excepted acreage.
(a) The following acreage will not be
included in computing acreage
limitations:
(1) Acreage under any lease any
portion of which is committed to any
federally approved oil and gas
agreement;
(2) Acreage under any lease for which
royalty (including compensatory royalty
or royalty in-kind) was paid in the
preceding calendar year; and
(3) Acreage under leases subject to an
operating, drilling or development
contract approved by the Secretary, as
provided in 43 CFR 3105.30.
(b) Acreage subject to offers to lease,
overriding royalties and payments out of
production will not be included in
computing acreage limitations.
ddrumheller on DSK120RN23PROD with RULES4
§ 3101.24
Excess acreage.
(a) Where, as the result of the
termination or contraction of an oil and
gas agreement or the elimination of a
lease from an operating, drilling, or
development contract, a party holds or
controls excess accountable acreage,
that party will have 90 calendar days
from the date of termination,
contraction or elimination, to reduce the
holdings to the prescribed limitation
and to file proof of the reduction in the
proper BLM office. Where, as a result of
a merger or the purchase of the
controlling interest in a corporation, a
party acquired acreage in excess of the
amount permitted, the party holding the
excess acreage will have 180 calendar
days from the date of the merger or
purchase to divest the excess acreage. If
additional time is required to complete
the divestiture of the excess acreage, a
petition requesting additional time,
along with a full justification for the
additional time, may be filed with the
authorized officer prior to the
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termination of the 180 days provided
herein.
(b) If any person is found to hold
accountable acreage in violation of the
provisions of these regulations, lease(s)
or interests therein will be subject to
cancellation or forfeiture in their
entirety, until sufficient acreage has
been eliminated to comply with the
acreage limitation. Excess acreage or
interest will be cancelled in the inverse
order of acquisition.
§ 3101.25
Computation.
The accountable acreage of a party
owning an undivided interest in a lease
will be the party’s proportionate part of
the total lease acreage.
§ 3101.30 Leases within unit areas, joinder
evidence required.
Before issuance of a lease for lands
within an approved unit, the lease
offeror must file evidence with the
proper BLM office that it has joined in
the unit agreement and unit operating
agreement or a statement giving
satisfactory reasons for its failure to
enter into such agreement. If such
statement is satisfactory to the
authorized officer, the lessee may be
permitted to operate independently but
will be required to conform to the terms
and provisions of the unit agreement
with respect to such operations.
§ 3101.40
Terminated leases.
(a) The authorized officer will not
issue a lease for lands which have been
covered by a lease which terminated
automatically until 90 calendar days
after the date of termination.
(b) The authorized officer will not,
after the receipt of a petition for
reinstatement, issue a new lease
affecting any of the lands covered by the
terminated lease until all action on the
petition is final.
Federal Lands Administered by an
Agency Other Than the Bureau of Land
Management
§ 3101.51
General requirements.
Public domain and acquired lands
will be leased only after seeking
concurrence from the surface managing
agency, which, upon receipt of a
description of the lands from the
authorized officer, may report to the
authorized officer that it consents to
leasing with stipulations, if any, or
withholds consent or objects to leasing.
§ 3101.52 Action by the Bureau of Land
Management.
(a) Where the surface managing
agency has consented to leasing with
required stipulations, and the Secretary
decides to issue a lease, the authorized
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officer will incorporate the stipulations
into any lease which it may issue. The
authorized officer may add other
appropriate stipulations.
(b) The authorized officer will not
issue a lease on lands to which the
surface managing agency objects or
withholds consent and for which
consent or concurrence is required by
law.
(c) The authorized officer will review
all recommendations of the surface
managing agency and will accept all
reasonable recommendations.
(d) Where the surface managing
agency is the Fish and Wildlife Service,
there will be no drilling or prospecting
under any lease heretofore or hereafter
issued on lands within a wildlife refuge,
except with the consent and approval of
the Secretary with the concurrence of
the Fish and Wildlife Service as to the
time, place and nature of such
operations in order to give complete
protection to wildlife populations and
wildlife habitat on the areas leased, and
all such operations must be conducted
in accordance with BLM stipulations.
§ 3101.53
Appeals.
(a) The decision of the authorized
officer to reject an offer to lease or to
issue a lease with stipulations
recommended by the surface managing
agency may be appealed to the Interior
Board of Land Appeals under 43 CFR
part 4.
(b) Where, as provided by statute, the
surface managing agency has required
that certain stipulations be included in
a lease or has consented, or objected or
refused to consent to leasing, any appeal
by an affected lease offeror will be
subject to the administrative remedies if
provided for by the particular surface
managing agency.
§ 3101.60 State’s or charitable
organization’s ownership of surface
overlying federally owned minerals.
Where the United States has conveyed
title to, or otherwise transferred the
control of the surface of lands to any
State or political subdivision, agency, or
instrumentality thereof, or a college or
any other educational corporation or
association, or a charitable or religious
corporation or association, with
reservation of the oil and gas rights to
the United States, such party will be
given an opportunity to suggest any
lease stipulations deemed necessary for
the protection of existing surface
improvements or uses, to set forth the
facts supporting the necessity of the
stipulations and also to file any
objections it may have to the issuance
of a lease. Where a party controlling the
surface opposes the issuance of a lease
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or wishes to place such restrictive
stipulations upon the lease that it could
not be operated upon or become part of
a drilling unit and hence is without
mineral value, the facts submitted in
support of the opposition or request for
restrictive stipulations may be given
consideration and each case will be
decided on its merits. The opposition to
lease or necessity for restrictive
stipulations expressed by the party
controlling the surface affords no legal
basis or authority to refuse to issue the
lease or to issue the lease with the
requested restrictive stipulations for the
reserved minerals in the lands; in such
case, the final determination whether to
issue and with what stipulations, or not
to issue the lease depends upon whether
or not the interests of the United States
would best be served by the issuance of
the lease.
Subpart 3102—Qualifications of
Lessees
§ 3102.10
Who may hold leases.
Leases or interests therein may be
acquired and held only by citizens of
the United States; associations
(including partnerships and trusts) of
such citizens; corporations organized
under the laws of the United States or
of any State or Territory thereof; and
municipalities.
ddrumheller on DSK120RN23PROD with RULES4
§ 3102.20
Non-U.S. Citizens.
(a) Leases or interests therein may be
acquired and held by non-U.S. Citizens
only through stock ownership, holding
or control in a present or potential
lessee that is incorporated under the
laws of the United States or of any State
or territory thereof, and only if the laws,
customs or regulations of their country
do not deny similar or like privileges to
citizens or corporations of the United
States. If it is determined that a country
has denied similar or like privileges to
citizens or corporations of the United
States, it would be placed on a list
available from any BLM State office.
(b) The Committee on Foreign
Investment in the United States is
authorized to review covered real estate
transactions and to mitigate any risk to
the national security of the United
States that arises as a result of such
transactions. Covered real estate
transactions may include certain
transactions involving the Federal
mineral estate (see 31 CFR part 802).
§ 3102.30
Minors.
Leases must not be acquired or held
by someone considered to be a minor
under the laws of the State in which the
lands are located, but leases may be
acquired and held by legal guardians or
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trustees of minors on their behalf. Such
legal guardians or trustees must be
citizens of the United States or
otherwise meet the provisions of 43 CFR
3102.10.
§ 3102.40
Signature.
Signatures on all applications and
BLM forms certify acceptance of lease
terms and stipulations, as well as
compliance with the regulations under
43 CFR part 3100. Refer to § 3102.50 for
certification of compliance and
evidence. The BLM also accepts
electronic signatures and submissions.
(a) A bid to lease must be made on a
current form approved by the Director.
Copies must be exact reproductions of
the official approved form, without
additions, omissions, or other changes.
When the bid is filed in person at the
proper BLM office, the bid must be
typed or printed plainly, signed, and
dated by the offeror or an authorized
agent on behalf of the present or
potential lessee. Bids may be made to
the BLM by other arrangements, such as
electronically signed and filed, when
specifically authorized by the BLM.
(b) Documents signed by any party
other than the present or potential
lessee must be rendered in a manner to
reveal the name of the present or
potential lessee, the name of the
signatory and their relationship. A
signatory who is a member of the
organization that constitutes the present
or potential lessee (e.g., officer of a
corporation, partner of a partnership,
etc.) may be requested by the authorized
officer to clarify his/her relationship,
when the relationship is not shown on
the documents filed.
Compliance, Certification of
Compliance and Evidence
§ 3102.51
Compliance.
Only responsible and qualified
bidders and lessees may own, hold, or
control an interest in a lease or
prospective lease. Responsible and
qualified bidders and lessees, including
corporations, and all members of
associations, including partnerships of
all types, will, without exception, be
qualified and in compliance with the
Act. Compliance means that the persons
are:
(a) Citizens of the United States (see
§ 3102.10) or non-U.S. citizens who own
stock in a corporation organized under
State or Federal law (see § 3102.20);
(b) In compliance with the Federal
acreage limitations (see § 3101.20);
(c) Not minors (see § 3102.30);
(d) Except for an assignment or
transfer under 43 CFR subpart 3106, in
compliance with section 2(a)(2)(A) of
the Act (30 U.S.C. 201(2)(A)), in which
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30973
case the signature on a bid or lease
constitutes evidence of compliance. A
lease issued to any person in violation
of this paragraph (d) will be subject to
the cancellation provisions of 43 CFR
3108.30.
(e) Not in violation of the provisions
of section 41 of the Act (30 U.S.C. 195);
and
(f) In compliance with section 17(g) of
the Act (30 U.S.C. 226(g)), in which case
the signature on an offer, lease,
assignment, or transfer constitutes
evidence of compliance that the
signatory and any subsidiary, affiliate,
or person, association, or corporation
controlled by or under common control
with the signatory, as defined in 43 CFR
3400.0–5(rr), has not failed or refused to
comply with reclamation requirements
with respect to all leases and operations
thereon in which such person has an
interest. A person is noncompliant with
section 17(g) of the Act when they fail
to comply with their reclamation
obligations or other standards
established under 30 U.S.C. 226 in the
time specified in a notice from the BLM.
A lease issued, or an assignment or
transfer approved, to any such person in
violation of this paragraph (f) may be
subject to the cancellation provisions of
43 CFR 3108.30, notwithstanding any
administrative or judicial appeals that
may be pending with respect to
violations or penalties assessed for
failure to comply with the prescribed
reclamation standards on any lease
holdings. Noncompliance will end upon
a determination by the authorized
officer that all required reclamation has
been completed and that the United
States has been fully reimbursed for any
costs incurred due to the required
reclamation.
(g) In compliance with 43 CFR
3106.10(d) and section 30A of the Act
(30 U.S.C. 187(a)). The authorized
officer may accept the signature on a
request for approval of an assignment of
less than 640 acres outside of Alaska
(2,560 acres within Alaska) as
acceptable certification that the
assignment would further the
development of oil and gas, or the
authorized officer may apply the
provisions of 43 CFR 3102.53.
(h) Not excluded or disqualified from
participating in a transaction covered by
Federal non-procurement debarment
and suspension (2 CFR parts 180 and
1400), unless the Department explicitly
approves an exception for a transaction
pursuant to the regulations in those
parts.
§ 3102.52
Certification of compliance.
Any party(s) seeking to obtain an
interest in a lease must certify that it is
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in compliance with the Act as set forth
in 43 CFR 3102.51. A corporation or
publicly traded association, including a
publicly traded partnership, must
certify that constituent members of the
corporation, association or partnership
holding or controlling more than 10
percent of the instruments of ownership
of the corporation, association or
partnership are in compliance with the
Act. Execution and submission of a
competitive bid form or request for
approval of a transfer of record title or
of operating rights (sublease),
constitutes certification of compliance.
§ 3102.53
Evidence of compliance.
The authorized officer may request at
any time further evidence of compliance
and qualification from any party
holding or seeking to hold an interest in
a lease. Failure to comply with the
request of the authorized officer will
result in adjudication of the action
based on the incomplete submission.
Subpart 3103—Fees, Rentals and
Royalty
§ 3103.1
every 4 years by a final rule. The BLM
will adjust the amounts according to the
change in the Implicit Price Deflator for
Gross Domestic Product since the
previous adjustment. The fiscal terms
displayed below are effective on June
22, 2024. Per the Inflation Reduction
Act, the BLM will not adjust the rental
nor the minimum bonus bids until after
August 16, 2032.
Fiscal terms.
(a) The table in this section shows the
fiscal terms, that the BLM will adjust
TABLE 1 TO PARAGRAPH (a)—FISCAL TERMS TABLE
Oil and gas (parts 3100, 3110, 3120, 3130, 3140):
Fiscal term
Competitive oil and gas, tar sand, and combined hydrocarbon leases .......................................................
Rental of $3 per acre, or fraction
thereof, per year during the first 2year period beginning upon lease
issuance, $5 per acre per year, or
fraction thereof, for the following 6
years, and then $15 per acre, or
fraction thereof, per year thereafter.
Rental of $20 per acre, or fraction
thereof.
Minimum bonus bids of $25 per acre,
or fraction thereof.
Minimum bonus bids of $10 per acre,
or fraction thereof.
$5 per acre.
Competitive lease reinstatement, Class II ....................................................................................................
Competitive combined hydrocarbon leases ..................................................................................................
Competitive oil and gas and tar sand leases ...............................................................................................
Expression of interest filing fee ....................................................................................................................
(b) The amounts in the fiscal terms
table are not subject to appeal to the
Interior Board of Land Appeals pursuant
to 43 CFR part 4, subpart E.
Payments
§ 3103.11
Form of remittance.
All remittances must be by personal
check, cashier’s check, certified check,
or money order, and must be made
payable to the Department of the
Interior—Bureau of Land Management
or the Department of the Interior—
Office of Natural Resources Revenue, as
appropriate. Payments made to the BLM
may be made by other arrangements
such as by electronic funds transfer or
credit card when specifically authorized
by the BLM. In the case of payments
made to the ONRR, such payments may
also be made by electronic funds
transfer.
ddrumheller on DSK120RN23PROD with RULES4
§ 3103.12
Where remittance is submitted.
(a)(1) All processing fees for the
respective lease applications,
nominations, or requests for approval of
a transfer found in the fee schedule in
§ 3000.120 of this chapter and all firstyear rentals and bonuses for leases
issued under 43 CFR part 3100 must be
paid to the proper BLM office.
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(2) All second year and subsequent
rentals, except for leases specified in
paragraph (b) of this section, must be
paid to the ONRR, refer to 30 CFR
1218.51.
(b) All rentals and royalties on
producing leases, communitized leases
in producing spacing units, unitized
leases in producing unit areas, leases on
which compensatory royalty is payable
and all payments under subsurface
storage agreements must be paid to the
ONRR.
Rentals
§ 3103.21
Rental requirements.
(a) Each competitive bid submitted in
response to a Notice of Competitive
Lease Sale must be accompanied by full
payment of the first year’s rental based
on the total acreage for that lease in the
Notice of Competitive Lease Sale.
(b) If the acreage is incorrectly
indicated in a Notice of Competitive
Lease Sale, payment of the rental based
on the error is curable within 15
calendar days of receipt of notice from
the authorized officer of the error.
(c) Rental will not be prorated for any
lands in which the United States owns
an undivided fractional interest and
must be paid for the full acreage in such
lands.
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§ 3103.22
Annual rental payments.
Rentals must be paid on or before the
lease anniversary date. A full year’s
rental must be submitted even when
less than a full year remains in the lease
term, except as provided in 43 CFR
3103.42(d). Failure to make the required
payment on or before the lease
anniversary date will cause a lease to
terminate automatically by operation of
law. If the designated ONRR office is not
open on the anniversary date, payment
received on the next day the designated
ONRR office is open to the public will
be deemed to be timely made. Payments
made to an improper BLM or ONRR
office will be returned and will not be
forwarded to the designated ONRR
office. Rental must be paid at the
following rates:
(a) The annual rental for all leases is
as stated in the lease, and the annual
rental for all new leases will be as
specified in 43 CFR 3103.1;
(b) Rental will not be due on acreage
for which royalty or minimum royalty is
being paid, except on nonproducing
leases when compensatory royalty has
been assessed in which case annual
rental as established in the lease will be
due in addition to compensatory
royalty;
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(c) For leases that are reinstated under
§ 3108.23, the annual rental will be as
specified in 43 CFR 3103.1 beginning
with the termination date upon the
filing of a petition to reinstate a lease;
and
(d) Each succeeding time a specific
lease is reinstated under § 3108.23, the
annual rental on that lease will increase
by an additional $10 per acre or fraction
thereof.
Royalties
§ 3103.31
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 the amount or value of
the production removed or sold as
follows:
(1) For leases issued before August 16,
2022, the rate prescribed in the lease or
in applicable regulations at the time of
lease issuance;
(2) For leases issued between August
16, 2022, and August 16, 2032, the
royalty rate will be 16.67 percent;
(3) For leases issued on or after
August 16, 2032, a rate of not less than
16.67 percent on all leases issued under
the Act;
(4) A minimum of 16.67 percent on all
leases issued under 43 CFR subpart
3109;
(5) For reinstated leases, the rate used
for royalty determination that applies to
new leases at the time of the
reinstatement plus 4 percentage points,
plus an additional 2 percentage points
for each succeeding reinstatement. In no
case will royalties on the reinstated
lease be less than 20 percent.
(b) Leases that qualify under specific
provisions of the Act of August 8, 1946
(30 U.S.C. 226c) may apply for a
limitation of a 121⁄2 percent royalty rate.
(c) The average production per well
per day for oil and gas will be
determined pursuant to 43 CFR 3162.7–
4.
(d) Payment of a royalty on the
helium component of gas will not
convey the right to extract the helium
from the gas stream. Applications for
the right to extract helium from the gas
stream will be made under 43 CFR part
16.
ddrumheller on DSK120RN23PROD with RULES4
§ 3103.32
Minimum royalties.
(a) A minimum royalty must be paid
at the expiration of each lease year
beginning on or after a discovery of oil
or gas in paying quantities on the lands
leased, except on unitized leases that
lack production, the minimum royalty
must be paid only on the participating
acreage, at the following rates:
(1) On leases issued on or after August
8, 1946, and on those issued prior
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thereto if the lessee files an election
under section 15 of the Act of August 8,
1946, a minimum royalty of $1 per acre
or fraction thereof in lieu of rental,
except as provided in paragraph (a)(2) of
this section; and
(2) On leases issued from offers filed
after December 22, 1987, and on
competitive leases issued after
December 22, 1987, a minimum royalty
in lieu of rental of not less than the
amount of rental which otherwise
would be required for that lease year.
(b) Minimum royalties will not be
prorated for any lands in which the
United States owns a fractional interest
and must be paid on the full acreage of
the lease.
(c) Minimum royalties and rentals on
non-participating acreage must be paid
to the ONRR.
(d) The minimum royalty provisions
of this section are applicable to leases
reinstated under 43 CFR 3108.23.
(e) If the royalty paid during any year
aggregates to less than the minimum
royalty, then the lessee must pay the
difference at the end of the lease year.
Production Incentives
§ 3103.41
Royalty reductions.
(a) In order to encourage the greatest
ultimate recovery of oil or gas and in the
interest of conservation, the Secretary,
upon a determination that it is
necessary to promote development or
that the leases cannot be produced in
paying quantities under the terms
provided therein, may waive, suspend
or reduce the rental or minimum royalty
or reduce the royalty on an entire
leasehold, or any portion thereof.
(b)(1) An application for the benefits
under paragraph (a) of this section must
be filed by the operator/payor in the
proper BLM office. The application
must contain the serial number of the
leases, the names of the record title
holders, operating rights owners
(sublessees), and operators for each
lease, the description of lands by legal
subdivision and a description of the
relief requested.
(2) Each application must show the
number, location and status of each well
drilled, a tabulated statement for each
month covering a period of not less than
6 months prior to the date of filing the
application of the aggregate amount of
oil or gas subject to royalty, the number
of wells counted as producing each
month and the average production per
well per day.
(3) Every application must contain a
detailed statement of expenses and costs
of operating the entire lease, the income
from the sale of any production and all
facts tending to show whether the wells
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can be produced in paying quantities
upon the fixed royalty or rental. Where
the application is for a reduction in
royalty, complete information must be
furnished as to whether overriding
royalties, payments out of production,
or similar interests are paid to others
than the United States, the amounts so
paid and efforts made to reduce them.
The applicant must also file agreements
of the holders to a reduction of all other
royalties or similar payments from the
leasehold to an aggregate not in excess
of one-half the royalties due the United
States.
(c) Petition may be made for a
reduction of royalty for leases reinstated
under 43 CFR 3108.23. Petitions to
waive, suspend or reduce rental or
minimum royalty for leases reinstated
under 43 CFR 3108.23 may be made
under this section.
§ 3103.42 Suspension of operations and/or
production.
(a) A suspension of all operations and
production may be directed or
consented to by the authorized officer
only in the interest of conservation of
natural resources. A suspension of
operations only or a suspension of
production only may be directed or
consented to by the authorized officer in
cases where the lessee is prevented from
operating on the lease or producing
from the lease, despite the exercise of
due care and diligence, by reason of
force majeure, that is, by matters beyond
the reasonable control of the lessee.
Applications for any suspension must
be filed in the proper BLM office.
Complete information showing the
necessity of such relief must be
furnished.
(b) The term of any lease will be
adjusted to account for the suspension.
Beginning on the date the suspension is
lifted, the term will be extended by the
time that was remaining on the term of
the lease on the effective date of the
suspension. No lease will expire during
any suspension.
(c) A suspension will take effect as of
the time specified in the direction or
assent of the authorized officer, in
accordance with the provisions of 43
CFR 3165.1.
(d) Rental and minimum royalty
payments will be suspended during any
period of suspension of all operations
and production directed or assented to
by the authorized officer beginning with
the first day of the lease month in which
the suspension of all operations and
production becomes effective, or if the
suspension of all operations and
production becomes effective on any
date other than the first day of a lease
month, beginning with the first day of
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the lease month following such effective
date. However, if there is any
production sold or removed during the
suspension, the lessee must pay royalty
on that production.
(e) Rental and minimum royalty
payments will resume on the first day
of the lease month in which the
suspension of all operations and
production is lifted. Where rentals are
creditable against royalties and have
been paid in advance, proper credit may
be allowed on the next rental or royalty
due under the terms of the lease.
(f) Rental and minimum royalty
payments will not be suspended during
any period of suspension of operations
only or suspension of production only.
(g) Where all operations and
production are suspended on a lease on
which there is a well capable of
producing in paying quantities and the
authorized officer approves resumption
of operations and production, such
resumption will be regarded as lifting
the suspension, including the
suspension of rental and minimum
royalty payments, as provided in
paragraph (e) of this section.
(h) The relief authorized under this
section also may be obtained for any
Federal lease included within an
approved oil and gas agreement. Oil and
gas agreement obligations will not be
suspended by relief obtained under this
section but will be suspended only in
accordance with the terms and
conditions of the specific agreement.
Subpart 3104—Bonds
§ 3104.1
Bond amounts.
(a) The table in this section shows the
minimum bond amounts, that the BLM
will adjust every 10 years by a final rule.
The BLM will adjust the amounts
according to the change in the Implicit
Price Deflator for Gross Domestic
Product since the previous adjustment.
The minimum bond amounts displayed
below are effective on June 22, 2024.
TABLE 1 TO PARAGRAPH (a)—MINIMUM BOND AMOUNT TABLE
Minimum bond
amount
Oil and gas (parts 3100, 3110, 3120, 3130, 3140):
Lease Bond ..........................................................................................................................................................................................
Statewide Bond ....................................................................................................................................................................................
(b) The Minimum Bond Amount are
not subject to appeal to the Interior
Board of Land Appeals pursuant to 43
CFR part 4, subpart E.
(c) Principals must increase or replace
all bonds not meeting the appropriate
minimum bond amount in paragraph (a)
by:
(1) June 22, 2026, for statewide; and
(2) June 22, 2027, for lease bonds.
(d) Failure to increase or replace an
existing bond that does not meet the
minimum bond amount may:
(1) Subject all wells covered by the
bond(s) to shut down under the
provisions of 43 CFR 3163.1(a)(3);
(2) Subject all leases covered by the
bond(s) to cancellation under the
provisions of 43 CFR 3108.30; and
(3) Result in the BLM referring the
bond obligor or principal to the
Department’s Suspension and
Debarment Program under 2 CFR part
1400 to determine if the person will be
suspended or debarred from doing
business with the Federal Government.
ddrumheller on DSK120RN23PROD with RULES4
§ 3104.10
Bond obligations.
(a) Prior to the commencement of
surface disturbing activities related to
drilling operations, the lessee, operating
rights owner (sublessee), or operator
must submit a surety or a personal
bond, conditioned upon compliance
with all of the terms and conditions of
the entire leasehold(s) covered by the
bond, as described in this subpart. The
bond amounts must be not less than the
minimum amounts described in this
subpart in order to ensure compliance
with the Act, including complete and
timely plugging of the well(s),
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reclamation of the lease area(s), and the
restoration of any lands or surface
waters adversely affected by lease
operations after the abandonment or
cessation of oil and gas operations on
the lease(s) in accordance with, but not
limited to, the standards and
requirements set forth in 43 CFR 3162.3
and 3162.5 and orders issued by the
authorized officer.
(b) Surety bonds must be issued by
qualified surety companies approved by
the Department of the Treasury (see
Department of the Treasury Circular No.
570).
(c) Personal bonds must be
accompanied by a:
(1) Certificate of deposit issued by a
financial institution, the deposits of
which are federally insured, explicitly
granting the Secretary full authority to
demand immediate payment in case of
default in the performance of the terms
and conditions of the lease. The
certificate will explicitly indicate on its
face, or through assignment, that
Secretarial approval is required prior to
redemption of the certificate of deposit
by any party;
(2) Cashier’s check;
(3) Certified check; or
(4) Negotiable Treasury securities of
the United States of a value equal to the
amount specified in the bond.
Negotiable Treasury securities must be
accompanied by a proper conveyance to
the Secretary of full authority to sell
such securities in case of default in the
performance of the terms and conditions
of a lease.
(5) Irrevocable letter of credit issued
by a financial institution, for a specific
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$150,000
500,000
term, identifying the secretary as sole
payee with full authority to demand
immediate payment in the case of
default in the performance of the terms
and conditions of a lease. Letters of
credit must be subject to the following
conditions:
(i) The letter of credit must be issued
only by a financial institution organized
or authorized to do business in the
United States;
(ii) The letter of credit must be
irrevocable during its term. A letter of
credit used as security for any lease
upon which drilling has taken place and
final approval of all abandonment has
not been given, or as security for an
individual lease or statewide bond, will
be forfeited and will be collected by the
authorized officer if not replaced by
other suitable bond or letter of credit at
least 30 days before its expiration date;
(iii) The letter of credit must be
payable to the Bureau of Land
Management upon demand, in part or in
full, upon receipt from the authorized
officer of a notice of collection stating
the basis therefore, e.g., default in
compliance with the lease terms and
conditions or failure to file a
replacement in accordance with
paragraph (c)(5)(ii) of this section;
(iv) The initial expiration date of the
letter of credit must be at least 1 year
following the date it is filed in the
proper BLM office; and
(v) The letter of credit must contain a
provision for automatic renewal for
periods of not less than 1 year in the
absence of notice to the proper BLM
office at least 90 days prior to the
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originally stated or any extended
expiration date. In the event the BLM is
notified of the financial institution’s
intent not to renew the letter of credit,
the principal must extend the letter of
credit or provide an adequate
replacement bond with an assumption
of liability rider. If the BLM does not
receive an adequate notice or
replacement bond with rider, the BLM
will collect the letter of credit within 30
days of the expiration without further
notification to the obligor.
§ 3104.20
Lease bond.
The operator, a lessee, or an owner of
operating rights (sublessee) must be
covered by a bond in its own name as
principal or obligor in an amount of not
less than the amount specified in 43
CFR 3104.1 for each lease conditioned
upon compliance with all of the terms
of the lease. Where two or more lease
interest holders have interests in
different formations or portions of the
lease, separate bonds may be posted.
The operator shall be covered by a bond
in his/her own name as principal, or a
bond in the name of the lessee or
sublessee, provided that a consent of the
surety, or the obligor in the case of a
personal bond, to include the operator
under the coverage of the bond is
furnished to the BLM office maintaining
the bond.
§ 3104.30
Statewide bonds.
In lieu of lease bonds, lessees, owners
of operating rights (sublessees), or
operators may furnish a bond in an
amount of not less than the amount
specified in 43 CFR 3104.1 covering all
leases and operations in any one State.
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§ 3104.40
Surface owner protection bond.
(a) If a good-faith effort by the Federal
lessee, its operator, or representatives
has not resulted in an agreement with
the surface owner under 43 CFR
3171.19, the authorized officer will
require an adequate surface owner
protection bond in an amount sufficient
to indemnify the surface owner against
the reasonable and foreseeable damages
to crops and tangible improvements
from the proposed operations that
would not otherwise be covered by a
bond held by the BLM. This surface
owner protection bond is not part of the
bond obligations under lease or
statewide bonds.
(b) The surface owner protection bond
must be provided on a BLM-approved
form.
(c) The surface owner protection bond
may be a personal or surety bond and
must be not less than $1,000.
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(d) The BLM will notify the surface
owner of the proposed surface owner
protection bond amount.
(e) If the surface owner objects to the
sufficiency of the surface owner
protection bond, the BLM authorized
officer will determine the sufficiency of
the bond necessary to indemnify the
surface owner for the reasonable and
foreseeable damages to crops and
tangible improvements.
§ 3104.50
Increased amount of bonds.
(a) When an operator desiring
approval of an APD has caused the
BLM, or a surface management agency,
to make a demand for payment under a
bond or other financial guarantee within
the 5-year period prior to submission of
the APD, due to failure to plug a well
or reclaim lands completely in a timely
manner, the authorized officer will
require, prior to approval of the APD, a
bond in an amount equal to the costs,
when higher than the minimum bond
amounts, as estimated by the authorized
officer of plugging the well and
reclaiming the disturbed area involved
in the proposed operation, or in the
minimum amount as prescribed in this
subpart, whichever is greater.
(b) The authorized officer may require
an increase in the amount of any bond
whenever it is determined that the
operator poses a risk due to factors,
including, but not limited to, a history
of previous violations, a notice from the
ONRR that there are uncollected
royalties due, or the total cost of
plugging existing wells and reclaiming
lands exceeds the present bond amount
based on the estimates determined by
the authorized officer. The increase in
bond amount may be to any level
specified by the authorized officer, but
in no circumstances will it exceed the
total of the estimated costs of plugging
and reclamation, the amount of
uncollected royalties due to the ONRR,
plus the amount of money owed to the
lessor due to previous violations
remaining outstanding.
§ 3104.60
copies.
Where filed and number of
All bonds must be filed in the proper
BLM office on a current form approved
by the Director. A single copy executed
by the principal or, in the case of surety
bonds, by both the principal and an
acceptable surety is sufficient. A bond
filed on a form not currently in use will
be acceptable, unless such form has
been declared obsolete by the Director
prior to the filing of such bond. For
purposes of 43 CFR 3104.20 and
3104.30, bonds or bond riders must be
filed in the BLM State office having
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30977
jurisdiction over the lease or operations
covered by the bond or rider.
§ 3104.70
Default.
(a) Where, upon a default, the surety
makes a payment to the United States of
an obligation incurred under a lease, the
face amount of the surety bond or
personal bonds and the surety’s liability
thereunder will be reduced by the
amount of such payment.
(b) After default, where the obligation
in default equals or is less than the face
amount of the bond(s), the principal
must either post a new bond or restore
the existing bond(s) to the amount
previously held or a larger amount as
determined by the authorized officer. In
lieu thereof, the principal may file
separate bonds for each lease covered by
the deficient bond(s). Where the
obligation incurred exceeds the face
amount of the bond(s), the principal
must make full payment to the United
States for all obligations incurred that
are in excess of the face amount of the
bond(s) and must post a new bond in
the amount previously held or such
larger amount as determined by the
authorized officer. The restoration of a
bond or posting of a new bond must be
made within 6 months or less after
receipt of notice from the authorized
officer. Failure to comply with these
requirements may:
(1) Subject all leases covered by such
bond(s) to cancellation under the
provisions of 43 CFR 3108.30; and
(2) Result in the bond obligor or
principal being referred to the
Department’s Suspension and
Debarment Program under 2 CFR part
1400 to determine if the person will be
suspended or debarred from doing
business with the Federal Government.
§ 3104.80
Termination of period of liability.
The authorized officer will not give
consent to termination of the period of
liability of any bond unless an
acceptable replacement bond has been
filed or until all the terms and
conditions of the lease have been met.
§ 3104.90 Unit Operator and nationwide
bonds held prior to June 22, 2024.
Unit operator and nationwide bonds
accepted by the BLM prior to June 22,
2024, must be replaced with individual
lease or statewide bonds by June 22,
2025. The BLM will not accept any new
unit operator or nationwide bonds.
Subpart 3105—Cooperative
Conservation Provisions
§ 3105.10
Cooperative or unit agreement.
(a) The suggested contents of such an
agreement and the procedures for
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obtaining approval are contained in 43
CFR part 3180.
(b) An application to form a unit
agreement, a unit expansion, or a
designation of a successor operator must
include the processing fee found in the
fee schedule in § 3000.120 of this
chapter.
Communitization Agreements
§ 3105.21
Where filed.
(a) An application to form a
communitization agreement or modify
an existing agreement must be filed with
the proper BLM office for final approval.
(b) An application for a
communitization agreement must
include:
(1) A statement as to whether the
proposed communitization agreement
deviates from the BLM’s current model
communitization agreement form, and a
certification that the applicant received
the required signatures;
(2) An Exhibit A displaying a map of
the area covered by the proposed
agreement and the separate agreement
tracts; and
(3) An Exhibit B displaying the
separate tracts and ownership;
(c) To ensure accurate reporting to
ONRR, an application for a
communitization agreement should be
submitted at least 90 calendar days prior
to first production.
(d) An application for designations of
successor operator for a
communitization agreement must
include the processing fee found in the
fee schedule in § 3000.120 of this
chapter.
§ 3105.22
Purpose.
When a lease or a portion thereof
cannot be independently developed and
operated in conformity with an
established well-spacing or welldevelopment program, the authorized
officer may approve a communitization
agreement for such lands with other
lands, whether or not owned by the
United States, upon a determination
that it is in the public interest.
Operations or production under such an
agreement will be deemed to be
operations or production as to each
lease committed thereto.
ddrumheller on DSK120RN23PROD with RULES4
§ 3105.23
Requirements.
(a) The communitization agreement
must describe the separate tracts
comprising the drilling or spacing unit,
must show the apportionment of the
production or royalties to the several
parties, the name of the operator, and
contain adequate provisions for the
protection of the interests of the United
States. The agreement must be signed by
or on behalf of all necessary parties and
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must be filed prior to the expiration of
the Federal lease(s) involved in order to
confer the benefits of the agreement
upon such lease(s).
(b) The agreement will be effective as
to the Federal lease(s) involved only if
approved by the authorized officer.
Approved communitization agreement
are considered effective from the date of
the agreement or from the date of the
onset of production from the
communitized formation, whichever is
earlier, except when the spacing unit is
subject to a State pooling order after the
date of first sale, then the effective date
of the agreement will be the effective
date of the order.
(c) The public interest requirement for
an approved communitization
agreement will be satisfied only if the
well dedicated thereto has been
completed for production in the
communitized formation at the time the
agreement is approved or, if not, that the
operator thereafter commences and/or
diligently continues drilling operations
to a depth sufficient to test the
communitized formation or establishes
to the satisfaction of the authorized
officer that further drilling of the well
would be unwarranted or impracticable.
If an application is received for
voluntary termination of a
communitization agreement during its
fixed term or such an agreement
automatically expires at the end of its
fixed term without the public interest
requirement having been satisfied, the
approval of that agreement by the
authorized officer will be invalid and no
Federal lease included in the
communitization agreement will be
eligible for an extension under 43 CFR
3107.40.
§ 3105.24
terms.
Communitization agreement
The communitization agreement will
remain in effect for a period of 2 years
from the effective date or approval date,
whichever is later, and so long
thereafter as communitized substances
may be produced in paying quantities,
or as otherwise specified in the
agreement.
operations on a scale large enough to
justify the discovery, development,
production or transportation of oil or
gas and to finance the same.
§ 3105.33
Requirements.
The contract must be accompanied by
a statement showing all the interests
held by the contractor in the area or
field and the proposed or agreed plan
for development and operation of the
field. All the contracts held by the same
contractor in the area or field must be
submitted for approval at the same time
and full disclosure of the projects made.
Subsurface Storage of Oil and Gas
§ 3105.41
Where filed.
(a) Applications for subsurface storage
or designations of successor operator
must be filed in the proper BLM office.
(b) The final gas storage agreement
signed by all the parties in interest must
be submitted to the BLM.
(c) Applications for subsurface storage
agreements or designations of successor
operator must include the processing fee
found in the fee schedule in § 3000.120
of this chapter.
§ 3105.42
Purpose.
To avoid waste and to promote
conservation of natural resources, the
Secretary, upon application by the
interested parties, may authorize the
subsurface storage of oil and gas,
whether or not produced from lands
owned by the United States. Such
authorization will provide for the
payment of such storage fee or rental on
the stored oil or gas as may be
determined adequate in each case, or, in
lieu thereof, for a royalty other than that
prescribed in the lease when such
stored oil or gas is produced in
conjunction with oil or gas not
previously produced. The BLM will
require a bond as provided under § 3104
for operations conducted in a subsurface
storage agreement.
§ 3105.43
Requirements.
A contract submitted for approval
under this section must be filed with the
proper BLM office.
The agreement must disclose the
ownership of the lands involved, the
parties in interest, the storage fee, rental
or royalty offered to be paid for such
storage and all information
demonstrating such storage would avoid
waste and promote the conservation of
natural resources.
§ 3105.32
§ 3105.44
Operating, Drilling, or Development
Contracts
§ 3105.31
Where filed.
Purpose.
Approval of operating, drilling or
development contracts will be granted
only to permit operators or pipeline
companies to enter into contracts with
a number of lessees sufficient to justify
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Extension of lease term.
Any lease used for the storage of oil
or gas will be extended for the period
of storage under an approved agreement.
The obligation to pay annual lease rent
continues during the extended period.
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§ 3105.50
Consolidation of leases.
(a) Leases may be consolidated upon
written request of the lessee filed with
the proper BLM office. The request must
identify each lease involved by serial
number and justify the consolidation.
Each request for a consolidation of
leases must include the processing fee
found in the fee schedule in § 3000.120
of this chapter.
(b) All parties holding any undivided
interest in any lease involved in the
consolidation must agree to enter into
the same lease consolidation.
(c) Leases containing different types
of lands (public domain lands vs.
acquired lands), mixed fractional
mineral interest, or provisions required
by law that cannot be reconciled, will
not be consolidated.
(d) Consolidation of leases will not
exceed acreage limits of 2,560 acres for
competitive leases and 10,240 acres for
noncompetitive leases.
(e) The effective date, the anniversary
date, and the primary term of the
consolidated lease will be those of the
oldest original lease included in the
consolidation. The term of a
consolidated lease may be extended
beyond the primary lease term under
subpart 3107.
(f) The highest royalty and rental rates
of the each of the leases to be
consolidated will apply to the
consolidated lease.
(g) Lease stipulations and other terms
and conditions of each original lease,
except as noted in paragraphs (e) and (f)
of this section, will continue to apply to
that lease or any portion thereof
regardless of the lease becoming a part
of a consolidated lease.
Subpart 3106—Transfers by
Assignment, Sublease, or Otherwise
ddrumheller on DSK120RN23PROD with RULES4
§ 3106.10
(a) Leases may be transferred by
assignment or sublease as to all or part
of the acreage in the lease or as to either
a divided or undivided interest therein.
(b) An assignment of the record title
conveys both record title and operating
rights, unless operating rights have been
severed from the record title through an
approved transfer of operating rights.
Thereafter, the operating rights and
record title may each be subject to
further transfers.
(c) An assignment of a separate zone,
deposit, depth, formation, specific well,
or of part of a legal subdivision, will be
denied.
(d) Within the boundaries of a Federal
lease, operating rights may only be
divided with respect to legal
subdivisions, depth ranges, and
formations.
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§ 3106.20 Qualifications of assignees and
transferees.
Assignees and transferees must
comply with the provisions of 43 CFR
subpart 3102 and post any bond that
may be required. Only responsible and
qualified lessees may own, hold, or
control an interest in a lease.
§ 3106.30
Transfers, general.
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(e) An assignment of less than 640
acres outside Alaska or of less than
2,560 acres within Alaska will be
denied unless the assignment
constitutes the entire lease or is
demonstrated to further the
development of oil and gas to the
satisfaction of the authorized officer.
Reference 43 CFR 3102.51(g) for
certification of compliance.
(f) The rights of the transferee to a
lease or an interest therein will not be
recognized by the Department until the
transfer has been approved by the
authorized officer.
(g) A transfer may be withdrawn in
writing, signed by the transferor and the
transferee, if the transfer has not been
approved by the authorized officer.
(h) A request for approval of a transfer
of a lease or interest in a lease must be
filed within 90 days from the date of its
execution. The 90-day filing period will
begin on the date the transferor signs
and dates the transfer. If the transfer is
filed after the 90th day, the authorized
officer may require verification that the
transfer is still in force and effect.
(i) A transfer of production payments
or overriding royalty or other similar
payments, arrangements, or interests
must be filed in the proper BLM office
but will not require approval.
(j) No transfer of an offer to lease or
interest in a lease will be approved prior
to the issuance of the lease.
Fees.
(a) Each transfer of record title or of
operating rights (sublease) for each lease
must include payment of the processing
fee for assignments and transfers found
in the fee schedule in § 3000.120 of this
chapter.
(b) Each transfer of overriding royalty
or payment out of production must
include payment of the processing fee
for overriding royalty transfers or
payments out of productions found in
the fee schedule in § 3000.120 of this
chapter for each lease to which it
applies.
Forms
§ 3106.41 Transfers of record title and of
operating rights (subleases).
Each transfer of record title or of an
operating right (sublease) must be filed
with the proper BLM office on a current
form approved by the Director. A
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30979
separate form for each transfer, in
triplicate, must be filed for each lease
out of which a transfer is made. The
BLM does not require triplicate copies
of the assignment or transfer when it is
electronically submitted. Copies of
documents other than the current form
approved by the Director must not be
submitted. However, reference(s) to
other documents containing information
affecting the terms of the transfer may
be made on the submitted form.
§ 3106.42 Transfers of other interests,
including royalty interests and production
payments.
(a) Each transfer of overriding royalty
interest, payment out of production or
similar interests created or reserved
must be described for each lease on the
current assignment or transfer form
when filed.
(b) A single executed copy of each
such transfer of other interests for each
lease must be filed with the proper BLM
office.
§ 3106.43
Mass transfers.
(a) A mass transfer may be utilized in
lieu of the provisions of 43 CFR 3106.41
and 3106.42 when an assignor or
transferor transfers interests of any type
in more than one Federal lease to the
same assignee or transferee.
(b) The mass transfer must be filed
with each proper BLM office
administering any lease affected by the
mass transfer. The transfer must be on
a current form approved by the Director
with an exhibit attached to each copy
listing the following for each lease:
(1) The serial number;
(2) The type and percent of interest
being conveyed; and
(3) A description of the lands affected
by the transfer in accordance with 43
CFR 3106.50.
(c)(1) One duplicate copy of the form
must be filed with the proper BLM
office for each lease involved in the
mass transfer. A copy of the exhibit for
each lease may be limited to line items
pertaining to individual leases as long
as that line item includes the
information required by paragraph (b) of
this section. The BLM does not require
a duplicate copy of the assignment or
transfer when it is electronically
submitted.
(2) When the BLM does not receive
the requisite number of copies, the
applicant must reimburse the BLM for
the full costs incurred to make the
required number of copies. The BLM
will waive fees under one dollar.
(d) A mass transfer must include the
processing fee for assignments and
transfers found in the fee schedule in
§ 3000.120 of this chapter for each such
interest transferred for each lease.
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§ 3106.50
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Description of lands.
Each assignment of record title must
describe the lands involved in the same
manner as the lands are described in the
lease, except no land description is
required when 100 percent of the entire
area encompassed within a lease is
conveyed.
§ 3106.60
Bond requirements.
Where the lessee or operating rights
owner (sublessee) maintains a bond
covering the lease, the assignee of
record title interest or transferee of
operating rights in such lease must
furnish, if bond coverage continues to
be required, a proper bond that will
cover any obligations arising under the
lease to the same extent as the assignor’s
or transferor’s bond.
Approval of Transfer or Assignment
§ 3106.71
§ 3106.72 Continuing obligation of an
assignor or transferor.
(a) The lessee or sublessee remains
responsible for performing all
obligations under the lease until the
date the BLM approves an assignment of
record title interest or transfer of
operating rights.
(b) After the BLM approves the
assignment or transfer, the assignor or
transferor will continue to be
responsible for lease obligations that
accrued before the approval date,
whether or not such obligations were
identified at the time of the assignment
or transfer. This includes paying
compensatory royalties for drainage. It
also includes responsibility for plugging
wells drilled and removing facilities
installed or used before the effective
date of the assignment or transfer.
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Effective date of transfer.
The signature of the authorized officer
on the official form will constitute
approval of the assignment of record
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Effect of transfer.
An assignment of record title to 100
percent of a portion of the lease
segregates the transferred portion and
the retained portion into separate leases.
Each resulting lease retains the
anniversary date and the terms and
conditions of the original lease. An
assignment of record title to less than
100 percent of a portion of the lease or
a transfer of operating rights (sublease)
will not segregate the transferred and
retained portions into separate leases.
Jkt 262001
(a) The assignee of record title agrees
to comply with the terms of the original
lease during the lease tenure. The
assignee assumes the responsibility to
plug and abandon all wells which are
no longer capable of producing, reclaim
the lease site, and remedy all
environmental problems in existence
and that a purchaser exercising
reasonable diligence should have
known existed at the time of the
transfer. When required, the record title
holder must also maintain an adequate
bond to ensure performance of these
responsibilities.
(b) The transferee of operating rights
agrees to comply with the terms of the
original lease as it applies to the area or
horizons for the interest acquired. The
transferee assumes the responsibility to
plug and abandon all wells that are no
longer capable of producing, reclaim the
lease site, and remedy all environmental
problems in existence and that a
purchaser exercising reasonable
diligence should have known existed at
the time of the transfer. When required,
the operating rights holder must also
maintain an adequate bond to ensure
performance of these responsibilities.
Other Types of Transfers
§ 3106.81
Lease account status.
The BLM will not approve a transfer
if the lease account is delinquent with
respect to: royalty payments; lease
obligations, such as, but not limited to,
rent and minimum royalty; or
production reporting to ONRR for a
lease in non-terminable status.
§ 3106.74
§ 3106.75
§ 3106.76 Obligations of assignee or
transferee.
Failure to qualify.
The BLM will not approve any
assignment of record title or transfer of
operating rights (sublease) if any party
in interest is not a qualified lessee, or if
the bond is insufficient. The BLM
approves assignments and transfers for
administrative purposes only. Approval
does not warrant or certify that either
party to a transfer holds legal or
equitable title to a lease.
§ 3106.73
title or transfer of operating rights
(sublease) which will take effect as of
the first day of the lease month
following the date of filing in the proper
BLM office of all documents and
statements required by this subpart and
an appropriate bond, if one is required.
Heirs and devisees.
(a) If an offeror, applicant, lessee or
transferee dies, their rights would be
assigned or transferred to the heirs,
devisees, executor or administrator of
the estate, as appropriate, upon the
filing of legal documents demonstrating
that the assignee or transferee is
recognized as the successor of the
deceased.
(b) The filing must include the
processing fee for the transfer to an heir/
devisee found in the fee schedule in
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§ 3000.120 of this chapter with the
request to assign lease rights.
(c) The filing must include a
qualification statement demonstrating
qualification to hold an interest in a
lease in accordance with 43 CFR subpart
3102. Any ownership or interest
otherwise forbidden by the regulations
in this part which may be acquired by
descent, will, judgment or decree may
be held for a period not to exceed 2
years after its acquisition. Any such
forbidden ownership or interest held for
a period of more than 2 years after
acquisition may be subject to
cancellation.
(d) A bond rider or replacement bond
may be required for any bond(s)
previously furnished by the decedent.
§ 3106.82
Change of name.
(a) A legally recognized change of
name of a lessee or sublessee must be
reported to the proper BLM office. The
notice of name change must be
submitted in writing with adequate
information concerning the name
change. For a corporate name change,
the request must include the Secretary
of State’s Certificate of Name Change,
along with the Articles of Incorporation,
or Amendment, if available.
(b) An entity must include with the
notice of name change the required
processing fee listed in the fee schedule
in § 3000.120 of this chapter.
(c) If a bond(s) has been furnished, a
change of name on the bond may be
made by surety consent or a rider to the
original bond or by a replacement bond.
§ 3106.83 Corporate mergers and
dissolution of corporations, partnerships,
and trusts.
(a) In the event a corporate merger
affects leases where property of the
dissolving corporation to the surviving
corporation is accomplished by
operation of law, an assignment of any
affected lease interest is not required.
An entity must notify the BLM of the
merger and provide copies of the
Secretary of State’s Certificate of Merger,
along with the Articles of Incorporation,
or Amendment, if available, to the BLM.
(b) The BLM will not recognize any
transfers provided by the Articles of
Dissolution unless an entity has filed
with the BLM a Certificate of
Dissolution of an incorporated entity,
certified as accepted by the State where
the entity was incorporated.
(c) An entity must file with the BLM
a dissolution of a partnership or trust
through an order or decree that
authorizes settlement, discharge, and
distribution of the lease holdings and/or
interests for official recognition of the
assignment of lease interests.
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(d) An entity must include the
processing fee for corporate merger or
dissolution of corporation, partnership,
or trust found in the fee schedule in
§ 3000.120 of this chapter.
(e) The authorized officer may require
a bond rider or replacement bond for all
affected corporations, partnerships or
trusts.
§ 3106.84
Sheriff’s sale/deed.
(a) Where a notice of sale of the
leasehold interest is published pursuant
to State law applicable to the execution
of sales of real property, the purchaser
must submit a copy of the Sheriff’s
Certificate of Sale to the proper BLM
office after any redemption period has
passed.
(b) When submitting the certificate
described in paragraph (a), an entity
must include the processing fee for
sheriff’s deed found in the fee schedule
in § 3000.120 of this chapter.
(c) The purchaser(s) must file a
qualification statement to hold an
interest in a lease in accordance with 43
CFR subpart 3102. Failure to provide a
qualification statement after 2 years will
result in the BLM cancelling the lease or
interest.
(d) If a bond has been furnished by
the previous interest holder, the
authorized officer may require a new
bond.
Subpart 3107—Continuation and
Extension
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§ 3107.10
Extension by drilling.
(a) Any lease on which actual drilling
operations were commenced prior to the
end of its primary term and are being
diligently prosecuted at the end of the
primary term or any lease which is part
of an approved oil and gas agreement
upon which such drilling takes place,
will be extended for 2 years subject to
the rental being timely paid as required
by 43 CFR 3103.20, and subject to the
provisions of 43 CFR 3105.23 and
appendix A to part 3180, if applicable.
The BLM will not grant a drilling
extension for a lease in its extended
term.
(b) Actual drilling operations must be
conducted in a manner that a reasonable
person seriously looking for oil or gas
could be expected to make in that
particular area, given the existing
knowledge of geologic and other
pertinent facts. In drilling a new well on
a lease or for the benefit of a lease under
the terms of an approved agreement, it
must be taken to a depth sufficient to
penetrate at least one formation
recognized in the area as potentially
productive of oil or gas, or where an
existing well is reentered, it must be
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taken to a depth sufficient to penetrate
at least one new and deeper formation
recognized in the area as potentially
productive of oil or gas. The authorized
officer may determine that further
drilling is unwarranted or
impracticable.
(c) When a BLM-approved directional
or horizontal well is drilled within the
leased area from an off-lease location
with the intent to produce from the
leased area, the BLM will consider
drilling to have commenced on the
leased area when drilling is commenced
at the off-lease location.
Production
§ 3107.21
Continuation by production.
A lease will be extended so long as oil
or gas is being produced in paying
quantities.
§ 3107.22
Cessation of production.
A lease in its extended term because
of production (and lacking a well
capable of production in paying
quantities) will not expire upon
cessation of production, if, within 60
calendar days of cessation of
production, reworking or drilling
operations on the leasehold are
commenced and are thereafter
conducted with reasonable diligence
during the period of nonproduction. If
these reworking or drilling operations
fail to result in production in paying
quantities, the lease will expire by
operation of law, effective as of the date
paying production ceased.
§ 3107.23
Leases capable of production.
No lease for lands on which there is
a well capable of producing oil or gas
in paying quantities will expire because
the lessee fails to produce the same,
unless the lessee fails to place the lease
in production within a period of not less
than 60 calendar days as specified by
the authorized officer after receipt of
notice by certified mail from the
authorized officer to do so. Such
production must be continued unless
and until suspension of production is
granted by the authorized officer.
Extension of Leases Within Agreements
§ 3107.31 Leases committed to an
agreement.
(a) Any lease or portion of a lease
committed to an oil and gas agreement
that contains a general provision for
allocation of oil or gas will continue in
effect so long as the lease or portion
thereof remains subject to the
agreement; provided, that there is
production of oil or gas in paying
quantities under the agreement prior to
the expiration date of such lease.
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30981
(b) A well that is drilled and
completed on a lease committed to a
unit agreement, and that is capable of
production in paying quantities on a
lease basis, will extend the term of all
expiring Federal leases committed to the
unit agreement for the term of the unit
agreement and so long as the well is
capable of production in paying
quantities.
§ 3107.32
in part.
Segregation of leases committed
(a) Any lease committed after July 29,
1954, to any unit agreement, which
covers lands within and lands outside
the area covered by the agreement, will
be segregated, as of the effective date of
commitment to the unit, into separate
leases; one covering the lands
committed to the agreement, the other
lands not committed to the agreement.
For unproven areas, such segregation
will occur only when the public interest
requirement is satisfied pursuant to 43
CFR 3183.4(b). Upon satisfaction of the
public interest requirement, the BLM
will deem the segregation to have been
effective as of the date of commitment
of the lands to the unit.
(b)(1) The segregated lease covering
the non-unitized portion of the lands
will continue in force and effect for the
term of the lease or for 2 years from the
date of segregation, whichever is longer.
(2) If a partially committed lease is in
an extended term because of
production, the segregated, nonproducing lease will continue in effect
so long as the producing lease exists and
rentals are paid, and so long thereafter
as oil or gas is produced from the
committed lease.
§ 3107.40
Extension by elimination.
Any lease eliminated from any
approved or prescribed oil and gas
agreement authorized by the Act and
any lease in effect at the termination of
such agreement, unless relinquished,
will continue in effect for the original
term of the lease or for 2 years after its
elimination from the agreement or after
the termination of the plan or
agreement, whichever is longer, and for
so long thereafter as oil or gas is
produced in paying quantities. No lease
will be extended if the public interest
requirement for an approved oil and gas
agreement has not been satisfied, as
determined by the authorized officer.
Extension of Leases Segregated by
Assignment
§ 3107.51 Extension after discovery on
other segregated portions.
Any lease segregated by assignment,
including the retained portion, will
continue in effect for the primary term
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of the original lease, or for 2 years after
the date a well capable of production in
paying quantities is established upon
any other portion of the original lease,
whichever is the longer period.
§ 3107.52 Undeveloped parts of leases in
their extended term.
Undeveloped parts of leases retained
or assigned out of leases which are in
their extended term will continue in
effect for 2 years after the effective date
of assignment, provided the parent lease
was issued prior to September 2, 1960.
§ 3107.53
leases.
Undeveloped parts of producing
Undeveloped parts of leases retained
or assigned out of leases which are
extended by production, actual or
suspended, or the payment of
compensatory royalty will continue in
effect for 2 years after the effective date
of assignment and for so long thereafter
as oil or gas is produced in paying
quantities.
§ 3107.60
Extension of reinstated leases.
Where a reinstatement of a terminated
lease is granted under 43 CFR 3108.20
and the authorized officer finds that the
reinstatement will not afford the lessee
a reasonable opportunity to continue
operations under the lease, the
authorized officer may extend the term
of such lease for a period sufficient to
give the lessee such an opportunity.
Any extension will be subject to the
following conditions:
(a) No extension will exceed a period
equal to the unexpired portion of the
lease or any extension thereof remaining
at the date of termination.
(b) When the reinstatement occurs
after the expiration of the term or
extension thereof, the lease may be
extended from the date the authorized
officer grants the petition, but in no
event for more than 2 years from the
date the reinstatement is authorized and
so long thereafter as oil or gas is
produced in paying quantities.
Other Extension Types
ddrumheller on DSK120RN23PROD with RULES4
§ 3107.71
royalty.
Payment of compensatory
The payment of a compensatory
royalty will extend the term of any lease
for the period during which such
compensatory royalty is paid and for a
period of 1 year from the
discontinuance of such payments.
§ 3107.72
gas.
Subsurface storage of oil and
Any lease used for the storage of oil
or gas will be extended for the period
of storage under an approved agreement.
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Subpart 3108—Relinquishment,
Termination, Cancellation
§ 3108.10
Relinquishment.
The lessee(s) may relinquish the lease
or any legal subdivision of the lease at
any time. The lessee(s) must file a
written relinquishment with the BLM
State Office with jurisdiction over the
lease. All lessees holding record title
interests in the lease must sign the
relinquishment. A relinquishment takes
effect on the date the lessee filed it with
the BLM. However, the lessee(s) and the
party that issued the bond will continue
to be obligated to:
(a) Make payments of all accrued
rentals and royalties, including
payments of compensatory royalty due
for all drainage that occurred before the
relinquishment;
(b) Place all wells to be relinquished
in condition for suspension or
abandonment as the BLM requires; and
(c) Complete reclamation of the leased
sites after stopping or abandoning oil
and gas operations on the lease, under
a plan approved by the BLM or the
appropriate surface management
agency.
Termination by Operation of Law and
Reinstatement
§ 3108.21
Automatic termination.
(a) Except as provided in paragraph
(b) of this section, any lease on which
there is no well capable of producing oil
or gas in paying quantities will
automatically terminate by operation of
law (30 U.S.C. 188) if the lessee fails to
pay the rental at the designated ONRR
office on or before the lease anniversary
date. However, if the designated ONRR
office is closed on the anniversary date,
a rental payment received on the next
business day the ONRR office is open to
the public will be considered timely
made.
(b) If the rental payment due under a
lease is paid on or before its anniversary
date but the amount of the payment is
deficient and the deficiency is nominal
as defined in this section, or the amount
of payment made was determined in
accordance with the rental or acreage
figure stated in a decision rendered by
the authorized officer, and such figure is
found to be in error resulting in a
deficiency, such lease will not have
automatically terminated unless the
lessee fails to pay the deficiency within
the period prescribed in the Notice of
Deficiency provided for in this section.
A deficiency will be considered
nominal if it is not more than $100 or
more than 5 percent of the total
payment due, whichever is less. The
designated ONRR office will send a
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Notice of Deficiency to the lessee. The
Notice will allow the lessee 15 days
from the date of receipt or until the due
date, whichever is later, to submit the
full balance due to the designated ONRR
office. If the payment required by the
Notice is not paid within the time
allowed, the lease will have terminated
by operation of law as of its anniversary
date.
(c) The automatic termination
provision does not apply where, due to
other contingencies, additional rental is
due on a date other than the lease
anniversary date and where the lessee
did not receive notice that the obligation
had accrued, unless the lessee fails to
pay the rental within the period
prescribed in the BLM Notice.
§ 3108.22 Reinstatement at existing rental
and royalty rates: Class I reinstatements.
(a) Except as hereinafter provided, the
authorized officer may reinstate a lease
which has terminated for failure to pay
on or before the anniversary date the
full amount of rental due, provided that:
(1) Such rental was paid or tendered
within 20 days after the anniversary
date; and
(2) It is shown to the satisfaction of
the authorized officer that the failure to
timely submit the full amount of the
rental due was either justified or not
due to a lack of reasonable diligence on
the part of the lessee (reasonable
diligence includes a rental payment that
is paid to the ONRR on or before the
lease anniversary date. If the designated
ONRR office or payment system is not
operational on the anniversary date,
payment received on the next business
day in which the designated ONRR
office or payment system is operational
to the public will be deemed timely);
and
(3) A petition for reinstatement and
the processing fee for lease
reinstatement, Class I, found in the fee
schedule in § 3000.120 of this chapter,
are filed with the proper BLM office
within 60 days after receipt of Notice of
Termination of Lease due to late
payment of rental. If a terminated lease
becomes productive prior to the time
the lease is reinstated, all required
royalty that has accrued must be paid to
the ONRR.
(b) The burden of showing that the
failure to pay on or before the
anniversary date was justified or not
due to lack of reasonable diligence is on
the lessee.
(c) Under no circumstances will a
terminated lease be reinstated if:
(1) A valid oil and gas lease has been
issued prior to the filing of a petition for
reinstatement affecting any of the lands
covered by that terminated lease; or
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(2) The oil and gas interests of the
United States in the lands have been
disposed of or otherwise have become
unavailable for leasing.
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§ 3108.23 Reinstatement at higher rental
and royalty rates: Class II reinstatements.
(a) The authorized officer may, if the
requirements of this section are met,
reinstate a competitive oil and gas lease
which was terminated by operation of
law for failure to pay rental timely when
the rental was not paid or tendered
within 20 calendar days of the
termination date, and it is shown to the
satisfaction of the authorized officer that
such failure was justified or not due to
a lack of reasonable diligence, or no
matter when the rental was paid, it is
shown to the satisfaction of the
authorized officer that such failure was
inadvertent.
(b)(1) Such leases may be reinstated if
the required back rental and royalty at
the increased rates accruing from the
date of termination, together with a
petition for reinstatement, are filed on
or before the earlier of:
(i) Sixty calendar days after the last
date that any lessee of record received
Notice of Termination by certified mail;
or
(ii) Twenty-four months after
termination of the lease.
(2) After determining that the
requirements for filing of the petition for
reinstatement have been timely met, the
authorized officer may reinstate the
lease if:
(i) No valid lease has been issued
prior to the filing of the petition for
reinstatement affecting any of the lands
covered by the terminated lease,
whether such lease is still in effect or
not;
(ii) The oil and gas interests of the
United States in the lands have not been
disposed of or have not otherwise
become unavailable for leasing;
(iii) Payment of all back rentals and
royalties at the rates established for the
reinstated lease has been made;
(iv) An agreement has been signed by
the lessee and attached to and made a
part of the lease specifying future
rentals at the applicable rates specified
for reinstated leases in 43 CFR 3103.22
and future royalties at the rates set in 43
CFR 3103.31 for all production removed
or sold from such lease or shared by
such lease from production allocated to
the lease by virtue of its participation in
an oil and gas agreement;
(v) A notice of the proposed
reinstatement of the terminated lease
and the terms and conditions of
reinstatement has been published in the
Federal Register at least 30 days prior
to the date of reinstatement for which
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the lessee must reimburse the BLM for
the full costs incurred in the publishing
of said notice; and
(vi) The lessee has paid the BLM a
nonrefundable administrative fee of
$500.
(c) The authorized officer will furnish
to the Chairpersons of the Committee on
Natural Resources of the House of
Representatives and of the Committee
on Energy and Natural Resources of the
Senate, at least 30 days prior to the date
of reinstatement, a copy of the notice,
together with information concerning
rental, royalty, volume of production, if
any, and any other matter which the
authorized officer considers significant
in making the determination to
reinstate.
(d) If the authorized officer reinstates
the lease, the reinstatement will be
effective as of the date of termination,
for the unexpired portion of the original
lease or any extension thereof remaining
on the date of termination, and so long
thereafter as oil or gas is produced in
paying quantities. Where a lease is
reinstated under this section and the
authorized officer finds that the
reinstatement of such lease either:
(1) Occurs after the expiration of the
primary term or any extension thereof;
or
(2) Will not afford the lessee a
reasonable opportunity to continue
operations under the lease, the
authorized officer may extend the term
of the reinstated lease for such period as
determined reasonable, but in no event
for more than 2 years from the date of
the reinstatement and so long thereafter
as oil or gas is produced in paying
quantities.
§ 3108.30
Cancellation.
(a) Whenever the lessee fails to
comply with any of the provisions of the
law, the regulations issued thereunder,
or the lease, the lease may be canceled
by the Secretary, if the leasehold does
not contain a well capable of production
of oil or gas in paying quantities, or if
the lease is not committed to an
approved oil and gas agreement that
contains a well capable of production of
unitized substances in paying
quantities. The lease may be canceled
only if the default continues for 30
calendar days after a notice of default
has been delivered in accordance with
43 CFR 1810.2.
(b) Whenever the lessee fails to
comply with any of the provisions of the
law, the regulations issued thereunder,
or the lease, and if the leasehold
contains a well capable of production of
oil or gas in paying quantities, or if the
lease is committed to an approved oil
and gas agreement that contains a well
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30983
capable of production of unitized
substances in paying quantities, the
lease may be canceled only by court
order in the manner provided by section
31(a) of the Act (30 U.S.C. 188).
(c) If any interest in any lease is
owned or controlled, directly or
indirectly, by means of stock or
otherwise, in violation of any of the
provisions of the Act, the lease may be
canceled, or the interest so owned may
be forfeited, or the person so owning or
controlling the interest may be
compelled to dispose of the interest,
only by court order in the manner
provided by section 27(h)(1) of the Act
(30 U.S.C. 184).
(d) Leases will be subject to
cancellation if improperly issued.
§ 3108.40
Bona fide purchasers.
A lease or interest therein may not be
cancelled to the extent that such action
adversely affects the title or interest of
a bona fide purchaser even though such
lease or interest, when held by a
predecessor in title, may have been
subject to cancellation. All purchasers
will be charged with constructive notice
as to all pertinent regulations and all
BLM records pertaining to the lease and
the lands covered by the lease. Prompt
action may be taken to dismiss as a
party to any proceedings with respect to
a violation by a predecessor of any
provisions of the Act, any person who
shows the holding of an interest as a
bona fide purchaser without having
violated any provisions of the Act. No
hearing will be necessary upon such
showing unless prima facie evidence is
presented that the purchaser is not a
bona fide purchaser.
§ 3108.50
rights.
Waiver or suspension of lease
If, during any proceeding with respect
to a violation of any provision of the
regulations in 43 CFR parts 3000 and
3100 or the Act, a party thereto files a
waiver of his/her rights under the lease
to drill or to assign his/her lease
interests, or if such rights are suspended
by order of the Secretary pending a
decision, payments of rentals and the
running of time against the term of the
lease involved will be suspended as of
the first day of the month following the
filing of the waiver or the Secretary’s
suspension until the first day of the
month following the final decision in
the proceeding or the revocation of the
waiver or suspension.
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Subpart 3109—Leasing under Special
Acts
Rights-of-Way
§ 3109.11
Generally.
The Act of May 21, 1930 (30 U.S.C.
301–306), authorizes either the leasing
of oil and gas deposits under railroad
and other rights-of-way to the owner of
the right-of-way or the entering of a
compensatory royalty agreement with
adjoining landowners. This authority
will be exercised only with respect to
railroad rights-of-way and easements
issued pursuant either to the Act of
March 3, 1875 (43 U.S.C.934 et seq.), or
pursuant to earlier railroad right-of-way
statutes, and with respect to rights-ofway and easements issued pursuant to
the Act of March 3, 1891 (43 U.S.C. 946
et seq.). The oil and gas underlying any
other right-of-way or easement is
included within any oil and gas lease
issued pursuant to the Act which covers
the lands within the right-of-way,
subject to the limitations on use of the
surface, if any, set out in the statute
under which, or permit by which, the
right-of-way or easement was issued,
and such oil and gas will not be leased
under the Act of May 21, 1930.
ddrumheller on DSK120RN23PROD with RULES4
§ 3109.12
Application.
(a) No approved form is required for
an application to lease oil and gas
deposits underlying a right-of-way.
(b) The right-of-way owner or his/her
transferee must file the application in
the proper BLM office.
(c) Include the processing fee for
leasing under right-of-way found in the
fee schedule in § 3000.120 of this
chapter.
(d) An application must include:
(1) Facts as to the ownership of the
right-of-way, and of the transfer if the
application is filed by a transferee;
(2) An executed transfer of the right
to obtain a lease, if necessary;
(3) A description of the development
of oil or gas in adjacent or nearby lands,
the location and depth of the wells, the
production and the probability of
drainage of the deposits in the right-ofway;
(4) A description of each legal
subdivision through which a portion of
the right-of-way desired to be leased
traverses; however, a description by
metes and bounds of the right-of-way is
not required; and
(5) A map of the applicable lands.
§ 3109.13
Notice.
After the BLM has determined that a
lease of a right-of-way or any portion
thereof is consistent with the public
interest, either upon consideration of an
application for lease or on its own
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motion, the authorized officer will serve
notice on the owner or lessee of the oil
and gas rights of the adjoining lands.
The adjoining landowner or lessee will
be allowed a reasonable time, as
provided in the notice, within which to
submit a bid for the percent of
compensatory royalty, the owner or
lessee must pay for the extraction of the
oil and gas underlying the right-of-way
through wells on such adjoining lands.
The owner of the right-of-way will be
given the same time period to submit a
bid for the lease.
§ 3109.14 Award of lease or compensatory
royalty agreement.
Award of lease to the owner of the
right-of-way, or a contract for the
payment of compensatory royalty by the
owner or lessee of the adjoining lands
will be made to the bidder whose offer
is determined by the authorized officer
to be to the best advantage of the United
States, considering the amount of
royalty to be received and the better
development under the respective
means of production and operation.
§ 3109.15 Compensatory royalty
agreement or lease.
(a) The lease or compensatory royalty
agreement will be on a form approved
by the Director.
(b) The primary term of the lease will
be for a period of 10 years.
(c) The following provisions of 43
CFR part 3100 apply to the issuance and
administration of leases for oil and gas
deposits underlying a right-of-way
issued under this part:
(1) All of subpart 3101, except
§§ 3101.21, 3101.22, 3101.23, 3101.24,
and 3101.25; and
(2) All of subparts 3102 through 3108;
§ 3109.20
System.
Units of the National Park
(a) Oil and gas leasing in units of the
National Park System will be governed
by 43 CFR part 3100 and all operations
conducted on a lease or permit in such
units will be governed by 43 CFR parts
3160 and 3180.
(b) Any lease or permit respecting
minerals in units of the National Park
System may be issued or renewed only
with the consent of the Regional
Director, National Park Service. Such
consent will only be granted upon a
determination by the Regional Director
that the activity permitted under the
lease or permit will not have significant
adverse effect upon the resources or
administration of the unit pursuant to
the authorizing legislation of the unit.
Any lease or permit issued will be
subject to such conditions as may be
prescribed by the Regional Director to
protect the surface and significant
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resources of the unit, to preserve their
use for public recreation, and to the
condition that site specific approval of
any activity on the lease will only be
given upon concurrence by the Regional
Director. All lease applications received
for reclamation withdrawn lands will
also be submitted to the Bureau of
Reclamation for review.
(c) The units subject to the regulations
in this part are those units of land and
water which are shown on the following
maps on file and available for public
inspection in the office of the Director
of the National Park Service and in the
Superintendent’s Office of each unit.
The boundaries of these units may be
revised by the Secretary as authorized in
the Acts.
(1) Lake Mead National Recreation
Area—The map identified as ‘‘boundary
map, 8360–80013B, revised February
1986.
(2) Whiskeytown Unit of the
Whiskeytown-Shasta-Trinity National
Recreation Area—The map identified as
‘‘Proposed Whiskeytown-Shasta-Trinity
National Recreation Area,’’ numbered
BOR–WST 1004, dated July 1963.
(3) Ross Lake and Lake Chelan
National Recreation Areas—The map
identified as ‘‘Proposed Management
Units, North Cascades, Washington,’’
numbered NP–CAS–7002, dated
October 1967.
(4) Glen Canyon National Recreation
Area—the map identified as ‘‘boundary
map, Glen Canyon National Recreation
Area,’’ numbered GLC–91,006, dated
August 1972.
(d) The following excepted units will
not be open to mineral leasing:
(1) Lake Mead National Recreation
Area. (i) All waters of Lakes Mead and
Mohave and all lands within 300 feet of
those lakes measured horizontally from
the shoreline at maximum surface
elevation;
(ii) All lands within the unit of
supervision of the Bureau of
Reclamation around Hoover and Davis
Dams and all lands outside of resource
utilization zones as designated by the
Superintendent on the map (602–2291B,
dated October 1987) of Lake Mead
National Recreation Area which is
available for inspection in the Office of
the Superintendent.
(2) Whiskeytown Unit of the
Whiskeytown-Shasta-Trinity National
Recreation Area. (i) All waters of
Whiskeytown Lake and all lands within
1 mile of that lake measured from the
shoreline at maximum surface elevation;
(ii) All lands classified as highdensity recreation, general outdoor
recreation, outstanding natural and
historic, as shown on the map
numbered 611–20,004B, dated April
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1979, entitled ‘‘Land Classification,
Whiskeytown Unit, WhiskeytownShasta-Trinity National Recreation
Area.’’ This map is available for public
inspection in the Office of the
Superintendent;
(iii) All lands within section 34 of
Township 33 north, Range 7 west, Mt.
Diablo Meridian.
(3) Ross Lake and Lake Chelan
National Recreation Areas. (i) All of
Lake Chelan National Recreation Area;
(ii) All lands within 1⁄2 mile of Gorge,
Diablo and Ross Lakes measured from
the shoreline at maximum surface
elevation;
(iii) All lands proposed for or
designated as wilderness;
(iv) All lands within 1⁄2 mile of State
Highway 20;
(v) Pyramid Lake Research Natural
Area and all lands within 1⁄2 mile of its
boundaries.
(4) Glen Canyon National Recreation
Area. Those units closed to mineral
disposition within the natural zone,
development zone, cultural zone and
portions of the recreation and resource
utilization zone as shown on the map
numbered 80,022A, dated March 1980,
entitled ‘‘Mineral Management Plan—
Glen Canyon National Recreation Area.’’
This map is available for public
inspection in the Office of the
Superintendent and the office of the
BLM State Offices, Arizona and Utah.
Lease Terms
3120.21 Duration of lease.
3120.22 Dating of leases.
3120.23 Lease size.
§ 3109.30 Shasta and Trinity Units of the
Whiskeytown-Shasta-Trinity National
Recreation Area.
All lands eligible and available for
leasing may be offered for competitive
auction under this subpart, including
but not limited to:
(a) Lands that were covered by
previously issued oil and gas leases that
have terminated, expired, been
cancelled or relinquished;
(b) Lands for which authority to lease
has been delegated from the General
Services Administration;
(c) If, in proceeding to cancel a lease,
interest in a lease, option to acquire a
lease or an interest therein, acquired in
violation of any of the provisions of the
Act, an underlying lease, interest or
option in the lease is cancelled or
forfeited through a bankruptcy or
otherwise to the United States and there
are valid interests therein that are not
subject to cancellation, forfeiture, or
compulsory disposition, such
underlying lease, interest, or option may
be sold to the highest responsible and
qualified bidder by competitive bidding
under this subpart, subject to all
outstanding valid interests therein and
valid options pertaining thereto. If less
than the whole interest in the lease,
interest, or option is cancelled or
forfeited, such partial interest may
likewise be sold by competitive bidding.
Section 6 of the Act of November 8,
1965 (Pub. L. 89–336), authorizes the
Secretary to permit the removal of oil
and gas from lands within the Shasta
and Trinity Units of the WhiskeytownShasta-Trinity National Recreation Area
in accordance with the Act or the
Mineral Leasing Act for Acquired
Lands. Subject to the determination by
the Secretary of Agriculture that
removal will not have significant
adverse effects on the purposes of the
Central Valley project or the
administration of the recreation area.
PART 3110 [REMOVED]
3. Under the authority of 30 U.S.C.
189, part 3110 is removed.
■ 4. Revise part 3120 to read as follows:
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■
PART 3120—COMPETITIVE LEASES
Sec.
General
3120.11 Lands available for competitive
leasing.
3120.12 Requirements.
3120.13 Protests.
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Expressions of Interest
3120.31 Expression of interest process.
3120.32 Expression of interest leasing
preference.
3120.33 Agency inventory of leasing.
Notice of Competitive Lease Sale
3120.41 General.
3120.42 Posting timeframes.
Competitive Auction
3120.51 Competitive auction.
3120.52 Payments required.
3120.53 Award of lease.
3120.60 Parcels not bid on at auction.
Future Interest
3120.71 Expression of interest to make
lands available for competitive lease.
3120.72 Future interest terms and
conditions.
3120.73 Compensatory royalty agreements.
PART 3120—COMPETITIVE LEASES
Authority: 16 U.S.C. 3101 et seq.; 30
U.S.C. 181 et seq. and 351–359; 40 U.S.C. 471
et seq.; 43 U.S.C. 1701 et seq.; Pub. L. 113–
291, 128 Stat. 3762; and the Attorney
General’s Opinion of April 2, 1941 (40 Op.
Atty. Gen. 41).
General
§ 3120.11
leasing.
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30985
If no satisfactory bid is obtained as a
result of the competitive offering of such
whole or partial interests, such interests
may be sold in accordance with 30
U.S.C. 184(h)(2) by such other methods
as the authorized officer deems
appropriate, but on terms no less
favorable to the United States than those
of the best competitive bid received.
Interest in outstanding leases(s) so sold
will be subject to the terms and
conditions of the existing lease(s);
(d) Lands which are otherwise
unavailable for leasing but which are
subject to drainage (protective leasing);
(e) Lands included in any expression
of interest submitted to the authorized
officer;
(f) Lands selected by the authorized
officer; and
(g) Lands that were offered on a
previous sale for which no bid was
accepted or received.
§ 3120.12
Requirements.
(a) Each BLM state office will hold
sales at least quarterly if eligible lands
are available for competitive leasing.
(b) Lease sales will be conducted by
a competitive auction process.
(c) The BLM may issue a lease only
to the highest responsible and qualified
bidder. If a person does not pay the
minimum monies owed the day of the
sale, the BLM may refer that person to
the Department of the Interior’s Office of
the Inspector General, Administrative
Remedies Division, for appropriate
action, including potential suspension
and debarment.
(d) The national minimum acceptable
bid will be as specified in § 3103.1 of
this chapter and payable on the gross
acreage and will not be prorated for any
lands in which the United States owns
a fractional interest.
§ 3120.13
Protests.
(a) No action pursuant to the
regulations in this subpart will be
suspended under 43 CFR 4.21(a) due to
a protest from a notice by the authorized
officer to hold a lease sale.
(b) Notwithstanding paragraph (a) of
this section, the authorized officer may
suspend the offering of a specific parcel
while considering a protest against its
inclusion in a Notice of Competitive
Lease Sale.
(c) Only the Assistant Secretary for
Land and Minerals Management may
suspend a lease sale for good cause after
reviewing the reason(s) for a protest.
Lease Terms
§ 3120.21
Duration of lease.
Competitive leases will be issued for
a primary term of 10 years.
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§ 3120.22
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Dating of leases.
All competitive leases will be
considered issued when signed by the
authorized officer. Competitive leases,
except future interest leases issued
under § 3120.80, will be effective as of
the first day of the month following the
date the leases are signed on behalf of
the United States. A lease may be made
effective on the first day of the month
within which it is issued if a written
request is made prior to the date of
signature of the authorized officer.
Leases for future interest will be
effective as of the date the mineral
interests vest in the United States.
§ 3120.23
Lease size.
Lands may be offered in leasing units
of not more than 2,560 acres outside
Alaska, or 5,760 acres within Alaska,
which may be as nearly compact in form
as possible.
Expressions of Interest
ddrumheller on DSK120RN23PROD with RULES4
§ 3120.31
Expression of interest process.
(a) A party submitting an expression
of interest in leasing land available for
disposition under section 17 of the
Mineral Leasing Act must include the
submitter’s name and address and must
submit the expression of interest
through the BLM’s online leasing
system.
(b) The expression must provide a
description of the lands identified by
legal land description, as follows:
(1) For lands surveyed under the
public land survey system, describe the
lands to the nearest aliquot part within
the legal subdivision, section, township,
range, and meridian;
(2) For unsurveyed lands, describe the
lands by metes and bounds, giving
courses and distances, and tie this
information to an official corner of the
public land surveys, or to a prominent
topographic feature;
(3) For approved protracted surveys,
include an entire section, township,
range, and meridian. Do not divide
protracted sections into aliquot parts;
(4) For lands that have water
boundaries, describe the lands based on
the initial survey or deed acquiring
ownership;
(5) For fractional interest lands,
identify the United States mineral
ownership by percentage;
(6) For split estate lands, where the
surface rights are in private ownership
and the rights to develop the oil and gas
are managed by the Federal
Government, submit the private surface
owner’s name and address.
(7) For lands where the acquiring
agency has assigned an acquisition or
tract number covering the lands applied,
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submit the number in addition to any
description otherwise required by this
section. If the authorized officer
determines that the acquisition or tract
number, together with identification of
the State and county, constitutes an
adequate description, the authorized
officer may allow the description in this
manner in lieu of other descriptions
required by this section.
(c) A submitter may submit more than
one expression of interest, so long as
each expression separately satisfies the
requirements of paragraph (b) of this
section.
(d) Each expression of interest must
include a filing fee, as found in the fee
schedule in § 3103.1 of this chapter.
(e) The BLM may offer for sale all or
some of the lands specified in an
expression of interest and may offer
those lands as part of a parcel that
includes lands not specified in the
expression of interest.
§ 3120.32 Expression of interest leasing
preference.
When determining whether the BLM
should offer lands specified in an
expression of interest at lease sales, the
BLM will evaluate the Secretary’s
obligations to manage public lands for
multiple use and sustained yield and to
take any action required to prevent
unnecessary or undue degradation of
the lands and their resources, along
with other applicable legal
requirements. In evaluating the lands to
be offered, as part of the scoping
process, the BLM will consider, at
minimum:
(a) Proximity to oil and gas
development existing at the time of the
BLM’s evaluation, giving preference to
lands upon which a prudent operator
would seek to expand existing
operations;
(b) The presence of important fish and
wildlife habitats or connectivity areas,
giving preference to lands that would
not impair the proper functioning of
such habitats or corridors;
(c) The presence of historic
properties, sacred sites, and other high
value cultural resources, giving
preference to lands that would not
impair the cultural significance of such
resources;
(d) The presence of recreation and
other important uses or resources,
giving preference to lands that would
not impair the value of such uses or
resources; and
(e) The potential for oil and gas
development, giving preference to lands
with high potential for development.
§ 3120.33
Agency inventory of leasing.
Until August 16, 2032, the BLM will
from time to time calculate, for the
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preceding 1-year period before it issues
a wind or solar energy right-of-way, the
acreage for which expressions of interest
have been submitted to the BLM and the
sum total of acres offered for lease.
Notice of Competitive Lease Sale
§ 3120.41
General.
(a) The lands available for competitive
lease sale under this subpart will be
described in a Notice of Competitive
Lease Sale.
(b) The time, date, and place of the
competitive lease sale will be stated in
the notice.
(c) The notice will include an
identification of, and a copy of,
stipulations applicable to each parcel.
§ 3120.42
Posting timeframes.
(a) After identifying a preliminary list
of lands for a lease sale, the BLM will
provide a scoping period, of not less
than 30 calendar days, for public
comment on the preliminary parcel list
for the upcoming lease sale. The
preliminary parcel list is not subject to
protests or appeals.
(b) After drafting a National
Environmental Policy Act document for
a lease sale, the BLM will provide a
comment period, of not less than 30
calendar days, for public comment on
the National Environmental Policy Act
document for the upcoming lease sale.
The draft National Environmental
Policy Act document is not subject to
protests or appeals.
(c) At least 60 calendar days prior to
conducting a competitive auction, the
BLM will make available to the public
a list of lands to be offered for
competitive lease sale in a Notice of
Competitive Lease Sale.
(d) After posting the Notice of
Competitive Lease Sale notice, the BLM
will provide a protest period, of not less
than 30 calendar days, for public input
on the upcoming lease sale.
(e) The BLM will make available the
final National Environmental Policy Act
compliance documents prior to issuing
a lease from the lease sale.
Competitive Auction
§ 3120.51
Competitive auction.
(a) Parcels will be offered by
competitive auction.
(b) A winning bid will be the highest
bid by a responsible and qualified
bidder, equal to or exceeding the
national minimum acceptable bid. The
decision of the auctioneer will be final.
§ 3120.52
Payments required.
(a) Payments must be made in
accordance with 43 CFR 3103.11.
(b) Each winning bidder must submit,
by the close of official business hours on
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the day of the sale for the parcel, or such
other time as may be specified by the
authorized officer:
(1) The minimum bonus bid as
specified in § 3103.1 of this chapter;
(2) The total amount of the first year’s
rental; and
(3) The processing fee for competitive
lease applications found in the fee
schedule in § 3000.120 of this chapter
for each parcel.
(c) The winning bidder must submit
the balance of the bonus bid to the
proper BLM office within 10 business
days after the last day of the competitive
auction.
§ 3120.53
Award of lease.
(a) A bid will not be withdrawn and
will constitute a legally binding
commitment to execute the lease bid
form and accept a lease, including the
obligation to pay the bonus bid, first
year’s rental, and processing fee.
Execution by the high bidder of a
competitive lease bid form approved by
the Director constitutes certification of
compliance with 43 CFR subpart 3102,
will constitute a binding lease offer,
including all terms and conditions
applicable thereto, and must be
submitted when payment is made in
accordance with § 3120.62(b). Failure to
comply with § 3120.62(c) will result in
rejection of the bid and forfeiture of the
monies submitted under § 3120.62(b).
(b) A lease will be awarded to the
highest responsible and qualified
bidder. A copy of the lease will be
provided to the lessee after signature by
the authorized officer.
(c) If a bid is rejected, the land may
be reoffered competitively under this
subpart.
(d) The BLM will not issue a lease
until it resolves all protests covering the
lands to be leased.
(e) Leases will be issued within 60
calendar days, following payment by the
successful bidder of the remainder of
the bonus bid, if any, and the annual
rental for the first lease year. If the BLM
cannot issue the lease within 60 days,
the BLM, with the consent of the bidder,
may reject the offer.
ddrumheller on DSK120RN23PROD with RULES4
§ 3120.60
Lands offered at the competitive
auction that received no bids may be
offered in a future competitive auction.
Future Interest
§ 3120.71 Expression of interest to make
lands available for competitive lease.
An expression of interest for a future
interest lease must be filed in
accordance with this subpart.
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(a) No rental or royalty will be due to
the United States prior to the vesting of
the oil and gas rights in the United
States. However, the future interest
lessee must agree that if, he/she is or
becomes the holder of any present
interest operating rights in the lands:
(1) The future interest lessee transfers
all or a part of the lessee’s present oil
and gas interests, such lessee must file
in the proper BLM office an assignment
or transfer, in accordance with 43 CFR
subpart 3106, of the future interest lease
of the same type and proportion as the
transfer of the present interest; and
(2) The future interest lessee’s present
lease interests are relinquished,
cancelled, terminated, or expired, the
future interest lease rights with the
United States also will cease and
terminate to the same extent.
(b) Upon vesting of the oil and gas
rights in the United States, the future
interest lease rental and royalty will be
as for any competitive lease issued
under this subpart, as provided in 43
CFR subpart 3103, and the acreage will
be chargeable in accordance with 43
CFR 3101.20.
§ 3120.73 Compensatory royalty
agreements.
The terms and conditions of
compensatory royalty agreements
involving acquired lands in which the
United States owns a future or fractional
interest will be established on an
individual case basis. Such agreements
may be required when leasing is not
possible in situations where the interest
of the United States in the oil and gas
deposit includes both a present and a
future fractional interest in the same
tract containing a producing well.
PART 3130—OIL AND GAS LEASING:
NATIONAL PETROLEUM RESERVE
ALASKA
5. The authority citation for part 3130
continues to read as follows:
■
Authority: 42 U.S.C. 6508, 43 U.S.C. 1733
and 1740.
■
6. Revise § 3137.23 to read as follows:
§ 3137.23
Parcels not bid on at auction.
VerDate Sep<11>2014
§ 3120.72 Future interest terms and
conditions.
NPR–A unitization application.
The unitization application must
include:
(a) The proposed unit agreement;
(b) A map showing the proposed unit
area;
(c) A list of committed tracts
including, for each tract, the:
(1) Legal land description and
acreage;
(2) Names of persons holding record
title interest;
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30987
(3) Names of persons owning
operating rights; and
(4) Name of the unit operator.
(d) A statement certifying:
(1) The operator invited all owners of
oil and gas rights (leased or unleased)
and lease interests (record title and
operating rights) within the external
boundary of the unit area described in
the application to join the unit;
(2) That there are sufficient tracts
committed to the unit agreement to
reasonably operate and develop the unit
area;
(3) The commitment status of all
tracts within the area proposed for
unitization; and
(4) The operator accepts unit
obligations under § 3137.60 of this
subpart.
(e) Evidence of acceptable bonding;
(f) A discussion of reasonably
foreseeable and significantly adverse
effects on the surface resources of the
NPR–A and how unit operations may
reduce impacts compared to individual
lease operations;
(g) A discussion of the proposed
methodology for allocating production
among the committed tracts. If the unit
includes non-Federal oil and gas
mineral estate, you must explain how
the methodology takes into account
reservoir heterogeneity and area
variation in reservoir producibility; and
(h) Other documentation that the BLM
may request. The BLM may require
additional copies of maps, plats, and
other similar exhibits.
(i) The processing fee found in the fee
schedule in § 3000.120 of this chapter.
■ 7. Revise § 3137.61 to read as follows:
§ 3137.61
Change in unit operators.
(a) To change unit operators, the new
unit operator must submit to the BLM:
(1) Statements that:
(i) The new operator accepts unit
obligations; and
(ii) The percentage of required interest
owners consented to a change of unit
operator;
(2) Evidence of acceptable bonding
(see § 3137.60(b)); and
(3) The processing fee found in the fee
schedule in § 3000.120 of this chapter.
(b) The effective date of the change in
unit operator is the date the BLM
approves the new unit operator.
■ 8. Revise § 3138.11 to read as follows:
§ 3138.11 Applications for a subsurface
storage agreement.
(a) An application for a subsurface
storage agreement must include:
(1) The reason for forming a
subsurface storage agreement;
(2) A description of the area to be
included in the subsurface storage
agreement;
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(3) A description of the formation to
be used for storage;
(4) The proposed storage fees or
rentals. The fees or rentals must be
based on the value of the subsurface
storage, injection, and withdrawal
volumes, and rental income or other
income generated by the operator for
letting or subletting the storage
facilities;
(5) The payment of royalty for native
oil or gas (oil or gas that exists in the
formation before injection and that is
produced when the stored oil or gas is
withdrawn);
(6) A description of how often and
under what circumstances the operator
and the BLM intend to renegotiate fees
and payments;
(7) The proposed effective date and
term of the subsurface storage
agreement;
(8) Certification that all owners of
mineral rights (leased or unleased) and
lease interests have consented to the gas
storage agreement in writing;
(9) An ownership schedule showing
lease or land status;
(10) A schedule showing the
participation factor for all parties to the
subsurface storage agreement;
(11) Supporting data (geologic maps
showing the storage formation, reservoir
data, etc.) demonstrating the capability
of the reservoir for storage; and
(12) The processing fee found in the
fee schedule in § 3000.120 of this
chapter.
(b) The BLM will negotiate the terms
of a subsurface storage agreement with
the operator, including bonding, and
reservoir management.
(c) The BLM may request
documentation in addition to that
which the operator provides under
paragraph (a) of this section.
■ 9. Revise part 3140 to read as follows:
PART 3140—LEASING IN SPECIAL
TAR SAND AREAS
ddrumheller on DSK120RN23PROD with RULES4
Subpart 3140—Conversion of Existing Oil
and Gas Leases and Valid Claims Based on
Mineral Locations
Sec.
3140.1 Purpose.
3140.3 Authority.
3140.5 Definitions.
General Provisions
3140.11 Existing rights.
3140.12 Notice of intent to convert.
3140.13 Exploration plans.
3140.14 Other provisions.
3140.32
Action on an application.
Conversion
3140.41 Approval of plan of operations
(and unit and operating agreements).
3140.42 Issuance of the combined
hydrocarbon lease.
3140.50 Duration of the lease.
3140.60 Use of additional lands.
3140.70 Lands within the National Park
System.
Subpart 3141—Leasing in Special Tar Sand
Areas
3141.1 Purpose.
3141.3 Authority.
3141.5 Definitions.
3141.8 Other applicable regulations.
3141.10 General.
Prelease Exploration Within Special Tar
Sand Areas
3141.21 Geophysical exploration.
3141.22 Exploration licenses.
3141.30 Land use plans.
Consultation
3141.41 Consultation with the Governor.
3141.42 Consultation with others.
Leasing Procedures
3141.51 Economic evaluation.
3141.52 Term of lease.
3141.53 Royalties and rentals.
3141.54 Lease size.
3141.55 Dating of lease.
Sale Procedures
3141.61 Initiation of competitive lease
offering.
3141.62 Publication of a notice of
competitive lease offering.
3141.63 Conduct of sales.
3141.64 Qualifications.
3141.65 Rejection of bid.
3141.66 Consideration of next highest bid.
3141.70 Award of lease.
Subpart 3142—Paying Quantities/Diligent
Development for Combined Hydrocarbon
and Tar Sand Leases
3142.1 Purpose.
3142.3 Authority.
3142.5 Definitions.
3142.10 Diligent development.
Minimum Production Levels
3142.21 Minimum production schedule.
3142.22 Advance royalties in lieu of
production.
3142.30 Expiration.
PART 3140—LEASING IN SPECIAL
TAR SAND AREAS
Subpart 3140—Conversion of Existing
Oil and Gas Leases and Valid Claims
Based on Mineral Locations
Time Limitations
3140.31 Conversion applications.
The purpose of this subpart is to
provide for the conversion of existing
19:33 Apr 22, 2024
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§ 3140.3
§ 3140.1
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Purpose.
Frm 00074
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Authority.
These regulations are issued under
the authority of the Mineral Lands
Leasing Act of February 25, 1920 (30
U.S.C. 181 et seq.), the Mineral Leasing
Act for Acquired Lands (30 U.S.C. 351
et seq.), and the Combined Hydrocarbon
Leasing Act of 1981 (Pub. L. 97–78).
§ 3140.5
Definitions.
As used in this subpart, the term:
Combined hydrocarbon lease means a
lease issued in a Special Tar Sand Area
for the removal of gas and nongaseous
hydrocarbon substances other than coal,
oil shale or gilsonite.
Complete plan of operations means a
plan of operations that is in substantial
compliance with the information
requirements of 43 CFR part 3592 for
both exploration plans and mining
plans, as well as any additional
information required in this part and
under 43 CFR part 3593, as may be
appropriate.
Owner of an oil and gas lease means
all of the record title holders of an oil
and gas lease.
Owner of a valid claim based on a
mineral location means all parties
appearing on the title records
recognized as official under State law as
having the right to sell or transfer any
part of the mining claim, which was
located within a Special Tar Sand Area
prior to January 21, 1926, for any
hydrocarbon resource, except coal, oil
shale or gilsonite, leasable under the
Combined Hydrocarbon Leasing Act.
Special Tar Sand Area means an area
designated by the Department of the
Interior’s orders of November 20, 1980
(45 FR 76800), and January 21, 1981 (46
FR 6077) referred to in those orders as
Designated Tar Sand Areas, as
containing substantial deposits of tar
sand.
Unitization means unitization as that
term is defined in 43 CFR part 3180.
General Provisions
§ 3140.11
Authority: 30 U.S.C. 181 et seq.; 30 U.S.C.
351–359; 43 U.S.C. 1701 et seq.; Pub. L. 97–
78, 95 Stat. 1070; 42 U.S.C. 15801, unless
otherwise noted.
Applications
3140.21 Forms.
3140.22 Who may apply.
3140.23 Application requirements.
VerDate Sep<11>2014
oil and gas leases and valid claims
based on mineral locations within
Special Tar Sand Areas to combined
hydrocarbon leases.
Existing rights.
(a) The owner of an oil and gas lease
issued prior to November 16, 1981, or
the owner of a valid claim based on a
mineral location situated within a
Special Tar Sand Area may convert that
portion of the lease or claim so situated
to a combined hydrocarbon lease,
provided that such conversion is
consistent with the provisions of this
subpart. The application time period
ended on November 15, 1983.
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(b) Owners of oil and gas leases in
Special Tar Sand Areas who elect not to
convert their leases to a combined
hydrocarbon lease do not acquire the
rights to any hydrocarbon resource
except oil and gas as those terms were
defined prior to the enactment of the
Combined Hydrocarbon Leasing Act of
1981. The failure to file an application
to convert a valid claim based on a
mineral location within the time herein
provided will have no effect on the
validity of the mining claim nor the
right to maintain that claim.
§ 3140.12
Notice of intent to convert.
(a) Owners of oil and gas leases in
Special Tar Sand Areas which were
scheduled to expire prior to November
15, 1983, could have preserved the right
to convert their leases to combined
hydrocarbon leases by filing a Notice of
Intent to Convert with the BLM Utah
State Office.
(b) A letter, submitted by the lessee,
notifying the BLM of the lessee’s
intention to submit a plan of operations
constituted a notice of intent to convert
a lease. The Notice of Intent must have
contained the lease number.
(c) The Notice of Intent must have
been filed prior to the expiration date of
the lease. The notice would have
preserved the lessee’s conversion rights
only until November 15, 1983.
§ 3140.13
Exploration plans.
(a) The authorized officer may grant
permission to holders of existing oil and
gas leases to gather information to
develop, perfect, complete or amend a
plan of operations required for
conversion upon the approval of the
authorized officer of an exploration plan
developed in accordance with 43 CFR
3592.1.
(b) The approval of an exploration
plan in units of the National Park
System requires the consent of the
Regional Director of the National Park
Service in accordance with § 3140.70.
(c) The filing of an exploration plan
alone will be insufficient to meet the
requirements of a complete plan of
operations as set forth in § 3140.23.
ddrumheller on DSK120RN23PROD with RULES4
§ 3140.14
Other provisions.
(a) A combined hydrocarbon lease
will be for no more than 5,760 acres.
Acreage held under a combined
hydrocarbon lease in a Special Tar Sand
Area is not chargeable to State oil and
gas limitations allowable in 43 CFR
3101.21 or 3101.22.
(b) The annual rental rate for all
combined hydrocarbon leases will be as
stated in the lease, and the annual rental
for all new leases will be as specified in
43 CFR 3103.1. The rental rate for a
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19:33 Apr 22, 2024
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combined hydrocarbon lease will be
payable upon conversion and annually,
in advance, thereafter.
(c)(1) The royalty rate for a combined
hydrocarbon lease converted from an oil
and gas lease will be that provided for
in the original oil and gas lease.
(2) The royalty rate for a combined
hydrocarbon lease converted from a
valid claim based on a mineral location
will be 16.67 percent.
(3) A reduction of royalties may be
granted either as provided in § 3103.40
or, at the request of the lessee and upon
a review of information provided by the
lessee, prior to commencement of
commercial operations if the purpose of
the request is to promote development
and the maximum production of tar
sand. A reduction of royalties for the tar
sand will not apply to the oil and gas
resource. A reduction of royalties for the
oil and gas will not apply to the tar sand
resource.
(d)(1) Existing oil and gas leases and
valid claims based on mineral locations
may be unitized prior to or after the
lease or claim has been converted to a
combined hydrocarbon lease. The
requirements of 43 CFR part 3180 will
provide the procedures and general
guidelines for unitization of combined
hydrocarbon leases. For leases within
units of the National Park System,
unitization requires the consent of the
Regional Director of the National Park
Service in accordance with § 3140.41(b).
(2) If the plan of operations submitted
for conversion is designed to cover a
unit, a fully executed unit agreement
will be approved before the plan of
operations applicable to the unit may be
approved under § 3140.20. The
proposed plan of operations and the
proposed unit agreement may be
reviewed concurrently. The approved
unit agreement will be effective after the
leases or claims subject to it are
converted to combined hydrocarbon
leases. The plan of operations will
explain how and when each lease
included in the unit operation will be
developed.
(e) Except as provided for in this
subpart, the regulations set out in 43
CFR part 3100 are applicable, as
appropriate, to all combined
hydrocarbon leases issued under this
subpart.
Applications
§ 3140.21
Forms.
No special form is required for a
conversion application.
§ 3140.22
Who may apply.
Only owners of oil and gas leases
issued within Special Tar Sands Areas,
on or before November 16, 1981, and
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30989
owners of valid claims based on mineral
locations within Special Tar Sands
Areas, are eligible to convert leases or
claims to combined hydrocarbon leases
in Special Tar Sands Areas.
§ 3140.23
Application requirements.
(a) The BLM stopped accepting
conversion applications on November
15, 1983. The applicant must have
submitted to the BLM Utah State Office,
a written request for a combined
hydrocarbon lease signed by the owner
of the lease or valid claim which must
be accompanied by three copies of a
plan of operations which must meet the
requirements of 43 CFR 3592.1 and
which must have provided for
reasonable protection of the
environment and diligent development
of the resources requiring enhanced
recovery methods of development or
mining.
(b) A plan of operations may be
modified or amended before or after
conversion of a lease or valid claim to
reflect changes in technology, slippages
in schedule beyond the control of the
lessee, new information about the
resource or the economic or
environmental aspects of its
development, changes to or initiation of
applicable unit agreements or for other
purposes. To obtain approval of a
modification or amended plan, the
applicant must submit a written
statement of the proposed changes or
supplements and the justification for the
changes proposed. Any modifications
will be in accordance with 43 CFR
3592.1(c). The approval of the
modification or amendment is the
responsibility of the authorized officer.
Changes or modification to the plan of
operations will have no effect on the
primary term of the lease. The
authorized officer will, prior to
approving any amendment or
modification, review the modification or
amendment with the appropriate
surface management agency. For leases
within units of the National Park
System, no amendment or modification
will be approved without the consent of
the Regional Director of the National
Park Service in accordance with
§ 3140.70.
(c) The plan of operations may be for
a single existing oil and gas lease or
valid claim or for an area of proposed
unit operation.
(d) The plan of operations must
identify by lease number all Federal oil
and gas leases proposed for conversion
and identify valid claims proposed for
conversion by the recordation number
of the mining claim.
(e) The plan of operations must
include any proposed designation of
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operator or proposed operating
agreement.
(f) The plan of operations may include
an exploration phase, if necessary, but
it must include a development phase.
Such a plan can be approved even
though it may indicate work under the
exploration phase is necessary to perfect
the proposed plan for the development
phase as long as the overall plan
demonstrates reasonable protection of
the environment and diligent
development of the resources requiring
enhanced recovery methods of mining.
(g)(1) Upon determination that the
plan of operations is complete, the
authorized officer will suspend the term
of the Federal oil and gas lease(s) as of
the date that the complete plan was
filed until the plan is finally approved
or rejected. Only the term of the oil and
gas lease will be suspended, not any
operation and production requirements
thereunder.
(2) If the authorized officer
determines that the plan of operations is
not complete, the applicant will be
notified that the plan is subject to
rejection if not completed within the
period specified in the notice.
(3) The authorized officer may request
additional data after the plan of
operations has been determined to be
complete. This request for additional
information will have no effect on the
suspension of the running of the oil and
gas lease.
Time Limitations
§ 3140.31
Conversion applications.
A plan of operations to convert an
existing oil and gas lease or valid claim
based on a mineral location to a
combined hydrocarbon lease must have
been filed on or before November 15,
1983, or prior to the expiration of the oil
and gas lease, whichever was earlier,
except as provided in § 3140.12.
§ 3140.32
Action on an application.
The authorized officer will take action
on an application for conversion within
15 months of receipt of a proposed plan
of operations.
§ 3140.41 Approval of plan of operations
(and unit and operating agreements).
ddrumheller on DSK120RN23PROD with RULES4
§ 3140.42 Issuance of the combined
hydrocarbon lease.
(a) After a plan of operations is found
acceptable, and is approved, the
authorized officer will prepare and
submit to the owner, for execution, a
combined hydrocarbon lease containing
all appropriate terms and conditions,
including any necessary stipulations
that were part of the oil and gas lease
being converted, as well as any
additional stipulations, such as those
required to ensure compliance with the
plan of operations.
(b) The authorized officer will not
sign the combined hydrocarbon lease
until it has been executed by the
conversion applicant and the lease or
claim to be converted has been formally
relinquished to the United States.
(c) The effective date of the combined
hydrocarbon lease will be the first day
of the month following the date that the
authorized officer signs the lease.
(d) The authorized officer will issue
one combined hydrocarbon lease to
cover the existing contiguous oil and gas
leases or valid claims based on mineral
locations which have been approved for
conversion within the special tar sand
area.
§ 3140.50
(a) The owner of an oil and gas lease,
or the owner of a valid claim based on
a mineral location will have such lease
or claim converted to a combined
hydrocarbon lease when the plan of
operations, filed under § 3140.23, is
deemed acceptable and is approved by
the authorized officer.
(b) The conversion of a lease within
a unit of the National Park System will
19:33 Apr 22, 2024
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Duration of the lease.
A combined hydrocarbon lease will
be for a primary term of 10 years and for
so long thereafter as oil or gas is
produced in paying quantities. If the
applicant withdraws the combined
hydrocarbon lease application or the
BLM denies the conversion application,
the suspension on the oil and gas lease
will be lifted and the term will be
extended by the time remaining on the
term of the lease.
§ 3140.60
Conversion
VerDate Sep<11>2014
be approved only with the consent of
the Regional Director of the National
Park Service in accordance with
§ 3140.70.
(c) A plan of operations may not be
approved in part but may be approved
where it contains an appropriately
staged plan of exploration and
development operations.
Use of additional lands.
(a) The authorized officer may
noncompetitively lease additional lands
for ancillary facilities in a Special Tar
Sand Area that are needed to support
any operations necessary for the
recovery of tar sand. Such uses include,
but are not limited to, mill site or waste
disposal. Application for a lease or
permit to use additional lands must be
filed under the provisions of 43 CFR
part 2920 with the proper BLM office
having jurisdiction of the lands. The
application for additional lands may be
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filed at the time a plan of operations is
filed.
(b) A lease for the use of additional
lands will not be issued when the use
can be authorized under 43 CFR parts
2800 and 2880. Such uses include, but
are not limited to, reservoirs, pipelines,
electrical generation systems,
transmission lines, roads, and railroads.
(c) Within units of the National Park
System, permits or leases for additional
lands will only be issued by the
National Park Service. Applications for
such permits or leases must be filed
with the Regional Director of the
National Park Service.
§ 3140.70
System.
Lands within the National Park
The BLM stopped accepting
conversion applications on November
15, 1983. Conversions of existing oil and
gas leases and valid claims based on
mineral locations to combined
hydrocarbon leases within units of the
National Park System will be allowed
only where mineral leasing is permitted
by law and where the lands covered by
the lease or claim proposed for
conversion are open to mineral resource
disposition in accordance with any
applicable minerals management plan.
(See 43 CFR 3100.3(h)(4)). In order to
consent to any conversion or any
subsequent development under a
combined hydrocarbon lease requiring
further approval, the Regional Director
of the National Park Service must find
that there will be no resulting
significant adverse impacts on the
resources and administration of such
areas or on other contiguous units of the
National Park System in accordance
with 43 CFR 3109.20(b).
Subpart 3141—Leasing in Special Tar
Sand Areas
§ 3141.1
Purpose.
The purpose of this subpart is to
provide for the competitive leasing of
lands and issuance of combined
hydrocarbon leases, oil and gas leases,
or tar sand leases within special tar sand
areas.
§ 3141.3
Authority.
The regulations in this subpart are
issued under the authority of the
Mineral Leasing Act of February 25,
1920 (30 U.S.C. 181 et seq.), the Mineral
Leasing Act for Acquired Lands (30
U.S.C. 351 et seq.), the Federal Land
Policy and Management Act of 1976 (43
U.S.C. 1701 et seq.), the Combined
Hydrocarbon Leasing Act of 1981 (95
Stat. 1070), and the Energy Policy Act
of 2005 (Pub. L. 109–58).
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§ 3141. 5
Definitions.
As used in this subpart, the term:
Combined hydrocarbon lease means a
lease issued in a Special Tar Sand Area
for the removal of any gas and
nongaseous hydrocarbon substance
other than coal, oil shale or gilsonite.
Oil and gas lease means a lease issued
in a Special Tar Sand Area for the
exploration and development of oil and
gas resources other than tar sand.
Special Tar Sand Area means an area
designated by the Department of the
Interior’s Orders of November 20, 1980
(45 FR 76800), and January 21, 1981 (46
FR 6077), and referred to in those orders
as Designated Tar Sand Areas, as
containing substantial deposits of tar
sand.
Tar sand means any consolidated or
unconsolidated rock (other than coal, oil
shale or gilsonite) that either:
(1) Contains a hydrocarbonaceous
material with a gas-free viscosity, at
original reservoir temperature greater
than 10,000 centipoise, or
(2) contains a hydrocarbonaceous
material and is produced by mining or
quarrying.
Tar sand lease means a lease issued
in a Special Tar Sand area exclusively
for the exploration for and extraction of
tar sand.
ddrumheller on DSK120RN23PROD with RULES4
§ 3141.8
Other applicable regulations.
(a) Combined hydrocarbon leases. (1)
The following provisions of 43 CFR part
3100, as they relate to competitive
leasing, apply to the issuance and
administration of combined
hydrocarbon leases issued under this
part.
(i) All of 43 CFR subpart 3100;
(ii) All of 43 CFR subpart 3101, with
the exception of §§ 3101.21, 3101.22,
3101.23, 3101.24, and 3101.25;
(iii) All of 43 CFR subpart 3102;
(iv) All of 43 CFR subpart 3103, with
the exception of §§ 3103.21, and
3103.31(a), (b), and (c);
(v) All of 43 CFR subpart 3104;
(vi) All of 43 CFR subpart 3105;
(vii) All of 43 CFR subpart 3106, with
the exception of § 3106.10(j);
(viii) All of 43 CFR subpart 3107;
(ix) All of 43 CFR subpart 3108; and
(x) All of 43 CFR subpart 3109, with
special emphasis on § 3109.20(b).
(2) Prior to commencement of
operations, the lessee must develop
either a plan of operations as described
in 43 CFR 3592.1 which ensures
reasonable protection of the
environment or file an application for a
permit to drill as described in 43 CFR
part 3160, whichever is appropriate.
(3) The provisions of 43 CFR part
3180 will serve as general guidance to
the administration of combined
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hydrocarbon leases issued under this
part to the extent they may be included
in unit or cooperative agreements.
(b) Oil and gas leases. (1) All of the
provisions of 43 CFR parts 3100, and
3120 apply to the issuance and
administration of oil and gas leases
issued under this part.
(2) All of the provisions of 43 CFR
parts 3160 and 3170 apply to operations
on an oil and gas lease issued under this
part.
(3) The provisions of 43 CFR part
3180 apply to the administration of oil
and gas leases issued under this part.
(c) Tar sand leases. (1) The following
provisions of 43 CFR part 3100, as they
relate to competitive leasing, apply to
the issuance of tar sand leases issued
under this part.
(i) All of 43 CFR subpart 3102;
(ii) All of 43 CFR subpart 3103 with
the exception of §§ 3103.21, 3103.22(d),
3103.31, and 3103.32;
(iii) All of 43 CFR 3120.50; and
(iv) All of 43 CFR 3120.60.
(2) Prior to commencement of
operations, the lessee must develop a
plan of operations as described in 43
CFR 3592.1 which ensures reasonable
protection of the environment.
§ 3141.10
General.
(a) Combined hydrocarbons or tar
sands within a Special Tar Sand Area
will be leased only by competitive
bonus bidding.
(b) Oil and gas within a Special Tar
Sand Area will be leased by competitive
bonus bidding as described in 43 CFR
part 3120.
(c) The authorized officer may issue
either combined hydrocarbon leases, or
oil and gas leases for oil and gas within
such areas.
(d) The rights to explore for or
develop tar sand deposits in a Special
Tar Sand Area may be acquired through
either a combined hydrocarbon lease or
a tar sand lease.
(e) An oil and gas lease in a Special
Tar Sand Area does not include the
rights to explore for or develop tar sand.
(f) A tar sand lease in a Special Tar
Sand Area does not include the rights to
explore for or develop oil and gas.
(g) The minimum acceptable bid for a
lease issued for tar sand will be as
specified in § 3103.1 of this chapter.
(h) The acreage of combined
hydrocarbon leases or tar sand leases
held within a Special Tar Sand Area
will not be charged against acreage
limitations for the holding of oil and gas
leases as provided in 43 CFR 3101.21.
(i)(1) The authorized officer may
noncompetitively lease additional lands
for ancillary facilities in a Special Tar
Sand Area that are shown by an
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30991
applicant to be needed to support any
operations necessary for the recovery of
tar sand. Such uses include, but are not
limited to, mill siting or waste disposal.
An application for a lease or permit to
use additional lands must be filed under
the provisions of 43 CFR part 2920 with
the proper BLM office having
jurisdiction of the lands. The
application for additional lands may be
filed at the time a plan of operations is
filed.
(2) A lease for the use of additional
lands will not be issued under this part
when the use can be authorized under
43 CFR part 2800. Such uses include,
but are not limited to, reservoirs,
pipelines, electrical generation systems,
transmission lines, roads and railroads.
(3) Within units of the National Park
System, permits or leases for additional
lands for any purpose will be issued
only by the National Park Service.
Applications for such permits or leases
must be filed with the Regional Director
of the National Park Service.
Prelease Exploration Within Special
Tar Sand Areas
§ 3141.21
Geophysical exploration.
Geophysical exploration in Special
Tar Sand Areas will be governed by 43
CFR part 3150. Information obtained
under a permit must be made available
to the BLM upon request.
§ 3141.22
Exploration licenses.
(a) Any person(s) responsible and
qualified to hold a lease under the
provisions of 43 CFR subpart 3102 and
this subpart may obtain an exploration
license to conduct core drilling and
other exploration activities to collect
geologic, environmental and other data
concerning tar sand resources only on
lands, the surface of which are under
the jurisdiction of the BLM, within or
adjacent to a Special Tar Sand Area. The
application for such a license must be
submitted to the proper BLM office
having jurisdiction over the lands. No
drilling for oil or gas will be allowed
under an exploration license issued
under this subpart. No specific form is
required for an application for an
exploration license.
(b) The application for an exploration
license will be subject to the following
requirements:
(1) Each application must contain the
name and address of the applicant(s);
(2) Each application must be
accompanied by a nonrefundable filing
fee based on the coal exploration license
application fee found in the fee
schedule in § 3000.120 of this chapter;
(3) Each application must contain a
description of the lands covered by the
application according to section,
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township and range in accordance with
the official survey;
(4) Each application must include an
exploration plan which complies with
the requirements of 43 CFR 4392.1(a);
and
(5) An application must cover no
more than 5,760 acres, which will be as
compact as possible. The authorized
officer may grant an exploration license
covering more than 5,760 acres only if
the application contains a justification
for an exception to the normal
limitation.
(c) The authorized officer may, if the
authorized officer determines it
necessary to avoid impacts resulting
from duplication of exploration
activities, require applicants for
exploration licenses to provide an
opportunity for other parties to
participate in exploration under the
license on a pro rata cost sharing basis.
If joint participation is determined
necessary, it will be conducted
according to the following:
(1) Immediately upon the notification
of a determination that parties will be
given an opportunity to participate in
the exploration license, the applicant
must publish a ‘‘Notice of Invitation,’’
approved by the authorized officer, once
every week for 2 consecutive weeks in
at least one newspaper of general
circulation in the area where the lands
covered by the exploration license are
situated. This notice must contain an
invitation to the public to participate in
the exploration license on a pro rata cost
sharing basis. Copies of the ‘‘Notice of
Invitation’’ must be filed with the
authorized officer at the time of
publication by the applicant for posting
in the proper BLM office having
jurisdiction over the lands covered by
the application for at least 30 days prior
to the issuance of the exploration
license.
(2) Any person seeking to participate
in the exploration program described in
the Notice of Invitation must notify the
authorized officer and the applicant in
writing of such intention within 30 days
after posting in the proper BLM office
having jurisdiction over the lands
covered by the Notice of Invitation. The
authorized officer may require
modification of the original exploration
plan to accommodate the legitimate
exploration needs of the person(s)
seeking to participate and to avoid the
duplication of exploration activities in
the same area, or that the person(s)
should file a separate application for an
exploration license.
(3) An application to conduct
exploration which could have been
conducted under an existing or recent
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exploration license issued under this
paragraph may be rejected.
(d) The authorized officer may accept
or reject an exploration license
application. An exploration license will
become effective on the date specified
by the authorized officer as the date
when exploration activities may begin.
The exploration plan approved by the
BLM will be attached and made a part
of each exploration license.
(e) An exploration license will be
subject to these terms and conditions:
(1) The license will be for a term of
not more than 2 years;
(2) The annual rental rate for an
exploration license will be as stated in
the license;
(3) The licensee must provide a bond
in an amount determined by the
authorized officer, but not less than
$5,000. The authorized officer may
accept bonds furnished under 43 CFR
subpart 3104, if adequate. The period of
liability under the bond will be
terminated only after the authorized
officer determines that the terms and
conditions of the license, the
exploration plan and the regulations
have been met;
(4) The licensee must provide to the
BLM, upon request, all required
information obtained under the license.
Any information provided will be
treated as confidential and proprietary,
if appropriate, at the request of the
licensee, and will not be made public
until the areas involved have been
leased or if the BLM determines that
public access to the data will not
damage the competitive position of the
licensee.
(5) Operations conducted under a
license will not unreasonably interfere
with or endanger any other lawful
activity on the same lands, must not
damage any improvements on the lands,
and will not result in any substantial
disturbance to the surface of the lands
and their resources;
(6) The authorized officer will include
in each license requirements and
stipulations to protect the environment
and associated natural resources, and to
ensure reclamation of the land disturbed
by exploration operations;
(7) When unforeseen conditions are
encountered that could result in an
action prohibited by paragraph (e)(5) of
this section, or when warranted by
geologic or other physical conditions,
the authorized officer may adjust the
terms and conditions of the exploration
license and may direct adjustment in
the exploration plan;
(8) The licensee may submit a request
for modification of the exploration plan
to the authorized officer. Any
modification will be subject to the
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regulations in this section and the terms
and conditions of the license. The
authorized officer may approve the
modification after any necessary
adjustments to the terms and conditions
of the license that are accepted in
writing by the licensee; and
(9) The license will be subject to
termination or suspension as provided
in 43 CFR 2920.9–3.
§ 3141.30
Land use plans.
No lease will be issued under this
subpart unless the lands have been
included in a land use plan which
meets the requirements under 43 CFR
part 1600 or an approved Minerals
Management Plan of the National Park
Service. The decision to hold a lease
sale and issue leases will be in
conformance with the appropriate plan.
Consultation
§ 3141.41
Consultation with the Governor.
The Secretary will consult with the
Governor of the State in which any tract
proposed for sale is located. The
Secretary will give the Governor 30 days
to comment before determining whether
to conduct a lease sale. The Secretary
will seek the recommendations of the
Governor of the State in which the lands
proposed for lease are located as to
whether or not to lease such lands and
what alternative actions are available
and what special conditions could be
added to the proposed lease(s) to
mitigate impacts. The Secretary will
accept the recommendations of the
Governor if the Secretary determines
that they provide for a reasonable
balance between the national interest
and the State’s interest. The Secretary
will communicate to the Governor in
writing and publish in the Federal
Register the reasons for his/her
determination to accept or reject such
Governor’s recommendations.
§ 3141.42
Consultation with others.
(a) Where the surface is administered
by an agency other than the BLM,
including lands patented or leased
under the provisions of the Recreation
and Public Purposes Act, as amended
(43 U.S.C. 869 et seq.), all leasing under
this subpart will be in accordance with
the consultation requirements of 43 CFR
subpart 3100.
(b) The issuance of combined
hydrocarbon leases, oil and gas leases,
and tar sand leases within special tar
sand areas in units of the National Park
System will be allowed only where
mineral leasing is permitted by law and
where the lands are open to mineral
resource disposition in accordance with
any applicable Minerals Management
Plan. In order to consent to any issuance
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of a combined hydrocarbon lease, oil
and gas lease, tar sand lease, or
subsequent development of
hydrocarbon resources within a unit of
the National Park System, the Regional
Director of the National Park Service
will find that there will be no resulting
significant adverse impacts to the
resources and administration of the unit
or other contiguous units of the National
Park System in accordance with 43 CFR
3109.20(b).
Leasing Procedures
§ 3141.51
Economic evaluation.
Prior to any lease sale for a combined
hydrocarbon lease, the authorized
officer will request an economic
evaluation of the total hydrocarbon
resource on each proposed lease tract
exclusive of coal, oil shale, or gilsonite.
§ 3141.52
Term of lease.
(a) Oil and gas leases in special tar
sand areas will have a primary term of
10 years and will remain in effect so
long thereafter as oil or gas is produced
in paying quantities.
(b) Tar Sand leases will have a
primary term of 10 years and will
remain in effect so long thereafter as tar
sand is produced in paying quantities.
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§ 3141.53
Royalties and rentals.
(a) The royalty rate on all combined
hydrocarbon leases or tar sand leases is
16.67 percent of the value of production
removed or sold from a lease. The
ONRR will be responsible for collecting
and administering royalties.
(b) The lessee may request the
Secretary to reduce the royalty rate
applicable to a tar sand lease prior to
commencement of commercial
operations in order to promote
development and maximum production
of the tar sand resource in accordance
with procedures established by the BLM
for oil shale leases and may request a
reduction in the royalty after
commencement of commercial
operations in accordance with 43 CFR
3103.41.
(c) The annual rental rate for a
combined hydrocarbon lease will be as
stated in the lease.
(d) The annual rental rate for a tar
sand lease will be as stated in the lease.
(e) Except as explained in paragraphs
(a) through (c) of this section, all other
provisions of 43 CFR 3103.20 and
3103.30 apply to combined hydrocarbon
leasing.
§ 3141.54
Lease size.
Combined hydrocarbon leases or tar
sand leases in Special Tar Sand Areas
will not exceed 5,760 acres.
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§ 3141.55
Dating of lease.
A combined hydrocarbon lease will
be effective as of the first day of the
month following the date the lease is
signed on behalf of the United States,
except where a prior written request is
made, a lease may be made effective on
the first of the month in which the lease
is signed.
Sale Procedures
§ 3141.61
offering.
Initiation of competitive lease
The BLM may, on its own motion,
offer lands through competitive bidding.
A request or expression(s) of interest in
tract(s) for competitive lease offerings
must be submitted in writing to the
proper BLM office.
§ 3141.62 Publication of a notice of
competitive lease offering.
Combined Hydrocarbon Leases, Tar
Sand Leases or Oil and Gas Leases. At
least 45 days prior to conducting a
competitive auction, lands to be offered
for a competitive lease sale, as in a
Notice of Competitive Lease Sale, will
be made available to the public. The
notice will specify the time and place of
sale; the manner in which the bids may
be submitted; the description of the
lands; the terms and conditions of the
lease, including the royalty and rental
rates; the amount of the minimum bid;
and will state that the terms and
conditions of the leases are available for
inspection and designate the proper
BLM office where bid forms may be
obtained.
§ 3141.63
Conduct of sales.
(a) Oil and gas leases. Lease sales for
oil and gas leases will be conducted
using the procedures for oil and gas
leases in 43 CFR 3120.60.
(b) Combined hydrocarbon leases and
tar sand leases. (1) Parcels will be
offered by competitive auction.
(2) The winning bid will be the
highest bid by a responsible and
qualified bidder, equal to the minimum
bonus bid amount as specified in
§ 3103.1 of this chapter or for
hydrocarbon leases, the minimum
bonus bid amount determined under
§ 3141.51, whichever is larger.
(3) Payments must be made as
provided in 43 CFR 3120.62.
§ 3141.64
Qualifications.
Each bidder must submit with the bid
a statement over the bidder’s signature
with respect to compliance with 43 CFR
subpart 3102.
§ 3141.65
Rejection of bid.
If the high bid is rejected for failure
by the successful bidder to execute the
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lease forms and pay the balance of the
bonus bid, or otherwise to comply with
the regulations of this subpart, the
minimum bonus payment
accompanying the bid will be forfeited.
§ 3141.66
bid.
Consideration of next highest
The Department reserves the right to
accept the next highest bid if the highest
bid is rejected. In no event will an offer
be made to the next highest bidder if the
difference between that bid and the bid
of the rejected successful bidder is
greater than the minimum bonus
payment forfeited by the rejected
successful bidder.
§ 3141.70
Award of lease.
After determining the highest
responsible and qualified bidder, the
authorized officer will send the lease on
a form approved by the Director, and
any necessary stipulations, to the
successful bidder. The successful bidder
must, not later than the 30th calendar
day after receipt of the lease, execute the
lease, pay the balance of the bid and the
first year’s rental, and file a bond as
required in 43 CFR subpart 3104.
Failure to comply with this section will
result in rejection of the lease.
Subpart 3142—Paying Quantities/
Diligent Development for Combined
Hydrocarbon and Tar Sand Leases
§ 3142.1
Purpose.
This subpart provides definitions and
procedures for meeting the production
in paying quantities and the diligent
development requirements for tar sand
in all combined hydrocarbon leases and
tar sand leases.
§ 3142.3
Authority.
These regulations are issued under
the authority of the Mineral Leasing Act
of 1920, as amended and supplemented
(30 U.S.C. 181 et seq.), the Mineral
Leasing Act for Acquired Lands (30
U.S.C. 351–359), the Federal Land
Policy and Management Act of 1976 (43
U.S.C. 1701 et seq.) and the Combined
Hydrocarbon Leasing Act of 1981 (95
Stat. 1070).
§ 3142.5
Definitions.
As used in this subpart, the term:
Production in paying quantities for
combined hydrocarbon leases means:
(1) Production, in compliance with an
approved plan of operations and by
nonconventional methods, of oil and gas
which can be marketed; or
(2) Production of oil or gas by
conventional methods as the term is
currently used in 43 CFR part 3160.
Production in paying quantities for oil
and gas leases means production of oil
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or gas by conventional methods that
meets the definition of ‘‘production in
paying quantities’’ in 43 CFR 3160.0–5.
Production in paying quantities for tar
sand leases means production of shale
oil quantities that provide a positive
return after all costs of production have
been met, including the amortized costs
of the capital investment.
§ 3142.10
Diligent development.
A lessee will have met its diligent
development obligation if:
(a) The lessee is conducting activity
on the lease in accordance with an
approved plan of operations; and
(b) The lessee files with the
authorized officer, not later than the end
of the eighth lease year, a supplement to
the approved plan of operations which
must include the estimated recoverable
tar sand reserves and a detailed
development plan for the next stage of
operations;
(c) The lessee has achieved
production in paying quantities, as that
term is defined in § 3142.5(a), by the
end of the primary term; and
(d) The lessee annually produces the
minimum amount of tar sand
established by the authorized officer
under the lease in the minimum
production schedule which will be
made part of the plan of operations or
pays annually advance royalty in lieu of
this minimum production.
Minimum Production Levels
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§ 3142.21
Minimum production schedule.
(a) Upon receipt of the supplement to
the plan of operations described in
§ 3142.10(b), the authorized officer will
examine the information furnished by
the lessee and determine if the estimate
of the recoverable tar sand reserves is
adequate and reasonable. In making this
determination, the authorized officer
may request, and the lessee must
furnish, any information that is the basis
of the lessee’s estimate of the
recoverable tar sand reserves. As part of
the authorized officer’s determination
that the estimate of the recoverable tar
sand reserves is adequate and
reasonable, the authorized officer may
consider, but is not limited to, the
following: ore grade, strip ratio, vertical
and horizontal continuity, extract
process recoverability, and proven or
unproven status of extraction
technology, terrain, environmental
mitigation factors, marketability of
products and capital operations costs.
The authorized officer will then
establish as soon as possible, but prior
to the beginning of the eleventh year,
based upon the estimate of the
recoverable tar sand reserves, a
minimum annual tar sand production
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schedule for the lease or unit operations
which will start in the eleventh year of
the lease. This minimum production
level will escalate in equal annual
increments to a maximum of 1 percent
of the estimated recoverable tar sand
reserves in the twentieth year of the
lease and remain at 1 percent each year
thereafter.
(b) The minimum annual tar sand
production schedule for the lease or
unit operations will be set at a level for
paying quantities. If the operator or
lessee cannot establish production in
paying quantities, the lease will
terminate at the end of the lease’s
primary term.
§ 3142.22 Advance royalties in lieu of
production.
(a) Failure to meet the minimum
annual tar sand production schedule
level in any year will result in the
assessment of an advance royalty in lieu
of production which will be credited to
future production royalty assessments
applicable to the lease or unit.
(b) If there is no production during
the lease year, and the lessee has reason
to believe that there will be no
production during the remainder of the
lease year, the lessee must submit to the
authorized officer a request for
suspension of production at least 90
days prior to the end of that lease year
and a payment sufficient to cover any
advance royalty due and owing as a
result of the failure to produce. Upon
receipt of the request for suspension of
production and the accompanying
payment, the authorized officer may
approve a suspension of production for
that lease year and the lease will not
expire during that year for lack of
production.
(c) If there is production on the lease
or unit during the lease year, but such
production fails to meet the minimum
production schedule required by the
plan of operations for that lease or unit,
the lessee must pay an advance royalty
within 60 days of the end of the lease
year in an amount sufficient to cover the
difference between such actual
production and the production schedule
required by the plan of operations for
that lease or unit and the authorized
officer may direct a suspension of
production for those periods during
which no production occurred.
§ 3142.30
Expiration.
Failure of the lessee to pay advance
royalty within the time prescribed by
the authorized officer, or failure of the
lessee to comply with any other
provisions of this subpart following the
end of the primary term of the lease,
will result in the automatic expiration of
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the lease as of the first of the month
following notice to the lessee of its
failure to comply. The lessee will
remain subject to the requirement of
applicable laws, regulations and lease
terms which have not been met at the
expiration of the lease.
PART 3150—ONSHORE OIL AND GAS
GEOPHYSICAL EXPLORATION
10. The authority citation for part
3150 continues to read as follows:
■
Authority: 16 U.S.C. 3150(b) and 668dd;
30 U.S.C. 189 and 359; 42 U.S.C. 6508; 43
U.S.C. 1201, 1732(b), 1733, 1734, 1740.
11. Revise subpart 3151 to read as
follows:
■
Subpart 3151—Exploration Outside of
Alaska
3151.10 Notice of intent to conduct oil and
gas geophysical exploration operations.
3151.20 Notice of completion of operations.
3151.30 Collection and submission of data.
Subpart 3151—Exploration Outside of
Alaska
§ 3151.10 Notice of intent to conduct oil
and gas geophysical exploration
operations.
Parties wishing to conduct oil and gas
geophysical exploration outside of the
State of Alaska must file a Notice of
Intent to Conduct Oil and Gas
Exploration Operations, referred to
herein as a notice of intent. The notice
of intent must include the filing fee
required by 43 CFR 3000.120 and must
be filed with the authorized officer of
the proper BLM office on the form
approved by the Director. Within 5
business days of the filing date, the
authorized officer will process the
notice of intent and notify the operator
of practices and procedures to be
followed. If the notice of intent cannot
be processed within 5 business days of
the filing date, the authorized officer
will promptly notify the operator as to
when processing will be completed,
giving the reason for the delay. The
operator must, within 5 business days of
the filing date, or such other time as
may be convenient for the operator,
participate in a field inspection if
requested by the authorized officer.
Signing of the notice of intent by the
operator will signify agreement to
comply with the terms and conditions
contained therein and in this part, and
with all practices and procedures
specified at any time by the authorized
officer.
§ 3151.20 Notice of completion of
operations.
Upon completion of exploration, the
permittee must file with the District
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Manager a Notice of Completion of Oil
and Gas Exploration Operations. Within
30 days after this filing, the authorized
officer will notify the permittee whether
rehabilitation of the lands is satisfactory
or whether additional rehabilitation is
necessary, specifying the nature and
extent of actions to be taken by the
permittee.
§ 3151.30
data.
Collection and submission of
(a) The permittee must submit to the
authorized officer all data and
information obtained in carrying out the
exploration plan.
(b) All information submitted under
this section is presumptively
confidential business information and is
subject to 43 CFR part 2, which sets
forth the rules of the Department of the
Interior relating to public availability of
information contained in Departmental
records, as provided at § 3100.40 of this
chapter.
PART 3160—ONSHORE OIL AND GAS
OPERATIONS
12. 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; 43 U.S.C.
1732(b), 1733, 1740; and Sec. 107, Pub. L.
114–74, 129 Stat. 599, unless otherwise
noted.
13. Revise § 3160.0–5 to read as
follows:
■
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§ 3160.0–5
Definitions.
As used in this part, the term:
Authorized representative means any
entity or individual authorized by the
Secretary to perform duties by
cooperative agreement, delegation or
contract.
Drainage means the migration of
hydrocarbons, inert gases (other than
helium), or associated resources caused
by production from other wells.
Federal lands means all lands and
interests in lands owned by the United
States which are subject to the mineral
leasing laws, including mineral
resources or mineral estates reserved to
the United States in the conveyance of
a surface or nonmineral estate.
Fresh water means water containing
not more than 1,000 ppm of total
dissolved solids, provided that such
water does not contain objectionable
levels of any constituent that is toxic to
animal, plant or aquatic life, unless
otherwise specified in applicable
notices or orders.
Knowingly or willfully means a
violation that constitutes the voluntary
or conscious performance of an act that
is prohibited or the voluntary or
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conscious failure to perform an act or
duty that is required. It does not include
performances or failures to perform that
are honest mistakes or merely
inadvertent. It includes, but does not
require, performances or failures to
perform that result from a criminal or
evil intent or from a specific intent to
violate the law. The knowing or willful
nature of conduct may be established by
plain indifference to or reckless
disregard of the requirements of the law,
regulations, orders, or terms of the lease.
A consistent pattern of performance or
failure to perform also may be sufficient
to establish the knowing or willful
nature of the conduct, where such
consistent pattern is neither the result of
honest mistakes or mere inadvertency.
Conduct that is otherwise regarded as
being knowing or willful is rendered
neither accidental nor mitigated in
character by the belief that the conduct
is reasonable or legal.
Lease means any contract, profit-share
arrangement, joint venture or other
agreement issued or approved by the
United States under a mineral leasing
law that authorizes exploration for,
extraction of, or removal of oil or gas.
Lease site means any lands, including
the surface of a severed mineral estate,
on which exploration for, or extraction
and removal of, oil or gas is authorized
under a lease.
Lessee means any person holding
record title or owning operating rights
in a lease issued or approved by the
United States.
Lessor means the party to a lease who
holds legal or beneficial title to the
mineral estate in the leased lands.
Major violation means noncompliance
that causes or threatens immediate,
substantial, and adverse impacts on
public health and safety, the
environment, production accountability,
or royalty income.
Maximum ultimate economic
recovery means the recovery of oil and
gas from leased lands which a prudent
operator could be expected to make
from that field or reservoir given
existing knowledge of reservoir and
other pertinent facts and utilizing
common industry practices for primary,
secondary, or tertiary recovery
operations.
Minor violation means
noncompliance that does not rise to the
level of a major violation.
New or resumed production under
section 102(b)(3) of the Federal Oil and
Gas Royalty Management Act means the
date on which a well commences
production, or resumes production after
having been off production for more
than 90 days, and is to be construed as
follows:
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(1) For an oil well, the date on which
liquid hydrocarbons are first sold or
shipped from a temporary storage
facility, such as a test tank, or the date
on which liquid hydrocarbons are first
produced into a permanent storage
facility, whichever first occurs; and
(2) For a gas well, the date on which
gas is first measured through sales
metering facilities or the date on which
associated liquid hydrocarbons are first
sold or shipped from a temporary
storage facility, whichever first occurs.
Notice to lessees and operators (NTL)
means a written notice issued by the
authorized officer. NTLs implement the
regulations in this part and operating
orders, and serve as instructions on
specific item(s) of importance within a
State, District, or Area.
Onshore oil and gas order means a
formal numbered order issued by the
Director that implements and
supplements the regulations in this part.
Operating rights owner means a
person who owns operating rights in a
lease. A record title holder may also be
an operating rights owner in a lease if
it did not transfer all of its operating
rights.
Operator means any person or entity
including but not limited to the lessee
or operating rights owner, who has
stated in writing to the authorized
officer that it is responsible under the
terms and conditions of the lease for the
operations conducted on the leased
lands or a portion thereof.
Paying well means a well that is
capable of producing oil or gas of
sufficient value to exceed direct
operating costs and the costs of lease
rentals or minimum royalty.
Person means any individual, firm,
corporation, association, partnership,
consortium or joint venture.
Production in paying quantities
means production from a lease of oil
and/or gas of sufficient value to exceed
direct operating costs and the cost of
lease rentals or minimum royalties.
Protective well means a well drilled or
modified to prevent or offset drainage of
oil and gas resources from its Federal or
Indian lease.
Record title holder means the
person(s) to whom the BLM or an Indian
lessor issued a lease or approved the
assignment of record title in a lease.
Shut-in well means a nonoperational
well that can physically and
mechanically operate by opening valves
or activating existing equipment.
Superintendent means the
superintendent of an Indian Agency, or
other officer authorized to act in matters
of record and law with respect to oil and
gas leases on restricted Indian lands.
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Surface use plan of operations means
a plan for surface use, disturbance, and
reclamation.
Temporarily abandoned well means a
nonoperational well that is not
physically or mechanically capable of
production or injection without
additional equipment or without
servicing the well, but that may have
future beneficial use.
Waste of oil or gas means any act or
failure to act by the operator that is not
sanctioned by the authorized officer as
necessary for proper development and
production and which results in:
(1) A reduction in the quantity or
quality of oil and gas ultimately
producible from a reservoir under
prudent and proper operations; or
(2) Avoidable surface loss of oil or
gas.
14. Revise § 3162.3–4 to read as
follows:
■
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§ 3162.3–4
Well abandonment.
(a) The operator must promptly plug
and abandon, in accordance with a plan
first approved in writing or prescribed
by the authorized officer, each newly
completed or recompleted well in
which oil or gas is not encountered in
paying quantities or which, after being
completed as a producing well, is
demonstrated to the satisfaction of the
authorized officer to be no longer
capable of producing oil or gas in
paying quantities, unless the authorized
officer approves the use of the well as
a service well for injection to recover
additional oil or gas or for subsurface
disposal of produced water. In the case
of a newly drilled or recompleted well,
the approval to abandon may be written
or oral with written confirmation.
(b) Completion of a well as plugged
and abandoned may also include
conditioning the well as a water supply
source for lease operations or for use by
the surface owner or appropriate
Government Agency, when authorized
by the authorized officer. All costs over
and above the normal plugging and
abandonment expense will be paid by
the party accepting the water well.
(c) Upon the removal of drilling or
production equipment from the well site
which is to be permanently abandoned,
the surface of the lands disturbed in
connection with the conduct of
operations must be reclaimed in
accordance with a plan first approved or
prescribed by the authorized officer.
(d) Operators of temporarily
abandoned wells must:
(1) Receive prior approval from the
authorized officer for any well
temporarily abandoned for more than 30
days. The authorized officer may
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authorize a delay in the permanent
abandonment of a well for a period of
up to 1 year. The operator must provide:
(i) Adequate and detailed justification
for the temporary abandonment;
(ii) Verification of the mechanical
integrity of the well; and
(iii) Isolate the completed interval(s)
prior to temporary abandonment.
(2) Receive prior approval from the
authorized officer for any additional
delays to permanently abandon a well
beyond 1 year. The authorized officer
may authorize additional delays, none
of which may exceed an additional 1year period. Each request for additional
delay must provide adequate and
detailed justification for continued
temporary abandonment.
(3) Within 4 years of temporary
abandonment of a well, complete one of
the following actions:
(i) Permanently abandon the well;
(ii) Resume production in paying
quantities or commence using the well
for injection or disposal;
(iii) Provide the authorized officer
with a detailed plan and timeline for
future beneficial use of the well. If the
authorized officer determines that there
is a legitimate future beneficial use for
the well, the officer may allow the
operator to delay permanent
abandonment by 1 additional year. The
authorized officer may grant additional
delays in 1-year increments, provided
that the operator confirms the future
beneficial use of the well and is making
verifiable progress on returning the well
to a beneficial use.
(e) Operators of shut-in wells must:
(1) Notify the authorized officer of the
well’s shut-in status, if the well will be
shut-in for 90 or more consecutive days,
and provide the date the well was shutin within 90 days of well shut-in;
(2) Within 3 years of well shut-in,
provide the authorized officer with
verification of the mechanical integrity
of the well and confirmation that the
well remains capable of producing in
paying quantities; and
(3) Within 4 years of well shut-in,
complete one of the following actions:
(i) Permanently abandon the well;
(ii) Resume production in paying
quantities; or
(iii) Provide the authorized officer
with a detailed plan and timeline for
future beneficial use of the well. If the
authorized officer determines that there
is a legitimate future beneficial use for
the well, the officer may allow the
operator to delay permanent
abandonment by 1 year. The authorized
officer may grant additional delays in 1year increments, provided that the
operator confirms the future beneficial
use of the well and is making verifiable
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progress on returning the well to a
beneficial use.
(f) All wells that are temporarily
abandoned or shut-in must have
mechanical integrity verified as required
in paragraphs (d)(1) and (e)(2) of this
section and must ensure that
mechanical integrity is verified every 3
years thereafter. The operator must
submit the results of each verification of
mechanical integrity to the authorized
officer within 30 days of the mechanical
integrity test.
■
15. Revise § 3164.1 to read as follows:
§ 3164.1
Onshore Oil and Gas Orders.
(a) The Director is authorized to issue
Onshore Oil and Gas Orders when
necessary to implement and supplement
the regulations in the part. All orders
will be published in final form in the
Federal Register.
(b) These Orders are binding on
operating rights owners and operators,
as appropriate, of Federal and restricted
Indian oil and gas leases which have
been, or may hereafter be, issued. There
are no current Onshore Oil and Gas
Orders currently in effect.
Note: Numbers to be assigned
sequentially by the Washington Office
as proposed Orders are prepared for
publication.
■
16. Revise § 3165.1 to read as follows:
§ 3165.1 Relief from operating and/or
producing requirements.
(a) Applications for relief from either
the operating or the producing
requirements of a lease, or both, must be
filed with the authorized officer, and
must include a full statement of the
circumstances that render such relief
necessary.
(b) The authorized officer will act on
applications submitted for a suspension
of operations or production, or both,
filed pursuant to 43 CFR 3103.42. The
application for suspension must be filed
with the authorized officer prior to the
expiration date of the lease; must be
executed by all operating rights owners
or by the operator on behalf of the
operating rights owners; and must
include a full statement of the
circumstances that makes such relief
necessary.
(c) The authorized officer will not
approve an application for a suspension
of a lease where the applicant only cites,
as the basis for the suspension, a
pending application for permit to drill
filed less than 90 calendar days prior to
the expiration date of the lease.
(d) If approved, a suspension of
operations and production will be
effective on the first of the month in
which the completed application was
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filed or the date specified by the
authorized officer in the approval.
Approved suspensions will not exceed
1 year. If the circumstances warrant all
operating rights owners, or the operator
on behalf of the operating rights owners,
may submit a request to extend the
suspension prior to the end of the
suspension.
(e) BLM-directed suspensions may
exceed 1 year.
(f) Suspensions will lift when the
basis provided for the suspension no
longer exists, when lifting the
suspension is in the public interest, or
as otherwise stated by the authorized
officer in the approval letter.
PART 3170—ONSHORE OIL AND GAS
PRODUCTION
17. 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.
■
18. Revise § 3171.6 to read as follows:
ddrumheller on DSK120RN23PROD with RULES4
§ 3171.6 Components of a complete APD
package.
Operators are encouraged to consider
and incorporate Best Management
Practices into their APDs because Best
Management Practices can result in
reduced processing times and reduced
number of Conditions of Approval. An
APD package must include the
following information that will be
reviewed by technical specialists of the
appropriate agencies to determine the
technical adequacy of the package:
(a) A completed Form 3160–3; and
(b) A well plat. Operators must
include in the APD package a well plat
and geospatial database prepared by a
registered surveyor depicting the
proposed location of the well and
identifying the points of control and
datum used to establish the section lines
or metes and bounds. The purpose of
this plat is to ensure that operations are
within the boundaries of the lease or
agreement and that the depiction of
these operations is accurately recorded
both as to location (latitude and
longitude) and in relation to the
surrounding lease or agreement
boundaries (public land survey corner
and boundary ties). The registered
surveyor should coordinate with the
cadastral survey division of the
appropriate BLM state office,
particularly where the lands have not
been surveyed under the Public Land
Survey System.
(1) The plat and geospatial database
must describe the location of operations
in:
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(i) Geographical coordinates generated
by an electronic navigation system, and
document the datum referenced to
generate these coordinates; and
(ii) In feet and direction from the
nearest two adjacent section lines, or, if
not within the Rectangular Survey
System, the nearest two adjacent
property lines, generated from the
BLM’s current Geographic Coordinate
Data Base.
(2) The surveyor who prepared the
plat must sign it, certifying that the
location has been staked on the ground
as shown on the plat.
(3) Surveying and staking are
necessary casual uses, typically
involving negligible surface disturbance.
The operator is responsible for making
access arrangements with the
appropriate Surface Managing Agency
(other than the BLM and the FS) or
private surface owner. On tribal or
allotted lands, the operator must contact
the appropriate office of the BIA to
make access arrangements with the
Indian surface owners. In the event that
not all of the Indian owners consent or
may be located, but a majority of those
who can be located consent, or the
owners of interests are so numerous that
it would be impracticable to obtain their
consent and the BIA finds that the
issuance of the APD will cause no
substantive injury to the land or any
owner thereof, the BIA may approve
access. Typical off-road vehicular use,
when conducted in conjunction with
these activities, is a necessary action for
obtaining a permit and may be done
without advance approval from the
Surface Managing Agency, except for:
(i) Lands administered by the
Department of Defense;
(ii) Other lands used for military
purposes;
(iii) Indian lands; or
(iv) Where more than negligible
surface disturbance is likely to occur or
is otherwise prohibited.
(4) No entry on split estate lands for
surveying and staking should occur
without the operator first making a good
faith effort to notify the surface owner.
Also, operators are encouraged to notify
the BLM or the FS, as appropriate,
before entering private lands to stake for
Federal mineral estate locations.
■ 19. Revise § 3171.14 to read as
follows:
§ 3171.14
Valid Period of Approved APD.
(a) For APDs approved after June 22,
2024, an APD approval is valid for 3
years from the date that it is approved,
or until lease expiration, whichever
occurs first.
(b) Notwithstanding paragraph (a) of
this section, if an APD approval expires
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30997
by reason other than lease expiration,
the APD approval shall remain valid if
the operator or lessee:
(1) Has drilled the well to the
approximate total measured depth in
the approved APD, including wells
drilled to the approximate total
measured depth and not yet completed;
(2) Is drilling the well with a rig
capable of drilling the well to the
proposed total measured depth in the
approved APD; or
(3) Has set the surface casing for the
well and has submitted a plan,
approved by the BLM prior to expiration
of the APD approval, for continuously
drilling the well to reach the proposed
total measured depth in the approved
APD. The plan must include the
timeframe for continuously drilling and
completing the well and any
extenuating circumstances that may
delay the continuous drilling and
completion of the well.
(c) If, upon expiration of the approved
APD, the operator created surface
disturbance or began drilling the well
under the approved APD, the operator
or lessee must either comply with all
applicable plugging, abandonment, and
reclamation requirements or submit a
new APD covering the existing
disturbance.
(d) The operator is responsible for
reclaiming any surface disturbance that
resulted from its actions, even if a well
was not drilled. Earthwork for
reclamation must be completed within 6
months of APD expiration (weather
permitting).
(e) The valid period for an approved
APD on a lease suspended under
subpart 3103 will be adjusted to account
for the suspension. Beginning on the
date the suspension is lifted, the valid
period of the approved APD will be
extended by the time that was
remaining on the term of the approved
APD on the effective date of the
suspension.
PART 3180—ONSHORE OIL AND GAS
UNIT AGREEMENTS: UNPROVEN
AREAS
20. The authority citation for part
3180 continues to read as follows:
■
Authority: 30 U.S.C. 189.
§ 3181.1
[Amended]
21. Amend § 3181.1 by removing the
phrase ‘‘§ 3186.1 of this title’’ wherever
it appears and adding in its place the
phrase ‘‘appendix A to this part’’.
■
■
22. Revise § 3181.5 to read as follows:
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§ 3181.5 Compensatory royalty payment
for unleased Federal land.
The unit agreement submitted by the
unit proponent for approval by the
authorized officer will provide for
payment to the Federal Government of
the current royalty percentage for leases
offered on onshore oil and gas lease
sales on production that would be
attributable to unleased Federal lands in
a PA of the unit if said lands were
leased and committed to the unit
agreement. The value of production
subject to compensatory royalty
payment will be determined pursuant to
30 CFR part 206, provided that no
additional royalty will be due on any
production subject to compensatory
royalty under this provision.
§ 3183.4
[Amended]
23. Amend § 3183.4 in paragraph (a)
by removing the phrase ‘‘§ 3186.1 of this
title’’ and adding in its place the phrase
‘‘appendix A to this part’’.
■
§ 3186.1 [Redesignated as Appendix A to
Part 3180]
24. Redesignate § 3186.1 as appendix
A to part 3180 and revise it to read as
follows:
■
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Appendix A to Part 3180—Model
onshore unit agreement for unproven
areas.
Introductory Section
1 Enabling Act and Regulations.
2 Unit Area.
3 Unitized Land and Unitized Substances.
4 Unit Operator.
5 Resignation or Removal of Unit Operator.
6 Successor Unit Operator.
7 Accounting Provisions and Unit
Operating Agreement.
8 Rights and Obligations of Unit Operator.
9 Drilling to Discovery.
10 Plan of Further Development and
Operation.
11 Participation After Discovery.
12 Allocation of Production.
13 Development or Operation of
Nonparticipating Land or Formations.
14 Royalty Settlement.
15 Rental Settlement.
16 Conservation.
17 Drainage.
18 Leases and Contracts Conformed and
Extended.
19 Covenants Run with Land.
20 Effective Date and Term.
21 Rate of Prospecting, Development, and
Production.
22 Appearances.
23 Notices.
24 No Waiver of Certain Rights.
25 Unavoidable Delay.
26 Nondiscrimination.
27 Loss of Title.
28 Nonjoinder and Subsequent Joinder.
29 Counterparts.
30 Surrender.[1]
31 Taxes.[1]
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32 No Partnership.[1]
Concluding Section in witness whereof.
General Guidelines.
Certification—Determination.
Unit Agreement for the Development and
Operation of the
Unit area llllllllllllllll
County of llllllllllllllll
State of lllllllllllllllll
No. lllllllllllllllllll
This agreement, entered into as of the ll
day of llll , 19ll by and between the
parties subscribing, ratifying, or consenting
hereto, and herein referred to as the ‘‘parties
hereto,’’
Witnesseth:
Whereas, the parties hereto are the owners
of working, royalty, or other oil and gas
interests in the unit area subject to this
agreement; and
Whereas, the Mineral Leasing Act of
February 25, 1920, 41 Stat. 437, as amended,
30 U.S.C. 181 et seq., authorizes Federal
lessees and their representatives to unite
with each other, or jointly or separately with
others, in collectively adopting and operating
under a unit plan of development or
operations of any oil and gas pool, field, or
like area, or any part thereof for the purpose
of more properly conserving the natural
resources thereof whenever determined and
certified by the Secretary of the Interior to be
necessary or advisable in the public interest;
and
Whereas, the parties hereto hold sufficient
interests in the ll Unit Area covering the
land hereinafter described to give reasonably
effective control of operations therein; and
Whereas, it is the purpose of the parties
hereto to conserve natural resources, prevent
waste, and secure other benefits obtainable
through development and operation of the
area subject to this agreement under the
terms, conditions, and limitations herein set
forth;
Now, therefore, in consideration of the
premises and the promises herein contained,
the parties hereto commit to this agreement
their respective interests in the belowdefined unit area, and agree severally among
themselves as follows:
1. ENABLING ACT AND REGULATIONS.
The Mineral Leasing Act of February 25,
1920, as amended, supra, and all valid
pertinent regulations including operating and
unit plan regulations, heretofore issued
thereunder or valid, pertinent, and
reasonable regulations hereafter issued
thereunder are accepted and made a part of
this agreement as to Federal lands, provided
such regulations are not inconsistent with the
terms of this agreement; and as to nonFederal lands, the oil and gas operating
regulations in effect as of the effective date
hereof governing drilling and producing
operations, not inconsistent with the terms
hereof or the laws of the State in which the
non-Federal land is located, are hereby
accepted and made a part of this agreement.
2. UNIT AREA. The area specified on the
map attached hereto marked Exhibit A is
hereby designated and recognized as
constituting the unit area, containing ll
acres, more or less.
Exhibit A shows, in addition to the
boundary of the unit area, the boundaries and
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identity of tracts and leases in said area to
the extent known to the Unit Operator.
Exhibit B attached hereto is a schedule
showing to the extent known to the Unit
Operator, the acreage, percentage, and kind
of ownership of oil and gas interests in all
lands in the unit area. However, nothing
herein or in Exhibits A or B shall be
construed as a representation by any party
hereto as to the ownership of any interest
other than such interest or interests as are
shown in the Exhibits as owned by such
party. Exhibits A and B shall be revised by
the Unit Operator whenever changes in the
unit area or in the ownership interests in the
individual tracts render such revision
necessary, or when requested by the
Authorized Officer, hereinafter referred to as
AO and not less than four copies of the
revised Exhibits shall be filed with the
proper BLM office.
The above-described unit area shall when
practicable be expanded to include therein
any additional lands or shall be contracted to
exclude lands whenever such expansion or
contraction is deemed to be necessary or
advisable to conform with the purposes of
this agreement. Such expansion or
contraction shall be effected in the following
manner:
(a) Unit Operator, on its own motion (after
preliminary concurrence by the AO), or on
demand of the AO, shall prepare a notice of
proposed expansion or contraction
describing the contemplated changes in the
boundaries of the unit area, the reasons
therefor, any plans for additional drilling,
and the proposed effective date of the
expansion or contraction, preferably the first
day of a month subsequent to the date of
notice.
(b) Said notice shall be delivered to the
proper BLM office, and copies thereof mailed
to the last known address of each working
interest owner, lessee and lessor whose
interests are affected, advising that 30 days
will be allowed for submission to the Unit
Operator of any objections.
(c) Upon expiration of the 30-day period
provided in the preceding item (b) hereof,
Unit Operator shall file with the AO evidence
of mailing of the notice of expansion or
contraction and a copy of any objections
thereto which have been filed with Unit
Operator, together with an application in
triplicate, for approval of such expansion or
contraction and with appropriate joinders.
(d) After due consideration of all pertinent
information, the expansion or contraction
shall, upon approval by the AO, become
effective as of the date prescribed in the
notice thereof or such other appropriate date.
(e) All legal subdivisions of lands (i.e., 40
acres by Government survey or its nearest lot
or tract equivalent; in instances of irregular
surveys, unusually large lots or tracts shall be
considered in multiples of 40 acres or the
nearest aliquot equivalent thereof), no parts
of which are in or entitled to be in a
participating area on or before the fifth
anniversary of the effective date of the first
initial participating area established under
this unit agreement, shall be eliminated
automatically from this agreement, effective
as of said fifth anniversary, and such lands
shall no longer be a part of the unit area and
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shall no longer be subject to this agreement,
unless diligent drilling operations are in
progress on unitized lands not entitled to
participation on said fifth anniversary, in
which event all such lands shall remain
subject hereto for so long as such drilling
operations are continued diligently, with not
more than 90-days time elapsing between the
completion of one such well and the
commencement of the next such well. All
legal subdivisions of lands not entitled to be
in a participating area within 10 years after
the effective date of the first initial
participating area approved under this
agreement shall be automatically eliminated
from this agreement as of said tenth
anniversary. The Unit Operator shall, within
90 days after the effective date of any
elimination hereunder, describe the area so
eliminated to the satisfaction of the AO and
promptly notify all parties in interest. All
lands reasonably proved productive of
unitized substances in paying quantities by
diligent drilling operations after the aforesaid
5-year period shall become participating in
the same manner as during said first 5-year
period. However, when such diligent drilling
operations cease, all nonparticipating lands
not then entitled to be in a participating area
shall be automatically eliminated effective as
the 91st day thereafter.
Any expansion of the unit area pursuant to
this section which embraces lands
theretofore eliminated pursuant to this
subsection 2(e) shall not be considered
automatic commitment or recommitment of
such lands. If conditions warrant extension
of the 10-year period specified in this
subsection, a single extension of not to
exceed 2 years may be accomplished by
consent of the owners of 90 percent of the
working interest in the current
nonparticipating unitized lands and the
owners of 60 percent of the basic royalty
interests (exclusive of the basic royalty
interests of the United States) in
nonparticipating unitized lands with
approval of the AO, provided such extension
application is submitted not later than 60
days prior to the expiration of said 10-year
period.
3. UNITIZED LAND AND UNITIZED
SUBSTANCES. All land now or hereafter
committed to this agreement shall constitute
land referred to herein as ‘‘unitized land’’ or
‘‘land subject to this agreement.’’ All oil and
gas in any and all formations of the unitized
land are unitized under the terms of this
agreement and herein are called ‘‘unitized
substances.’’
4. UNIT OPERATOR. llll is hereby
designated as Unit Operator and by signature
hereto as Unit Operator agrees and consents
to accept the duties and obligations of Unit
Operator for the discovery, development, and
production of unitized substances as herein
provided. Whenever reference is made herein
to the Unit Operator, such reference means
the Unit Operator acting in that capacity and
not as an owner of interest in unitized
substances, and the term ‘‘working interest
owner’’ when used herein shall include or
refer to Unit Operator as the owner of a
working interest only when such an interest
is owned by it.
5. RESIGNATION OR REMOVAL OF UNIT
OPERATOR. Unit Operator shall have the
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right to resign at any time prior to the
establishment of a participating area or areas
hereunder, but such resignation shall not
become effective so as to release Unit
Operator from the duties and obligations of
Unit Operator and terminate Unit Operator’s
rights as such for a period of 6 months after
notice of intention to resign has been served
by Unit Operator on all working interest
owners and the AO and until all wells then
drilled hereunder are placed in a satisfactory
condition for suspension or abandonment,
whichever is required by the AO, unless a
new Unit Operator shall have been selected
and approved and shall have taken over and
assumed the duties and obligations of Unit
Operator prior to the expiration of said
period.
Unit Operator shall have the right to resign
in like manner and subject to like limitations
as above provided at any time after a
participating area established hereunder is in
existence, but in all instances of resignation
or removal, until a successor Unit Operator
is selected and approved as hereinafter
provided, the working interest owners shall
be jointly responsible for performance of the
duties of Unit Operator, and shall not later
than 30 days before such resignation or
removal becomes effective appoint a common
agent to represent them in any action to be
taken hereunder.
The resignation of Unit Operator shall not
release Unit Operator from any liability for
any default by it hereunder occurring prior
to the effective date of its resignation.
The Unit Operator may, upon default or
failure in the performance of its duties or
obligations hereunder, be subject to removal
by the same percentage vote of the owners of
working interests as herein provided for the
selection of a new Unit Operator. Such
removal shall be effective upon notice thereof
to the AO.
The resignation or removal of Unit
Operator under this agreement shall not
terminate its right, title, or interest as the
owner of working interest or other interest in
unitized substances, but upon the resignation
or removal of Unit Operator becoming
effective, such Unit Operator shall deliver
possession of all wells, equipment, materials,
and appurtenances used in conducting the
unit operations to the new duly qualified
successor Unit Operator or to the common
agent, if no such new Unit Operator is
selected to be used for the purpose of
conducting unit operations hereunder.
Nothing herein shall be construed as
authorizing removal of any material,
equipment, or appurtenances needed for the
preservation of any wells.
6. SUCCESSOR UNIT OPERATOR.
Whenever the Unit Operator shall tender his
or its resignation as Unit Operator or shall be
removed as hereinabove provided, or a
change of Unit Operator is negotiated by the
working interest owners, the owners of the
working interests according to their
respective acreage interests in all unitized
land shall, pursuant to the Approval of the
Parties requirements of the unit operating
agreement, select a successor Unit Operator.
Such selection shall not become effective
until:
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30999
(a) a Unit Operator so selected shall accept
in writing the duties and responsibilities of
Unit Operator, and
(b) the selection shall have been approved
by the AO.
If no successor Unit Operator is selected
and qualified as herein provided, the AO at
his election may declare this unit agreement
terminated.
7. ACCOUNTING PROVISIONS AND UNIT
OPERATING AGREEMENT. If the Unit
Operator is not the sole owner of working
interests, costs and expenses incurred by
Unit Operator in conducting unit operations
hereunder shall be paid and apportioned
among and borne by the owners of working
interests, all in accordance with the
agreement or agreements entered into by and
between the Unit Operator and the owners of
working interests, whether one or more,
separately or collectively. Any agreement or
agreements entered into between the working
interest owners and the Unit Operator as
provided in this section, whether one or
more, are herein referred to as the ‘‘unit
operating agreement.’’ Such unit operating
agreement shall also provide the manner in
which the working interest owners shall be
entitled to receive their respective
proportionate and allocated share of the
benefits accruing hereto in conformity with
their underlying operating agreements,
leases, or other independent contracts, and
such other rights and obligations as between
Unit Operator and the working interest
owners as may be agreed upon by Unit
Operator and the working interest owners;
however, no such unit operating agreement
shall be deemed either to modify any of the
terms and conditions of this unit agreement
or to relieve the Unit Operator of any right
or obligation established under this unit
agreement, and in case of any inconsistency
or conflict between this agreement and the
unit operating agreement, this agreement
shall govern. Two copies of any unit
operating agreement executed pursuant to
this section shall be filed in the proper BLM
office prior to approval of this unit
agreement.
8. RIGHTS AND OBLIGATIONS OF UNIT
OPERATOR. Except as otherwise specifically
provided herein, the exclusive right,
privilege, and duty of exercising any and all
rights of the parties hereto which are
necessary or convenient for prospecting for,
producing, storing, allocating, and
distributing the unitized substances are
hereby delegated to and shall be exercised by
the Unit Operator as herein provided.
Acceptable evidence of title to said rights
shall be deposited with Unit Operator and,
together with this agreement, shall constitute
and define the rights, privileges, and
obligations of Unit Operator. Nothing herein,
however, shall be construed to transfer title
to any land or to any lease or operating
agreement, it being understood that under
this agreement the Unit Operator, in its
capacity as Unit Operator, shall exercise the
rights of possession and use vested in the
parties hereto only for the purposes herein
specified.
9. DRILLING TO DISCOVERY. Within 6
months after the effective date hereof, the
Unit Operator shall commence to drill an
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adequate test well at a location approved by
the AO, unless on such effective date a well
is being drilled in conformity with the terms
hereof, and thereafter continue such drilling
diligently until the ll formation has been
tested or until at a lesser depth unitized
substances shall be discovered which can be
produced in paying quantities (to wit:
quantities sufficient to repay the costs of
drilling, completing, and producing
operations, with a reasonable profit) or the
Unit Operator shall at any time establish to
the satisfaction of the AO that further drilling
of said well would be unwarranted or
impracticable, provided, however, that Unit
Operator shall not in any event be required
to drill said well to a depth in excess of ll
feet. Until the discovery of unitized
substances capable of being produced in
paying quantities, the Unit Operator shall
continue drilling one well at a time, allowing
not more than 6 months between the
completion of one well and the
commencement of drilling operations for the
next well, until a well capable of producing
unitized substances in paying quantities is
completed to the satisfaction of the AO or
until it is reasonably proved that the unitized
land is incapable of producing unitized
substances in paying quantities in the
formations drilled hereunder. Nothing in this
section shall be deemed to limit the right of
the Unit Operator to resign as provided in
Section 5, hereof, or as requiring Unit
Operator to commence or continue any
drilling during the period pending such
resignation becoming effective in order to
comply with the requirements of this section.
The AO may modify any of the drilling
requirements of this section by granting
reasonable extensions of time when, in his
opinion, such action is warranted.
[2] 9a. MULTIPLE WELL REQUIREMENTS.
Notwithstanding anything in this unit
agreement to the contrary, except Section 25,
UNAVOIDABLE DELAY, ll wells shall be
drilled with not more than 6-months time
elapsing between the completion of the first
well and commencement of drilling
operations for the second well and with not
more than 6-months time elapsing between
completion of the second well and the
commencement of drilling operations for the
third well, . . . regardless of whether a
discovery has been made in any well drilled
under this provision. Both the initial well
and the second well must be drilled in
compliance with the above specified
formation or depth requirements in order to
meet the dictates of this section; and the
second well must be located a minimum of
ll miles from the initial well in order to
be accepted by the AO as the second unit test
well, within the meaning of this section. The
third test well shall be diligently drilled, at
a location approved by the AO, to test the
ll formation or to a depth of ll feet,
whichever is the lesser, and must be located
a minimum of ll miles from both the
initial and the second test wells.
Nevertheless, in the event of the discovery of
unitized substances in paying quantities by
any well, this unit agreement shall not
terminate for failure to complete the ll
well program, but the unit area shall be
contracted automatically, effective the first
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day of the month following the default, to
eliminate by subdivisions (as defined in
Section 2(e) hereof) all lands not then
entitled to be in a participating area.
Until the establishment of a participating
area, the failure to commence a well
subsequent to the drilling of the initial
obligation well, or in the case of multiple
well requirements, if specified, subsequent to
the drilling of those multiple wells, as
provided for in this (these) section(s), within
the time allowed including any extension of
time granted by the AO, shall cause this
agreement to terminate automatically. Upon
failure to continue drilling diligently any
well other than the obligation well(s)
commenced hereunder, the AO may, after 15days’ notice to the Unit Operator, declare this
unit agreement terminated. Failure to
commence drilling the initial obligation well,
or the first of multiple obligation wells, on
time and to drill it diligently shall result in
the unit agreement approval being declared
invalid ab initio by the AO. In the case of
multiple well requirements, failure to
commence drilling the required multiple
wells beyond the first well, and to drill them
diligently, may result in the unit agreement
approval being declared invalid ab initio by
the AO;
10. PLAN OF FURTHER DEVELOPMENT
AND OPERATION. Within 6 months after
completion of a well capable of producing
unitized substances in paying quantities, the
Unit Operator shall submit for the approval
of the AO an acceptable plan of development
and operation for the unitized land which,
when approved by the authorized officer,
shall constitute the further drilling and
development obligations of the Unit Operator
under this agreement for the period specified
therein. Thereafter, from time to time before
the expiration of any existing plan, the Unit
Operator shall submit for the approval of the
AO a plan for an additional specified period
for the development and operation of the
unitized land. Subsequent plans should
normally be filed on a calendar year basis not
later than March 1 each year. Any proposed
modification or addition to the existing plan
should be filed as a supplement to the plan.
Any plan submitted pursuant to this
section shall provide for the timely
exploration of the unitized area, and for the
diligent drilling necessary for determination
of the area or areas capable of producing
unitized substances in paying quantities in
each and every productive formation. This
plan shall be as complete and adequate as the
AO may determine to be necessary for timely
development and proper conservation of the
oil and gas resources in the unitized area and
shall:
(a) Specify the number and locations of any
wells to be drilled and the proposed order
and time for such drilling; and
(b) Provide a summary of operations and
production for the previous year.
Plans shall be modified or supplemented
when necessary to meet changed conditions
or to protect the interests of all parties to this
agreement. Reasonable diligence shall be
exercised in complying with the obligations
of the approved plan of development and
operation. The AO is authorized to grant a
reasonable extension of the 6-month period
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herein prescribed for submission of an initial
plan of development and operation where
such action is justified because of unusual
conditions or circumstances.
After completion of a well capable of
producing unitized substances in paying
quantities, no further wells, except such as
may be necessary to afford protection against
operations not under this agreement and
such as may be specifically approved by the
AO, shall be drilled except in accordance
with an approved plan of development and
operation.
11. PARTICIPATION AFTER DISCOVERY.
Upon completion of a well capable of
producing unitized substances in paying
quantities, or as soon thereafter as required
by the AO, the Unit Operator shall submit for
approval by the AO, a schedule, based on
subdivisions of the public-land survey or
aliquot parts thereof, of all land then
regarded as reasonably proved to be
productive of unitized substances in paying
quantities. These lands shall constitute a
participating area on approval of the AO,
effective as of the date of completion of such
well or the effective date of this unit
agreement, whichever is later. The acreages
of both Federal and non-Federal lands shall
be based upon appropriate computations
from the courses and distances shown on the
last approved public-land survey as of the
effective date of each initial participating
area. The schedule shall also set forth the
percentage of unitized substances to be
allocated, as provided in Section 12, to each
committed tract in the participating area so
established, and shall govern the allocation
of production commencing with the effective
date of the participating area. A different
participating area shall be established for
each separate pool or deposit of unitized
substances or for any group thereof which is
produced as a single pool or zone, and any
two or more participating areas so
established may be combined into one, on
approval of the AO. When production from
two or more participating areas is
subsequently found to be from a common
pool or deposit, the participating areas shall
be combined into one, effective as of such
appropriate date as may be approved or
prescribed by the AO. The participating area
or areas so established shall be revised from
time to time, subject to the approval of the
AO, to include additional lands then
regarded as reasonably proved to be
productive of unitized substances in paying
quantities or which are necessary for unit
operations, or to exclude lands then regarded
as reasonably proved not to be productive of
unitized substances in paying quantities, and
the schedule of allocation percentages shall
be revised accordingly. The effective date of
any revision shall be the first of the month
in which the knowledge or information is
obtained on which such revision is
predicated; provided, however, that a more
appropriate effective date may be used if
justified by Unit Operator and approved by
the AO. No land shall be excluded from a
participating area on account of depletion of
its unitized substances, except that any
participating area established under the
provisions of this unit agreement shall
terminate automatically whenever all
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completions in the formation on which the
participating area is based are abandoned.
It is the intent of this section that a
participating area shall represent the area
known or reasonably proved to be productive
of unitized substances in paying quantities or
which are necessary for unit operations; but,
regardless of any revision of the participating
area, nothing herein contained shall be
construed as requiring any retroactive
adjustment for production obtained prior to
the effective date of the revision of the
participating area.
In the absence of agreement at any time
between the Unit Operator and the AO as to
the proper definition or redefinition of a
participating area, or until a participating
area has, or areas have, been established, the
portion of all payments affected thereby
shall, except royalty due the United States,
be impounded in a manner mutually
acceptable to the owners of committed
working interests. Royalties due the United
States shall be determined by the AO and the
amount thereof shall be deposited, as
directed by the AO, until a participating area
is finally approved and then adjusted in
accordance with a determination of the sum
due as Federal royalty on the basis of such
approved participating area.
Whenever it is determined, subject to the
approval of the AO, that a well drilled under
this agreement is not capable of production
of unitized substances in paying quantities
and inclusion in a participating area of the
land on which it is situated is unwarranted,
production from such well shall, for the
purposes of settlement among all parties
other than working interest owners, be
allocated to the land on which the well is
located, unless such land is already within
the participating area established for the pool
or deposit from which such production is
obtained. Settlement for working interest
benefits from such a nonpaying unit well
shall be made as provided in the unit
operating agreement.
12. ALLOCATION OF PRODUCTION. All
unitized substances produced from a
participating area established under this
agreement, except any part thereof used in
conformity with good operating practices
within the unitized area for drilling,
operating, and other production or
development purposes, or for repressuring or
recycling in accordance with a plan of
development and operations that has been
approved by the AO, or unavoidably lost,
shall be deemed to be produced equally on
an acreage basis from the several tracts of
unitized land and unleased Federal land, if
any, included in the participating area
established for such production. Each such
tract shall have allocated to it such
percentage of said production as the number
of acres of such tract included in said
participating area bears to the total acres of
unitized land and unleased Federal land, if
any, included in said participating area.
There shall be allocated to the working
interest owner(s) of each tract of unitized
land in said participating area, in addition,
such percentage of the production
attributable to the unleased Federal land
within the participating area as the number
of acres of such unitized tract included in
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said participating area bears to the total acres
of unitized land in said participating area, for
the payment of the compensatory royalty
specified in section 17 of this agreement.
Allocation of production hereunder for
purposes other than for settlement of the
royalty, overriding royalty, or payment out of
production obligations of the respective
working interest owners, including
compensatory royalty obligations under
section 17, shall be prescribed as set forth in
the unit operating agreement or as otherwise
mutually agreed by the affected parties. It is
hereby agreed that production of unitized
substances from a participating area shall be
allocated as provided herein, regardless of
whether any wells are drilled on any
particular part or tract of the participating
area. If any gas produced from one
participating area is used for repressuring or
recycling purposes in another participating
area, the first gas withdrawn from the latter
participating area for sale during the life of
this agreement shall be considered to be the
gas so transferred, until an amount equal to
that transferred shall be so produced for sale
and such gas shall be allocated to the
participating area from which initially
produced as such area was defined at the
time that such transferred gas was finally
produced and sold.
13. DEVELOPMENT OR OPERATION OF
NONPARTICIPATING LAND OR
FORMATIONS. Any operator may with the
approval of the AO, at such party’s sole risk,
costs, and expense, drill a well on the
unitized land to test any formation provided
the well is outside any participating area
established for that formation, unless within
90 days of receipt of notice from said party
of his intention to drill the well, the Unit
Operator elects and commences to drill the
well in a like manner as other wells are
drilled by the Unit Operator under this
agreement.
If any well drilled under this section by a
non-unit operator results in production of
unitized substances in paying quantities such
that the land upon which it is situated may
properly be included in a participating area,
such participating area shall be established or
enlarged as provided in this agreement and
the well shall thereafter be operated by the
Unit Operator in accordance with the terms
of this agreement and the unit operating
agreement.
If any well drilled under this section by a
non-unit operator that obtains production in
quantities insufficient to justify the inclusion
of the land upon which such well is situated
in a participating area, such well may be
operated and produced by the party drilling
the same, subject to the conservation
requirements of this agreement. The royalties
in amount or value of production from any
such well shall be paid as specified in the
underlying lease and agreements affected.
14. ROYALTY SETTLEMENT. The United
States and any State and any royalty owner
who is entitled to take in kind a share of the
substances now unitized hereunder shall be
hereafter be entitled to the right to take in
kind its share of the unitized substances, and
Unit Operator, or the non-unit operator in the
case of the operation of a well by a non-unit
operator as herein provided for in special
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cases, shall make deliveries of such royalty
share taken in kind in conformity with the
applicable contracts, laws, and regulations.
Settlement for royalty interest not taken in
kind shall be made by an operator
responsible therefor under existing contracts,
laws and regulations, or by the Unit Operator
on or before the last day of each month for
unitized substances produced during the
preceding calendar month; provided,
however, that nothing in this section shall
operate to relieve the responsible parties of
any land from their respective lease
obligations for the payment of any royalties
due under their leases.
If gas obtained from lands not subject to
this agreement is introduced into any
participating area hereunder, for use in
repressuring, stimulation of production, or
increasing ultimate recovery, in conformity
with a plan of development and operation
approved by the AO, a like amount of gas,
after settlement as herein provided for any
gas transferred from any other participating
area and with appropriate deduction for loss
from any cause, may be withdrawn from the
formation into which the gas is introduced,
royalty free as to dry gas, but not as to any
products which may be extracted therefrom;
provided that such withdrawal shall be at
such time as may be provided in the
approved plan of development and operation
or as may otherwise be consented to by the
AO as conforming to good petroleum
engineering practice; and provided further,
that such right of withdrawal shall terminate
on the termination of this unit agreement.
Royalty due the United States shall be
computed as provided in 30 CFR Group 200
and paid in value or delivered in kind as to
all unitized substances on the basis of the
amounts thereof allocated to unitized Federal
land as provided in Section 12 at the rates
specified in the respective Federal leases, or
at such other rate or rates as may be
authorized by law or regulation and
approved by the AO; provided, that for leases
on which the royalty rate depends on the
daily average production per well, said
average production shall be determined in
accordance with the operating regulations as
though each participating area were a single
consolidated lease.
15. RENTAL SETTLEMENT. Rental or
minimum royalties due on leases committed
hereto shall be paid by the appropriate
parties under existing contracts, laws, and
regulations, provided that nothing herein
contained shall operate to relieve the
responsible parties of the land from their
respective obligations for the payment of any
rental or minimum royalty due under their
leases. Rental or minimum royalty for lands
of the United States subject to this agreement
shall be paid at the rate specified in the
respective leases from the United States
unless such rental or minimum royalty is
waived, suspended, or reduced by law or by
approval of the Secretary or his duly
authorized representative.
With respect to any lease on non-Federal
land containing provisions which would
terminate such lease unless drilling
operations are commenced upon the land
covered thereby within the time therein
specified or rentals are paid for the privilege
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of deferring such drilling operations, the
rentals required thereby shall,
notwithstanding any other provision of this
agreement, be deemed to accrue and become
payable during the term thereof as extended
by this agreement and until the required
drilling operations are commenced upon the
land covered thereby, or until some portion
of such land is included within a
participating area.
16. CONSERVATION. Operations
hereunder and production of unitized
substances shall be conducted to provide for
the most economical and efficient recovery of
said substances without waste, as defined by
or pursuant to State or Federal law or
regulation.
17. DRAINAGE. (a) The Unit Operator shall
take such measures as the AO deems
appropriate and adequate to prevent drainage
of unitized substances from unitized land by
wells on land not subject to this agreement,
which shall include the drilling of protective
wells and which may include the payment of
a fair and reasonable compensatory royalty,
as determined by the AO.
(b) Whenever a participating area approved
under section 11 of this agreement contains
unleased Federal lands, the value of ll
(current royalty for leases offered on Federal
onshore oil and gas lease sales) ll percent
of the production that would be allocated to
such Federal lands under section 12 of this
agreement, if such lands were leased,
committed, and entitled to participation,
shall be payable as compensatory royalties to
the Federal Government. Parties to this
agreement holding working interests in
committed leases within the applicable
participating area shall be responsible for
such compensatory royalty payment on the
volume of production reallocated from the
unleased Federal lands to their unitized
tracts under section 12. The value of such
production subject to the payment of said
royalties shall be determined pursuant to 30
CFR part 206. Payment of compensatory
royalties on the production reallocated from
unleased Federal land to the committed
tracts within the participating area shall
fulfill the Federal royalty obligation for such
production, and said production shall be
subject to no further royalty assessment
under section 14 of this agreement. Payment
of compensatory royalties as provided herein
shall accrue from the date the committed
tracts in the participating area that includes
unleased Federal lands receive a production
allocation, and shall be due and payable
monthly by the last day of the calendar
month next following the calendar month of
actual production. If leased Federal lands
receiving a production allocation from the
participating area become unleased,
compensatory royalties shall accrue from the
date the Federal lands become unleased.
Payment due under this provision shall end
when the unleased Federal tract is leased or
when production of unitized substances
ceases within the participating area and the
participating area is terminated, whichever
occurs first.
18. LEASES AND CONTRACTS
CONFORMED AND EXTENDED. The terms,
conditions, and provisions of all leases,
subleases, and other contracts relating to
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exploration, drilling, development or
operation for oil or gas on lands committed
to this agreement are hereby expressly
modified and amended to the extent
necessary to make the same conform to the
provisions hereof, but otherwise to remain in
full force and effect; and the parties hereto
hereby consent that the Secretary shall and
by his approval hereof, or by the approval
hereof by his duly authorized representative,
does hereby establish, alter, change, or
revoke the drilling, producing, rental,
minimum royalty, and royalty requirements
of Federal leases committed hereto and the
regulations in respect thereto to conform said
requirements to the provisions of this
agreement, and, without limiting the
generality of the foregoing, all leases,
subleases, and contracts are particularly
modified in accordance with the following:
(a) The development and operation of
lands subject to this agreement under the
terms hereof shall be deemed full
performance of all obligations for
development and operation with respect to
each and every separately owned tract
subject to this agreement, regardless of
whether there is any development of any
particular tract of this unit area.
(b) Drilling and producing operations
performed hereunder upon any tract of
unitized lands will be accepted and deemed
to be performed upon and for the benefit of
each and every tract of unitized land, and no
lease shall be deemed to expire by reason of
failure to drill or produce wells situated on
the land therein embraced.
(c) Suspension of drilling or producing
operations on all unitized lands pursuant to
direction or consent of the AO shall be
deemed to constitute such suspension
pursuant to such direction or consent as to
each and every tract of unitized land. A
suspension of drilling or producing
operations limited to specified lands shall be
applicable only to such lands.
(d) Each lease, sublease, or contract
relating to the exploration, drilling,
development, or operation for oil or gas of
lands other than those of the United States
committed to this agreement which, by its
terms might expire prior to the termination
of this agreement, is hereby extended beyond
any such term so provided therein so that it
shall be continued in full force and effect for
and during the term of this agreement.
(e) Any Federal lease committed hereto
shall continue in force beyond the term so
provided therein or by law as to the land
committed so long as such lease remains
subject hereto, provided that production of
unitized substances in paying quantities is
established under this unit agreement prior
to the expiration date of the term of such
lease, or in the event actual drilling
operations are commenced on unitized land,
in accordance with provisions of this
agreement, prior to the end of the primary
term of such lease and are being diligently
prosecuted at that time, such lease shall be
extended for 2 years, and so long thereafter
as oil or gas is produced in paying quantities
in accordance with the provisions of the
Mineral Leasing Act, as amended.
(f) Each sublease or contract relating to the
operation and development of unitized
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substances from lands of the United States
committed to this agreement, which by its
terms would expire prior to the time at which
the underlying lease, as extended by the
immediately preceding paragraph, will
expire is hereby extended beyond any such
term so provided therein so that it shall be
continued in full force and effect for and
during the term of the underlying lease as
such term is herein extended.
(g) The segregation of any Federal lease
committed to this agreement is governed by
the following provision in the fourth
paragraph of sec. 17(m) of the Mineral
Leasing Act, as amended by the Act of
September 2, 1960 (74 Stat. 781–784) (30
U.S.C. 226(m)):
‘‘Any [Federal] lease heretofore or hereafter
committed to any such [unit] plan embracing
lands that are in part within and in part
outside of the area covered by any such plan
shall be segregated into separate leases as to
the lands committed and the lands not
committed as of the effective date of
unitization: Provided, however, That any
such lease as to the nonunitized portion shall
continue in force and effect for the term
thereof but for not less than 2 years from the
date of such segregation and so long
thereafter as oil or gas is produced in paying
quantities.’’
If the public interest requirement is not
satisfied, the segregation of a lease and/or
extension of a lease pursuant to 43 CFR
3107.32 and 43 CFR 3107.40, respectively,
shall not be effective.
[3] (h) Any lease, other than a Federal lease,
having only a portion of its lands committed
hereto shall be segregated as to the portion
committed and the portion not committed,
and the provisions of such lease shall apply
separately to such segregated portions
commencing as of the effective date hereof.
In the event any such lease provides for a
lump-sum rental payment, such payment
shall be prorated between the portions so
segregated in proportion to the acreage of the
respective tracts.
19. COVENANTS RUN WITH LAND. The
covenants herein shall be construed to be
covenants running with the land with respect
to the interests of the parties hereto and their
successors in interest until this agreement
terminates, and any grant, transfer or
conveyance of interest in land or leases
subject hereto shall be and hereby is
conditioned upon the assumption of all
privileges and obligations hereunder by the
grantee, transferee, or other successor in
interest. No assignment or transfer of any
working interest, royalty, or other interest
subject hereto shall be binding upon Unit
Operator until the first day of the calendar
month after Unit Operator is furnished with
the original, photostatic, or certified copy of
the instrument of transfer.
20. EFFECTIVE DATE AND TERM. This
agreement shall become effective upon
approval by the AO and shall automatically
terminate 5 years from said effective date
unless:
(a) Upon application by the Unit Operator
such date of expiration is extended by the
AO, or
(b) It is reasonably determined prior to the
expiration of the fixed term or any extension
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thereof that the unitized land is incapable of
production of unitized substances in paying
quantities in the formations tested hereunder,
and after notice of intention to terminate this
agreement on such ground is given by the
Unit Operator to all parties in interest at their
last known addresses, this agreement is
terminated with the approval of the AO, or
(c) A valuable discovery of unitized
substances in paying quantities has been
made or accepted on unitized land during
said initial term or any extension thereof, in
which event this agreement shall remain in
effect for such term and so long thereafter as
unitized substances can be produced in
quantities sufficient to pay for the cost of
producing same from wells on unitized land
within any participating area established
hereunder. Should production cease and
diligent drilling or reworking operations to
restore production or new production are not
in progress within 60 days and production is
not restored or should new production not be
obtained in paying quantities on committed
lands within this unit area, this agreement
will automatically terminate effective the last
day of the month in which the last unitized
production occurred, or
(d) It is voluntarily terminated as provided
in this agreement. Except as noted herein,
this agreement may be terminated at any time
prior to the discovery of unitized substances
which can be produced in paying quantities
by not less than 75 per centum, on an acreage
basis, of the working interest owners
signatory hereto, with the approval of the
AO. The Unit Operator shall give notice of
any such approval to all parties hereto. If the
public interest requirement is not satisfied,
the approval of this unit by the AO shall be
invalid.
21. RATE OF PROSPECTING,
DEVELOPMENT, AND PRODUCTION. The
AO is hereby vested with authority to alter
or modify from time to time, in his
discretion, the quantity and rate of
production under this agreement when such
quantity and rate are not fixed pursuant to
Federal or State law, or do not conform to
any Statewide voluntary conservation or
allocation program which is established,
recognized, and generally adhered to by the
majority of operators in such State. The
above authority is hereby limited to
alteration or modifications which are in the
public interest. The public interest to be
served and the purpose thereof, must be
stated in the order of alteration or
modification. Without regard to the
foregoing, the AO is also hereby vested with
authority to alter or modify from time to
time, in his discretion, the rate of prospecting
and development and the quantity and rate
of production under this agreement when
such alteration or modification is in the
interest of attaining the conservation
objectives stated in this agreement and is not
in violation of any applicable Federal or State
law.
Powers is the section vested in the AO
shall only be exercised after notice to Unit
Operator and opportunity for hearing to be
held not less than 15 days from notice.
22. APPEARANCES. The Unit Operator
shall, after notice to other parties affected,
have the right to appear for and on behalf of
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any and all interests affected hereby before
the Department of the Interior and to appeal
from orders issued under the regulations of
said Department, or to apply for relief from
any of said regulations, or in any proceedings
relative to operations before the Department,
or any other legally constituted authority;
provided, however, that any other interested
party shall also have the right at its own
expense to be heard in any such proceeding.
23. NOTICES. All notices, demands, or
statements required hereunder to be given or
rendered to the parties hereto shall be in
writing and shall be personally delivered to
the party or parties, or sent by postpaid
registered or certified mail, to the last-known
address of the party or parties.
24. NO WAIVER OF CERTAIN RIGHTS.
Nothing contained in this agreement shall be
construed as a waiver by any party hereto of
the right to assert any legal or constitutional
right or defense as to the validity or
invalidity of any law of the State where the
unitized lands are located, or of the United
States, or regulations issued thereunder in
any way affecting such party, or as a waiver
by any such party of any right beyond his or
its authority to waive.
25. UNAVOIDABLE DELAY. All
obligations under this agreement requiring
the Unit Operator to commence or continue
drilling, or to operate on, or produce unitized
substances from any of the lands covered by
this agreement, shall be suspended while the
Unit Operator, despite the exercise of due
care and diligence, is prevented from
complying with such obligations, in whole or
in part, by strikes, acts of God, Federal, State,
or municipal law or agencies, unavoidable
accidents, uncontrollable delays in
transportation, inability to obtain necessary
materials or equipment in the open market,
or other matters beyond the reasonable
control of the Unit Operator, whether similar
to matters herein enumerated or not.
26. NONDISCRIMINATION. In connection
with the performance of work under this
agreement, the Unit Operator agrees to
comply with all the provisions of section 202
(1) to (7) inclusive, of E.O. 11246 (30 FR
12319), as amended, which are hereby
incorporated by reference in this agreement.
27. LOSS OF TITLE. In the event title to
any tract of unitized land shall fail and the
true owner cannot be induced to join in this
unit agreement, such tract shall be
automatically regarded as not committed
hereto, and there shall be such readjustment
of future costs and benefits as may be
required on account of the loss of such title.
In the event of a dispute as to title to any
royalty, working interest, or other interests
subject thereto, payment or delivery on
account thereof may be withheld without
liability for interest until the dispute is
finally settled; provided, that, as to Federal
lands or leases, no payments of funds due the
United States shall be withheld, but such
funds shall be deposited as directed by the
AO, to be held as unearned money pending
final settlement of the title dispute, and then
applied as earned or returned in accordance
with such final settlement.
Unit Operator as such is relieved from any
responsibility for any defect or failure of any
title hereunder.
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31003
28. NONJOINDER AND SUBSEQUENT
JOINDER. If the owner of any substantial
interest in a tract within the unit area fails
or refuses to subscribe or consent to this
agreement, the owner of the working interest
in that tract may withdraw the tract from this
agreement by written notice delivered to the
proper BLM office and the Unit Operator
prior to the approval of this agreement by the
AO. Any oil or gas interests in lands within
the unit area not committed hereto prior to
final approval may thereafter be committed
hereto by the owner or owners thereof
subscribing or consenting to this agreement,
and, if the interest is a working interest, by
the owner of such interest also subscribing to
the unit operating agreement. After
operations are commenced hereunder, the
right of subsequent joinder, as provided in
this section, by a working interest owner is
subject to such requirements or approval(s),
if any, pertaining to such joinder, as may be
provided for in the unit operating agreement.
After final approval hereof, joinder by a
nonworking interest owner must be
consented to in writing by the working
interest owner committed hereto and
responsible for the payment of any benefits
that may accrue hereunder in behalf of such
nonworking interest. A nonworking interest
may not be committed to this unit agreement
unless the corresponding working interest is
committed hereto. Joinder to the unit
agreement by a working interest owner, at
any time, must be accompanied by
appropriate joinder to the unit operating
agreement, in order for the interest to be
regarded as committed to this agreement.
Except as may otherwise herein be provided,
subsequent joinders to this agreement shall
be effective as of the date of the filing with
the AO of duly executed counterparts of all
or any papers necessary to establish effective
commitment of any interest and/or tract to
this agreement.
29. COUNTERPARTS. This agreement may
be executed in any number of counterparts,
no one of which needs to be executed by all
parties, or may be ratified or consented to by
separate instrument in writing specifically
referring hereto and shall be binding upon all
those parties who have executed such a
counterpart, ratification, or consent hereto
with the same force and effect as if all such
parties had signed the same document, and
regardless of whether or not it is executed by
all other parties owning or claiming an
interest in the lands within the abovedescribed unit area.
[4] 30. SURRENDER. Nothing in this
agreement shall prohibit the exercise by any
working interest owner of the right to
surrender vested in such party by any lease,
sublease, or operating agreement as to all or
any part of the lands covered thereby,
provided that each party who will or might
acquire such working interest by such
surrender or by forfeiture as hereafter set
forth, is bound by the terms of this
agreement.
If as a result of any such surrender, the
working interest rights as to such lands
become vested in any party other than the fee
owner of the unitized substances, said party
may forfeit such rights and further benefits
from operations hereunder as to said land to
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the party next in the chain of title who shall
be and become the owner of such working
interest.
If as the result of any such surrender or
forfeiture working interest rights become
vested in the fee owner of the unitized
substances, such owner may:
(a) Accept those working interest rights
subject to this agreement and the unit
operating agreement; or
(b) Lease the portion of such land as is
included in a participating area established
hereunder subject to this agreement and the
unit operating agreement; or
(c) Provide for the independent operation
of any part of such land that is not then
included within a participating area
established hereunder.
If the fee owner of the unitized substances
does not accept the working interest rights
subject to this agreement and the unit
operating agreement or lease such lands as
above provided within 6 months after the
surrendered or forfeited, working interest
rights become vested in the fee owner; the
benefits and obligations of operations
accruing to such lands under this agreement
and the unit operating agreement shall be
shared by the remaining owners of unitized
working interests in accordance with their
respective working interest ownerships, and
such owners of working interests shall
compensate the fee owner of unitized
substances in such lands by paying sums
equal to the rentals, minimum royalties, and
royalties applicable to such lands under the
lease in effect when the lands were unitized.
An appropriate accounting and settlement
shall be made for all benefits accruing to or
payments and expenditures made or incurred
on behalf of such surrendered or forfeited
working interests subsequent to the date of
surrender or forfeiture, and payment of any
moneys found to be owing by such an
accounting shall be made as between the
parties within 30 days.
The exercise of any right vested in a
working interest owner to reassign such
working interest to the party from whom
obtained shall be subject to the same
conditions as set forth in this section in
regard to the exercise of a right to surrender.
[4] 31. TAXES. The working interest owners
shall render and pay for their account and
the account of the royalty owners all valid
taxes on or measured by the unitized
substances in and under or that may be
produced, gathered and sold from the land
covered by this agreement after its effective
date, or upon the proceeds derived
therefrom. The working interest owners on
each tract shall and may charge the proper
proportion of said taxes to royalty owners
having interests in said-tract, and may
currently retain and deduct a sufficient
amount of the unitized substances or
derivative products, or net proceeds thereof,
from the allocated share of each royalty
owner to secure reimbursement for the taxes
so paid. No such taxes shall be charged to the
United States or the State of llll or to
any lessor who has a contract with his lessee
which requires the lessee to pay such taxes.
[4] 32. NO PARTNERSHIP. It is expressly
agreed that the relation of the parties hereto
is that of independent contractors and
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nothing contained in this agreement,
expressed or implied, nor any operations
conducted hereunder, shall create or be
deemed to have created a partnership or
association between the parties hereto or any
of them.
In witness whereof, the parties hereto have
caused this agreement to be executed and
have set opposite their respective names the
date of execution.
Unit Operator llllllllllllll
Working Interest Owners lllllllll
Other Interest Owners llllllllll
General Guidelines
1. Executed agreement to be legally
complete.
2. Agreement submitted for approval must
contain Exhibit A and B in accordance with
models shown in Appendix B to part 3180
and Appendix C to part 3180.
3. Consents should be identified (in pencil)
by tract numbers as listed in Exhibit B and
assembled in that order as far as practical.
Unit agreements submitted for approval shall
include a list of the overriding royalty
interest owners who have executed
ratifications of the unit agreement.
Subsequent joinders by overriding royalty
interest owners shall be submitted in the
same manner, except each must include or be
accompanied by a statement that the
corresponding working interest owner has
consented in writing to such joinder. Original
ratifications of overriding royalty owners will
be kept on file by the Unit Operator or his
designated agent.
4. All leases held by option should be
noted on Exhibit B with an explanation as to
the type of option, i.e., whether for operating
rights only, for full leasehold record title, or
for certain interests to be earned by
performance. In all instances, optionee
committing such interests is expected to
exercise option promptly.
5. All owners of oil and gas interests must
be invited to join the unit agreement, and
statement to that effect must accompany
executed agreement, together with summary
of results of such invitations. A written
reason for all interest owners who have not
joined shall be furnished by the unit
operator.
6. In the event fish and wildlife lands are
included, add the following as a separate
section:
‘‘Wildlife Stipulation. Nothing in this unit
agreement shall modify the special Federal
lease stipulations applicable to lands under
the jurisdiction of the United States Fish and
Wildlife Service.’’
7. In the event National Forest System
lands are included within the unit area, add
the following as a separate section:
‘‘Forest Land Stipulation. Notwithstanding
any other terms and conditions contained in
this agreement, all of the stipulations and
conditions of the individual leases between
the United States and its lessees or their
successors or assigns embracing lands within
the unit area included for the protection of
lands or functions under the jurisdiction of
the Secretary of Agriculture shall remain in
full force and effect the same as though this
agreement had not been entered into, and no
modification thereof is authorized except
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with the prior consent in writing of the
Regional Forester, United States Forest
Service, ll, llll.’’
8. In the event National Forest System
lands within the Jackson Hole Area of
Wyoming are included within the unit area,
additional ‘‘special’’ stipulations may be
required to be included in the unit agreement
by the U.S. Forest Service, including the
Jackson Hole Special Stipulation.
9. In the event reclamation lands are
included, add the following as a new
separate section:
‘‘Reclamation Lands. Nothing in this
agreement shall modify the special, Federal
lease stipulations applicable to lands under
the jurisdiction of the Bureau of
Reclamation.’’
10. In the event a powersite is embraced in
the proposed unit area, the following section
should be added:
‘‘Powersite. Nothing in this agreement
shall modify the special, Federal lease
stipulations applicable to lands under the
jurisdiction of the Federal Energy Regulatory
Commission.’’
11. In the event special surface stipulations
have been attached to any of the Federal oil
and gas leases to be included, add the
following as a separate section:
‘‘Special surface stipulations. Nothing in
this agreement shall modify the special
Federal lease stipulations attached to the
individual Federal oil leases.’’
12. In the event State lands are included
in the proposed unit area, add the
appropriate State Lands Section as separate
section. (See § 3181.4(a)).
13. In the event restricted Indian lands are
involved, consult the AO regarding
appropriate requirements under § 3181.4(b).
Certification—Determination
Pursuant to the authority vested in the
Secretary of the Interior, under the Act
approved February 25, 1920, 41 Stat. 437, as
amended, 30 U.S.C. 181, et seq., and
delegated to (the appropriate Name and Title
of the authorized officer, BLM) under the
authority of 43 CFR part 3180, I do hereby:
A. Approve the attached agreement for the
development and operation of the ll, Unit
Area, State of llll. This approval shall
be invalid ab initio if the public interest
requirement under § 3183.4(b) is not met.
B. Certify and determine that the unit plan
of development and operation contemplated
in the attached agreement is necessary and
advisable in the public interest for the
purpose of more properly conserving the
natural resources.
C. Certify and determine that the drilling,
producing, rental, minimum royalty, and
royalty requirements of all Federal leases
committed to said agreement are hereby
established altered, changed, or revoked to
conform with the terms and conditions of
this agreement.
Dated lllll.
(Name and Title of authorized officer of the
Bureau of Land Management)
Notes
[1] Optional sections (in addition the
penultimate paragraph of Section 9 is to be
included only when more than one
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obligation well is required and paragraph (h)
of section 18 is to be used only when
applicable).
[2] Provisions to be included only when a
multiple well obligation is required.
[3] Optional paragraph to be used only
when applicable.
[4] Optional sections and subsection.
(Agreements submitted for final approval
should not identify section or provision as
‘‘optional.’’)
§ 3186.1–1 [Redesignated as Appendix B
to Part 3180]
25. Redesignate § 3186.1–1 as
appendix B to part 3180.
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31005
§ 3186.1–2 [Redesignated as Appendix C
to Part 3180]
§ 3186.4 [Redesignated as Appendix E to
part 3180]
26. Redesignate § 3186.1–2 as
appendix C to part 3180.
■
■
§ 3186.2
■
[Removed]
27. Remove § 3186.2.
§ 3186.3 [Redesignated as Appendix D to
part 3180]
28. Redesignate § 3186.3 as appendix
D to part 3180.
■
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29. Redesignate § 3186.4 as appendix
E to part 3180.
This action by the Principal Deputy
Assistant Secretary is taken pursuant to
an existing delegation of authority.
Steven H. Feldgus,
Principal Deputy Assistant Secretary, Land
and Minerals Management.
[FR Doc. 2024–08138 Filed 4–22–24; 8:45 am]
BILLING CODE 4331–29–P
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| File Type | application/pdf |
| File Modified | 2024-04-23 |
| File Created | 2024-04-23 |