[Federal Register Volume 80, Number 76 (Tuesday, April 21, 2015)]
[Proposed Rules]
[Pages 22148-22156]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-09033]
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DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Part 3100
[LLWO3100 L13100000.PP0000]
RIN 1004-AE41
Oil and Gas Leasing; Royalty on Production, Rental Payments,
Minimum Acceptable Bids, Bonding Requirements, and Civil Penalty
Assessments
AGENCY: Bureau of Land Management, Interior.
ACTION: Advance notice of proposed rulemaking.
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SUMMARY: The Bureau of Land Management (BLM) is issuing this Advanced
Notice of Proposed Rulemaking (ANPR) to solicit public comments and
suggestions that may be used to update the BLM's regulations related to
royalty rates, annual rental payments, minimum acceptable bids, bonding
requirements, and civil penalty assessments for Federal onshore oil and
gas leases. As explained below, each of these elements is important to
the appropriate management of the public's oil and gas resources. They
help ensure a fair return to the taxpayer, diligent development of
leased resources, adequate reclamation when development is complete;
and that there is adequate deterrence for violations of legal
requirements, including trespass and unauthorized removal. Aspects of
these elements are fixed by statute and beyond the Secretary's
authority to revise; however, in many instances they have been further
constrained by regulatory provisions (e.g., minimum bond amounts) that
have not been reviewed or adjusted in decades. The purpose of this ANPR
is to seek comments on this situation and the need for, and content of,
potential changes or updates to the existing regulations in these
areas.
Specifically, the BLM is seeking comments and suggestions that
would assist the agency in preparing a proposed rule that gives the
Secretary of the Interior (Secretary), through the BLM, the flexibility
to adjust royalty rates in response to changes in the oil and gas
market. Absent near-term enactment of new statutory flexibility for new
non-competitively issued leases, a future proposed rule would limit any
contemplated royalty rate changes to new competitively issued oil and
gas leases on BLM-managed lands, because the royalty rate that is
charged on non-competitively issued leases is currently fixed by
statute at 12.5 percent. The intent of any anticipated changes to the
royalty rate regulations would be to provide the BLM with the necessary
tools to ensure that the American people receive a fair return on the
oil and gas resources extracted from BLM-managed lands.
In addition to the royalty rate, the BLM is also seeking input on:
(1) How to update its annual rental payment, minimum acceptable bid,
and bonding requirements for oil and gas leases, and (2) Whether to
remove the caps established by existing regulations on civil penalties
that may be assessed under the Federal Oil and Gas Royalty Management
Act (FOGRMA). With respect to annual rental payments, the intent of any
potential increase in annual payments would be to provide a greater
financial incentive for oil and gas companies to develop their leases
promptly or relinquish them, including for potential re-leasing, as
appropriate, by other parties, and to ensure that leases acquired non-
competitively provide a fair financial return to the taxpayer. With
respect to the minimum acceptable bid, the intent of any potential
changes is to ensure that the American taxpayers receive a fair
financial return at BLM oil and gas lease sale auctions. With respect
to bonding requirements, the intent of any potential bonding updates
would be to ensure that bonds required for oil and gas activities on
public lands adequately capture costs associated with potential non-
compliance with any terms and conditions applicable to a Federal
onshore oil and gas lease. The BLM's existing regulations currently set
bond minimums that have not been adjusted in 50 years. With respect to
penalty assessments, the intent of the potential removal of the
regulatory caps would be to ensure that the penalties provide adequate
deterrence of unlawful conduct, particularly drilling on Federal
onshore leases without authorization and drilling into leased parcels
in knowing and willful trespass.
The anticipated updates to BLM's onshore oil and gas royalty rate
regulations and other potential changes to its standard lease fiscal
terms address recommendations from the Government Accountability Office
(GAO), and will help ensure that taxpayers are receiving a fair return
from the development of these resources. The anticipated changes to the
royalty rate regulations will also support implementation of reform
proposals in the Administration's Fiscal Year (FY) 2016 budget.
DATES: The BLM will accept comments and suggestions on this ANPR on or
before June 5, 2015.
ADDRESSES: You may submit comments by any of the following methods:
Mail: Director (630) Bureau of Land Management, U.S. Department of
the Interior, 1849 C St. NW., Room 2134LM, Washington, DC 20240,
Attention: 1004-AE41.
Personal or messenger delivery: U.S. Department of the Interior,
Bureau of Land Management, 20 M Street SE., Room 2134LM, Attention:
Regulatory Affairs, Washington, DC 20003.
Federal eRulemaking Portal: http://www.regulations.gov. Follow the
instructions at this Web site.
FOR FURTHER INFORMATION CONTACT: Dylan Fuge, Office of the Director, at
202-208-5235, Steven Wells, Division of Fluid Minerals, at 202-912-
7143, or Jully McQuilliams, Division of Fluid Minerals, at 202-912-
7156, for information regarding the substance of this ANPR. For
information on procedural matters or the rulemaking process generally,
you may contact Anna Atkinson, Regulatory Affairs, at 202-912-7438.
Persons who use a telecommunications device for the deaf (TDD) may call
the Federal Information Relay Service (FIRS) at 1-800-877-8339, 24
hours a day, 7 days a week to contact the above individuals.
SUPPLEMENTARY INFORMATION: The Department of the Interior (Department)
oversees and manages much of the nation's Federal mineral resources,
including onshore oil and natural gas
[[Page 22149]]
located on the 245 million surface acres and 700 million subsurface
acres managed by the BLM. It is responsible for ensuring that the
development of those resources occurs in an environmentally-responsible
manner, while also meeting the nation's energy needs. Key components of
the Department's management responsibility are ensuring that: (1) The
American public receives a fair return from the production of those
resources; (2) Issued leases are developed diligently and responsibly;
(3) There are adequate financial measures in place to address the risks
associated with development; and (4) Appropriate civil penalty
provisions are in place to address violations of applicable legal
requirements.
With respect to fair return, the BLM recognizes there is a need to
periodically assess the onshore oil and gas fiscal system and review
existing regulations and policies related to onshore royalty rates and
minimum acceptable bids. With respect to diligent development, the BLM
believes it may be appropriate to increase annual rental payments to
provide a greater incentive for lessees to develop leases promptly or
relinquish them so that they may be re-leased to other parties, as
appropriate. With respect to lessees' financial assurance obligations,
there may be a need to update existing bonding requirements to ensure
that the bonds provide adequate resources to reclaim and restore lands
and surface resources affected by leasing activities and development.
With respect to civil penalty assessments, there may be a need to
ensure that civil penalties adequately deter the unauthorized removal
of or trespass on leased Federal oil and gas resources, which
unlawfully deprive both the taxpayers and the lessees of the leased
resources or their value.
The purpose of this ANPR is to solicit public comments and
suggestions that would be helpful to the BLM in preparing a subsequent
proposed rule, as well as to gather input that is needed to update
onshore royalty rates, annual rental payments, the minimum acceptable
bid, bonding requirements, and caps on civil penalty assessments. The
scope of the anticipated proposed rule is likely to include a
combination of existing BLM onshore oil and gas regulations and
policies, including onshore royalty rates, oil and gas lease rental
payments, minimum acceptable bids, and bonding requirements, and civil
penalty assessments. See section III of this ANPR for a list of
specific questions relating to these topics.
I. Public Comment Procedures
Commenting on the ANPR
You may submit comments on the ANPR by mail, personal or messenger
delivery, or electronic mail.
Mail: Director (630) Bureau of Land Management, U.S. Department of
the Interior, 1849 C St. NW., Room 2134LM, Washington, DC 20240,
Attention: Regulatory Affairs, 1004-AE41.
Personal or messenger delivery: U.S. Department of the Interior,
Bureau of Land Management, 20 M Street SE., Room 2134LM, Attention:
Regulatory Affairs, Washington, DC 20003.
Electronic mail: You may access and comment on the ANPR at the
Federal eRulemaking Portal by following the instructions at that site
(see ADDRESSES).
Written comments and suggestions should:
--Be specific;
--Explain the reasoning behind your comments and suggestions; and
--Address the issues outlined in the ANPR.
For comments and suggestions to be the most useful, and most likely
to inform decisions on the content of any proposed rule, they should:
--Be substantive; and
--Facilitate the development and implementation of an environmentally
and fiscally responsible process for leasing public lands for oil and
gas production.
The BLM is particularly interested in receiving comments and
suggestions in response to the questions listed in section III of this
ANPR. These specific questions will focus the feedback on matters most
in need of public input for the development of the regulations. This
public input will assist the BLM in considering and proposing
appropriate adjustments to onshore lease royalty rates, annual rental
payments, minimum acceptable bids, bonding requirements, and civil
penalty or other assessments. All communications on these topics should
refer to RIN 1004-AE41 and may be submitted by the methods listed under
the ADDRESSES section of this ANPR.
Comments received after the close of the comment period (see DATES
section of this ANPR) may not necessarily be considered or included in
the Administrative Record for the proposed rule. Likewise, comments
delivered to an address other than those listed under the ADDRESSES
section of this ANPR may not necessarily be considered or included in
the Administrative Record for the proposed rule.
Reviewing Comments Submitted by Others
Comments, including names and street addresses of respondents, will
be available for public review at the personal or messenger delivery
address listed under ADDRESSES during regular business hours (7:45 a.m.
to 4:15 p.m.), Monday through Friday, except Federal holidays. They
will also be available at the Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions at this Web site for
submitting, accessing, and/or reviewing comments.
Before including your address, telephone number, email address, or
other personal identifying information in your comment, you should be
aware that your entire comment--including your personal identifying
information--may be made publicly available at any time. While you can
ask us in your comment to withhold your personal identifying
information from public review, we cannot guarantee that we will be
able to do so.
II. Background
Onshore Royalty Rates
The Mineral Leasing Act of 1920, as amended (30 U.S.C. 181 et seq.)
(MLA), the Mineral Leasing Act for Acquired Lands of 1947, as amended
(30 U.S.C. 351 et seq.) (MLAAL), and other statutes pertaining to
specific categories of land authorize the Secretary to lease Federal
oil and gas resources. The MLA and MLAAL prescribe the minimum
percentage of royalty reserved to the United States under an onshore
oil and gas lease on most Federal lands, as discussed further below.
The BLM is responsible for regulating onshore leasing activities for
BLM-managed lands and subsurface estate.
These authorities are implemented by the BLM through regulations at
43 CFR 3100. The BLM utilizes both competitive and non-competitive
leasing processes. Pursuant to the Federal Onshore Oil and Gas Leasing
Reform Act of 1987 (FOOGLRA), which amended the MLA, the BLM must first
offer parcels on a competitive basis.\1\ Leases are issued to the
highest qualified bidder as determined by an auction process.\2\
Parcels that do not
[[Page 22150]]
receive bids at auction must be made available for leasing on a non-
competitive basis to the first qualified applicant for a period of two
years after the lease sale at which those parcels were initially
offered. These non-competitive leases can be obtained, as explained
below, after payment of the first year's rent and an administrative fee
(30 U.S.C. 226(b)(1)(A); 43 CFR 3120.6). In aggregate, approximately 40
percent of the BLM-issued leases that are currently in force have been
issued non-competitively (GAO-14-50 at 8). In FY 2014, approximately 10
percent of leases were issued non-competitively.
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\1\ The MLA, as amended by the FOOGLRA, directs the BLM to hold
lease sales in each State where eligible lands are available for
leasing at least quarterly. 30 U.S.C. 226(b)(1)(A).
\2\ Under the MLA, lease sale auctions were, until recently,
required to be conducted by oral bidding. Id. In 2014, the National
Defense Authorization Act for Fiscal Year 2015 gave the BLM the
authority for the first time to hold Internet auctions. Public Law
113-291, Sec. 3022. The BLM has not yet implemented that authority.
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For all competitively-issued leases, the MLA requires a royalty
``at a rate of not less than 12.5 percent in amount or value of the
production removed or sold from the lease'' (emphasis added) (30 U.S.C.
226(b)(1)(A); 30 U.S.C. 352 (applying that requirement to leases on
acquired land)). Although the BLM is authorized under the MLA to
specify a royalty rate higher than 12.5 percent for competitive leases,
its existing regulations set a flat rate of 12.5 percent for such
leases (43 CFR 3103.3-1(a)(1)).\3\ For non-competitive leases, the
royalty rate is fixed at a flat 12.5 percent of the value of the
production by statute (30 U.S.C. 226(c) and 30 U.S.C. 352 (acquired
lands)).
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\3\ Before the FOOGLRA, the BLM issued leases with royalty rates
at or above 12.5 percent. Leases reinstated after termination due to
failure to pay annual rental are subject to a higher royalty rate
(43 CFR 3103.3-1(a)(2) and (3)).
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With this ANPR, the BLM seeks comments and suggestions on potential
revisions to the royalty rate system that are consistent with the
applicable statutory authorities (e.g., the statutory floor of 12.5
percent). Consistent with existing requirements, any potential
revisions to royalty rates, like those discussed below, would apply
only to new leases obtained competitively; non-competitive leases would
remain at the statutorily mandated 12.5 percent. Also, any potential
revisions would not apply to leases issued under the Indian Mineral
Leasing Act (tribal leases), 25 U.S.C. 396 (allotted leases), or the
Indian Mineral Development Act. It should also be noted that any
revisions to royalty rates would apply only to leases issued after the
effective date of any final rule.
Revenue generated from developing public energy resources that
belong to all Americans helps fund critical investments in communities
across the United States and creates American jobs, fosters land and
water conservation efforts, improves critical infrastructure, and
supports education. For FY 2014, onshore Federal oil and gas leases
produced about 148 million barrels of oil, 2.48 trillion cubic feet of
natural gas, and 2.9 billion gallons of natural gas liquids, with a
market value of almost $27 billion and generating royalties of almost
$3.1 billion. Nearly half of these revenues are distributed to the
States in which the leases are located.
The adequacy of the Department's oil and gas fiscal system has been
the subject of many studies by GAO, the Interior Department's Office of
the Inspector General (OIG), and other entities. The total government
revenues as a share of total lease revenues is the revenue generated
from taxes, fees, rental payments, bonus payments, and royalties. This
revenue in aggregate is commonly referred to as the ``government
take.'' GAO uses government take figures to compare various oil and gas
fiscal systems, such as those used on State-managed lands and in
certain foreign countries. The BLM's goal is to design an oil and gas
fiscal system that both ensures that the United States' oil and gas
resources are developed and managed in an environmentally-responsible
way that meets our energy needs, while also ensuring that the American
people receive a fair return on those resources (GAO-14-50 at 7).
In 2007 and 2008, the GAO released two reports focused on the
adequacy of the United States' oil and gas fiscal system. The first
report,\4\ which compared oil and gas revenues received by the United
States Government with the revenues that foreign governments receive
from the development of public oil and gas resources in those
countries, concluded that the United States Government receives one of
the lowest percentages in government revenue from public oil and gas
resource development in the world (GAO-07-676R at 2). The second
report,\5\ which focused on whether the Department received a fair
return on the resources it managed, cited the ``lack of price
flexibility in royalty rates'' and ``the inability to change fiscal
terms on existing leases,'' in support of GAO's finding that the United
States could be foregoing significant revenue from the production of
Federal oil and gas resources (GAO-08-691 at 6). The report also
faulted the Department for not having procedures in place to routinely
evaluate the ranking of the Federal oil and gas fiscal system, or the
industry rates of return on Federal leases versus other resource owners
(GAO-08-691 at 6). As a result, GAO recommended that the U.S. Congress
direct the Secretary to convene an independent panel to conduct a
review of the Federal oil and gas fiscal system and establish
procedures to periodically evaluate the system going forward. The U.S.
Congress did not take any action on the GAO's recommendation; however,
as explained below, the Department, including the BLM, undertook its
own review in response to the GAO's findings.
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\4\ Government Accountability Office (May 2007). Oil and Gas
Royalties: A Comparison of the Share of Revenue Received from Oil
and Gas Production by the Federal Government and Other Resource
Owners (GAO-07-676R).
\5\ Government Accountability Office (September 2008). Oil and
Gas Royalties: The Federal System for Collecting Oil and Gas
Revenues Needs Comprehensive Reassessment, September 2008 (GAO-08-
691).
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In an effort to respond to the GAO's findings, the BLM, in
coordination with the Bureau of Ocean Energy Management (BOEM),
contracted for a comparative assessment of oil and gas fiscal systems
on selected Department-managed Federal lands, State-managed lands, and
in certain foreign countries (IHS CERA Study).\6\ The Study identified
four factors that are amenable to relative comparisons: government
take, internal rate of return, profit-investment ratio, and
progressivity. The Study also considered measures of revenue risk and
fiscal system stability. In net, the IHS CERA Study found that as of
the time of its report, the Federal Government's fiscal system and
overall government take in aggregate were generally in the mainstream
nationally and internationally. However, the report estimated a
relatively wide range of government take, even within specific
geographic regions, and the Study's authors acknowledged that
government take varies with commodity prices, reserve size, reservoir
characteristics, resource location and development costs, distance from
infrastructure, water depth, and other factors. As a result, the IHS
CERA Study's authors tended to favor a sliding-scale royalty system
over a fixed-rate royalty due to its relative progressivity and ability
to respond to changes in commodity market conditions.
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\6\ IHS CERA (October 2011). Comparative Assessment of the
Federal Oil and Gas Fiscal System. Available at http://www.blm.gov/wo/st/en/prog/energy/comparative_assessment.html.
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In addition to the IHS CERA Study, the BLM also reviewed a separate
study that was conducted by industry, independent of the BLM's efforts
(Van Meurs Study (2011)).\7\ The Van Meurs
[[Page 22151]]
Study looked at a wide range of jurisdictions and regions across North
America and provided a comparison of the oil and gas fiscal systems on
Federal, State, and private lands throughout the United States and the
provinces in Canada. At the time it was published, the Van Meurs Study
suggested that in the United States: (1) Government take was generally
lower on Federal lands than the lessor's ``take'' on State lands or
private lands; (2) Government take was higher for gas than for oil; and
(3) The internal rate of return on leases was lower for gas than for
oil. The Report also made several recommendations to State and Federal
Governments in the United States and Canada, such as the application of
different fiscal terms to oil leases relative to gas leases based on
the prevailing prices of oil and gas at the time the report was
published. The continued growth of natural gas production in the United
States since the report was published raises questions about its
conclusions related to the intersection of specific prices and
individual government fiscal terms.
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\7\ PFC Energy, Van Meurs Corporation, and Rodgers Oil & Gas
Consulting (2011). World Rating of Oil and Gas Terms: Volume 1--
Rating of North American Terms for Oil and Gas Wells with a Special
Report on Shale Plays.
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As reflected by the findings in the reports discussed above, there
are challenges and uncertainties involved in comparing the relative
government take across regions or among nations. As a result, the BLM
is seeking through this ANPR additional points of comparison for
evaluating whether or not the BLM could achieve a better return through
changes to its royalty rate regulations. One such point of comparison
would be an evaluation of royalty rates charged by States on oil and
gas activities on State lands. This comparison is important because
while the Federal Government is a large player, it is only one of many
mineral rights owners in the United States. As a result, the royalty
rates charged by other significant mineral rights owners in the United
States are relevant to any assessment of the adequacy of the Federal
system.
For purposes of discussion and comparison, the Table below presents
information about royalty rates charged by the States for production on
State lands. The States listed below were selected because they have
significant oil and gas production or there is significant production
from Federal onshore oil and gas resources there. The information in
the Table is current as of December 2014. It should be noted that these
States receive all of the royalty from production on State lands. On
Federal lands, under the MLA, before the marginal ``net receipts
sharing'' deduction of 2 percent before distribution, the States
receive 50 percent of the royalty from production under most Federal
leases located within that State by way of permanent indefinite
appropriation (except Alaska where the State's share is 90 percent)
(see 30 U.S.C. 191(a)).\8\ As the table below shows, the royalty rates
on production from leases on private or State lands vary, but are
generally believed to be between 12.5 percent and 25 percent.
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\8\ After ``net receipts sharing'' deductions, the percentage of
MLA lease revenues distributed to the states is 88.2 percent in
Alaska and 49 percent in all other states. Remaining receipts are
deposited in the Reclamation Fund and miscellaneous receipts in the
U.S. Treasury.
\9\ Texas General Land Office, Oil and Gas Lease Bid Application
(Jan. 20, 2015), available at http://www.glo.texas.gov/what-we-do/energy-and-minerals/_documents/sealed-bids/bid01-20-15/web-notice-01-15.pdf.
\10\ University Lands, The University of Texas System, Standard
Oil and Gas Lease Agreement Form, available at http://www.utlands.utsystem.edu/forms/pdfs/LeaseAgreement45.pdf?201410.
Summary of State & Private Land Royalty Rates
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Jurisdiction Royalty rate Comment
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California (State lands).............. Negotiated on a lease-by-lease The California State Lands Commission
basis, but generally not less does not auction parcels. It negotiates
than 16.67 percent. lease terms, but it generally cannot
issue a lease with a royalty rate below
16.67 percent, by statute. Lease terms
are often based on neighboring leases.
Colorado (State lands)................ 16.67 percent................. Information from the Colorado State Land
Board Frequently Asked Questions.
Montana (State lands)................. 16.67 percent................. Montana statutes (Mont. Code Ann. Sec.
77-3-432) establishes a royalty of no
less than 12.5 percent. Montana's rule
(Sec. 36.25.210) sets the royalty rate
at 16.67 percent, unless the lease sale
notice announces a higher rate; the
most recent sale, in December 2014, did
not specify a higher rate.
New Mexico (State lands).............. 18.75 percent for development Information from the December 2014 lease
leases; 16.67 percent for sale notice.
discovery leases.
North Dakota (State lands)............ 18.75 percent or 16.67 percent Leases in Billings, Divide, Dunn, Golden
depending on the county. Valley, McKenzie, Mountrail, and
Williams counties carry an 18.75
percent royalty rate. Leases in other
counties carry a 16.67 percent royalty
rate. The statutory minimum royalty
rate for oil is 12.5 percent. N.D.
Cent. Code 15-05-10. Current Board of
University and School Lands rules (Sec.
85-06-06-05), as amended in 2012, set
the higher rates noted above.
Texas (State lands)................... 20 to 25 percent depending on By statute (Tex. Nat. Res. Code Ann.
the type of State land being Sec. 52.022), the School Land Board
leased. must set a royalty rate of at least
12.5 percent. The effective royalty
rates are specified in the notice for
bids. The royalty applies to all
subsequent wells drilled on a lease, so
long as the first well met the time
specifications. The specific rate
applied to new leases currently varies
between 20 to 25 percent depending on
the type of State land the lease is
located on, with most categories
subject to a 25 percent royalty
rate.\9\ New leases on University Lands
are currently subject to 25 percent
royalty rate.\10\
Utah (State lands).................... 12.5 percent or 16.67 percent. By regulation (Utah Admin. Code. R. 652-
20-1000), oil and gas leases must have
a royalty rate of at least 12.5
percent. The 16.67 percent royalty rate
is specified in the October 2014 lease
sale notice.
[[Page 22152]]
Wyoming (State lands)................. 16.67 percent; 12.5 percent if Information from the November 2014 lease
the parcel was offered in a sale notice. By statute (Wyo. Stat.
previous lease sale but did Ann. Sec. 36-6-101(c)), royalty rate
not receive a bid. must not be less than 5 percent of oil
and gas produced and saved.
Private Lands......................... Generally 12.5 percent to 25 Varies by contract.
percent.
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In 2013, the GAO issued another report identifying specific actions
for the Department to take to ensure that the Federal Government is
receiving a fair return on the resources it manages for the American
public.\11\ The GAO acknowledged that actions had been taken in
response to its prior recommendations (GAO-14-50 at 11), but remained
concerned that the Department has not taken steps to change the onshore
royalty rate regulations and had not established procedures for the
periodic assessment of the Federal oil and gas fiscal system (GAO-14-50
at 23).
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\11\ Government Accountability Office (December 2013). Oil and
Gas Resources: Actions Needed for the Interior to Better Ensure a
Fair Return (GAO-14-50).
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This ANPR directly addresses the GAO's first concern, because
through it the BLM is seeking additional information to help it resolve
some of the potentially contradictory inferences that can be drawn from
the reports described above as it considers potential changes to its
onshore royalty rate regulations. The BLM would be particularly
interested in information that would help it assess the adequacy of
existing rates. With respect to the periodic assessment of the onshore
oil and gas fiscal system, the BLM has completed a formal assessment
(see IHS CERA Study above) and the Department has taken steps to track
market conditions. However, it should be noted that because existing
regulations set a fixed royalty rate for new competitive leases,
periodic assessments of the fiscal system are of limited utility unless
those rules are amended. Because the BLM is considering potential
changes that would provide flexibility in setting royalty rates, it
poses some questions below on the scope, proper methodologies, and
recommended frequency of fiscal system assessments.\12\
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\12\ The BLM notes that rulemaking would not be required to
establish procedures for the periodic assessment of the onshore oil
and gas fiscal system.
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In addition to the statutory requirements, there are several
general economic factors that should be considered in assessing
potential changes to the current royalty rate. First, it should be
noted that there would be positive revenue benefits to the Federal
Government from adopting reasonable royalty rate increases.\13\ In the
near term, these benefits may be partially offset by a reduction in the
demand for new Federal competitive oil and gas leases. Such demand may
decrease to varying degrees depending on the magnitude of an increase
in royalty rate and the extent to which operators absorb the added
costs. Thus, the BLM is interested in receiving information about how
the magnitude of a particular royalty rate change might impact the
relative attractiveness of Federal leases compared to State and private
leases.
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\13\ See Draft Reports prepared by Enegis, LLC, for the BLM
(Contract No. L10PD03433)--Benefit-Cost and Economic Impact Analysis
of Raising the Onshore Royalty Rate Associated with New Federal Oil
Leasing (April and July 2011 versions).
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The BLM acknowledges that current oil and gas prices are low,
relative to the average price over the past decade; however,
recognizing the historic variability of those prices, the BLM would be
interested in information on the impacts of any royalty rate change at
a range of oil and gas prices. Additionally, the BLM would be
interested in information about the interplay between commodity prices
and a royalty rate's impact on the relative attractiveness of Federal
oil and gas leases.
It may be argued that potential production decreases resulting from
higher royalty rates could result in environmental benefits on Federal
lands, such as a reduction in the number of surface acres disturbed by
drilling and its associated infrastructure. The BLM would be interested
in receiving information related to these potential environmental
benefits, particularly studies where those benefits are quantified--
e.g., to what extent might such benefits be realized? Or, would they be
largely offset by drilling and production shifting to State or private
lands?
The BLM is also seeking input on how changes to the royalty rate
might affect the strategies employed by potential lessees for obtaining
Federal onshore oil and gas leases. As explained above, a company can
either obtain a parcel during a lease sale (resulting in a competitive
lease) or purchase those parcels that were not leased at the sale
after-the-fact on a first-come, first-serve basis (resulting in a non-
competitive lease). Under the first scenario, the operator has to pay a
bonus bid and would be subject to any changes to the royalty rate set
under amended regulations. For the non-competitive leases, there would
be no bonus bid and the royalty rate on the lease is set by statute at
a fixed 12.5 percent.\14\ Thus, there is a possibility that prospective
lessees may adjust their behavior in response to royalty rate changes,
either by bidding less for competitive leases or by trying to obtain
more leases non-competitively. The BLM is interested in information
about the extent to which such a shift might occur and, if so, how to
mitigate the effects of any shift in bidding behavior. However, the
current belief is that the most attractive parcels (i.e., those where
discovery and development prospects are strongest) will continue to be
sold at auction, as there is an inherent risk to the potential lessee
of lost opportunity in wagering that there will be no bids on such
parcels. For more marginal parcels, prospective lessees may be more
likely to take the risk that they can obtain them non-competitively
after an auction; however, as a general matter, marginal parcels are
also less likely to be developed.
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\14\ Parties acquiring a lease non-competitively must also pay
an application fee that is indexed for inflation. The fee amount for
FY 2015 is $405.
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What the foregoing illustrates from the BLM's perspective is that
selecting a royalty rate involves a series of trade-offs that have both
positive and negative consequences. The goal is to find the right
balance between higher revenue collections, oil and gas production, and
the relative attractiveness of leasing on Federal lands. According to
the GAO, in the royalty rate context, that means finding a government
take that ``would strike a balance between encouraging private
companies to invest in the development of oil and gas resources on
federal lands . . . while maintaining the public's interest in
collecting the appropriate level of revenues from the sale of the
public's resources'' (GAO-08-691 at 2).
[[Page 22153]]
It should also be remembered that oil and gas companies consider a
range of factors in deciding where to invest. In addition to government
take, they look at the size and availability of the oil and gas
resources and the costs associated with extracting those resources
(e.g., technological and labor costs) in a given area. They also look
at compliance costs, commodity prices, and infrastructure limitations.
For example, a company may decide to invest in the United States given
its stability, proven resources, and market access, even if government
take and certain other costs were higher relative to another country.
Oil and Gas Lease Annual Rental Payments
Under the MLA, as amended by FOOGLRA in 1987, prior to the
commencement of production of oil or gas in paying quantities, lessees
are required to pay annual rent of ``not less than $1.50 per acre per
year for the first through fifth years of the lease and not less than
$2 per acre per year for each year thereafter'' (30 U.S.C. 226(d)).
Following the commencement of production, this rental requirement
converts to a minimum royalty in lieu of rental. The minimum royalty is
``not less than the rental which otherwise would be required for that
lease year . . .'' when production began in paying quantities (Id.; 43
CFR 3103.2-2(c)) (explaining that rental payments are not due on leases
for which royalty or minimum royalty is being paid). The BLM's
regulations implementing this requirement fix the rental rates for
leases issued after December 22, 1987, at ``$1.50 per acre or fraction
thereof for the first 5 years of the lease term and $2 per acre or
fraction thereof for any subsequent year'' (43 CFR 3103.2-2(a)).
The BLM has not increased the rental rates since they were
initially set in 1987, even though the MLA only sets a floor for the
rates that must be charged by the BLM. The BLM anticipates updating its
rental rate requirements and seeks comments on appropriate changes as
discussed further below. The BLM would be particularly interested in
information about the rental rates charged by States and private
landowners for acreage leased, but not yet producing.
Minimum Acceptable Bid
In addition to requiring onshore oil and gas leases to first be
offered competitively, the MLA, as amended by FOOGLRA, also requires
the Secretary to 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'' (30 U.S.C. 226(b)(1)(A)) (emphasis added). The MLA sets the
minimum bid at $2 per acre for a period of two years from December 22,
1987 (30 U.S.C. 226(b)(1)(B)). Notably, the MLA specifically
contemplates that the Secretary may, at the conclusion of the two-year
period established by the statute, ``establish by regulation a higher
national minimum acceptable bid for all leases based upon a finding
that such action is necessary: (i) To enhance financial returns to the
United States; and (ii) to promote more efficient management of oil and
gas resources on Federal lands'' Id.\15\ The Secretary (through the
BLM) has not exercised this authority.\16\
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\15\ The MLA also requires that ``[n]inety days before the
Secretary makes any change in the national minimum acceptable bid,
the Secretary shall notify the Committee on Natural Resources of the
United States House of Representatives and the Committee on Energy
and Natural Resources of the United States Senate.'' 30 U.S.C.
226(b)(1)(B).
\16\ If the BLM were to increase the minimum acceptable bid, it
would also have to amend the regulations at 43 CFR 3120.5-2, which
currently require the winning bidder to pay at the day of sale the
minimum acceptable bid of $2 per acre, in addition to the first
year's rent, and a processing fee.
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The minimum acceptable bid is important because it establishes the
starting bid at the BLM's oil and gas lease sale auctions. Ideally, the
starting bid at any auction should be set at a level to ensure a fair
financial return for U.S. taxpayers on parcels acquired by third
parties competitively. The BLM's experience indicates that most parcels
sell for well in excess of the current minimum acceptable bid, which
may suggest the current minimum acceptable bid could be higher.
Therefore, the BLM is considering amending its regulations to increase
the minimum acceptable bid and seeks comments on appropriate changes as
discussed further below. The BLM would be particularly interested in
information about any minimum bid requirements imposed by States that
offer oil and gas leases competitively.
Additionally, the BLM would also be interested in information about
the potential impacts of any increase in the minimum acceptable bid
amount. As explained above, the minimum acceptable bid sets the floor
at which BLM will accept a bid for a parcel offered at a lease sale
auction. If the BLM does not receive bids that are equal to or greater
than the minimum bid for a parcel, then it does not lease the parcel at
the competitive sale. Parcels that are not leased competitively are
available, per the MLA, for lease non-competitively for a period of two
years following the auction. Entities leasing such parcels non-
competitively are required to pay an administrative fee and the first
year's rent, but a minimum acceptable bid or other bonus bid is not
required. As a result, the BLM has an interest in ensuring that the
minimum acceptable bid is not set so high as to encourage parcels to be
leased non-competitively. The BLM would be interested in receiving
information about whether or how to adjust the minimum acceptable bid
and whether the BLM should consider establishing a different annual
rental rate for non-competitively leased parcels to compensate for not
receiving a minimum bid when the BLM issues leases non-competitively.
Oil and Gas Lease Bonding
The MLA authorizes the Secretary to establish standards ``. . . as
may be necessary to ensure that an adequate bond, surety, or other
financial arrangement will be established prior to the commencement of
surface-disturbing activities on any lease, to ensure the complete and
timely reclamation of the lease tract, 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'' (30
U.S.C. 226(g)). Consistent with this statutory direction, the existing
regulations at 43 CFR 3104.1 require that, prior to surface disturbing
activities related to drilling operations, the lessee, sublessee, or
operator submit a surety or personal bond.
The purpose of the bond is to ensure the ``complete and timely
plugging of the well(s), 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'' (43 CFR 3104.1(a)). The regulations at 43 CFR 3104.2-
3104.4 set forth four different bond types:
(1) Lease/Individual Bonds, which by regulation only provide
coverage for one lease and must be in an amount of not less than
$10,000;
(2) Statewide Bonds, which cover all leases and operations in one
State and must be in an amount of not less than $25,000;
(3) Nationwide Bonds, which cover all leases and operations
nationwide and by regulation must be in an amount of not less than
$150,000; and
(4) Unit Operator's Bonds, which may be used in lieu of individual
lease, statewide, or nationwide bonds for operations conducted on
leases committed to an approved unit agreement. Existing regulations do
not
[[Page 22154]]
set a minimum amount for these types of bonds, but rather specify that
the amount will be set by the Authorized Officer. The BLM has not
increased the minimum bond amounts provided in the existing regulations
since 1960. As a result, those minimums do not reflect inflation and
likely do not cover the costs associated with the reclamation and
restoration of any individual oil and gas operation. The BLM
anticipates updating its bonding requirements and seeks comments on
appropriate changes as discussed further below.
Civil Penalty Assessment
In a recent report (No. CR-IS-BLM-0004-2014), the Department's OIG
expressed concern about the BLM's existing policies and procedures to
detect trespass in or drilling without approval on Federal onshore oil
and gas leases. Among other things, the OIG expressed concern about the
adequacy of the BLM's policies to deter such activities and recommended
that the BLM pursue increased monetary fines. In response to these
concerns and as explained below, the BLM is seeking input on removing
or modifying the caps on civil penalty assessments currently imposed by
its existing regulations.
The civil penalty provisions in section 109 of FOGRMA (30 U.S.C.
1719), provide authority for the BLM to assess civil penalties in
connection with certain activities on Federal onshore oil and gas
leasing and operations. Section 109(a) and (b) (30 U.S.C. 1719(a) and
(b)) provide for assessment of civil penalties of up to $500 per
violation per day for failure to comply with FOGRMA, any mineral
leasing law, any rule or regulation thereunder, or the terms of any
lease. Such penalties accrue only after the issuance of a notice of the
violation and failure by the party receiving the notice to correct the
violation within 20 days after issuance of the notice. Penalties run
from the date of the notice. If corrective action is not taken within
40 days, the maximum daily penalty increases to up to $5,000 per
violation per day, dating from the date of the notice. Existing
regulations at 43 CFR 3163.2(b) impose a cap on the total civil penalty
that can be assessed under sections 109(a) and (b) at a maximum of 60
days, which results in a maximum possible civil penalty assessment of
$300,000.
Section 109(c)(2) of FOGRMA (30 U.S.C. 1719(c)(2)) provides for a
civil penalty of up to $10,000 per violation per day (without a
requirement for prior notice and opportunity to correct) for failure or
refusal to permit lawful entry or inspection. Current BLM regulations
at 43 CFR 3163.2(e) cap the total assessment under section 109(c)(2) at
a maximum of 20 days, resulting in a maximum penalty of $200,000.
Finally, section 109(d)(1) and (2) of FOGRMA (30 U.S.C. 1719(d)(1)
and (2)), provide for a civil penalty of up to $25,000 per day (again
without a requirement for prior notice and opportunity to correct) for
knowingly or willfully preparing or submitting false, inaccurate, or
misleading reports or information (subsection (d)(1)) or for knowingly
or willfully taking, removing, or diverting oil or gas from any lease
site without valid legal authority (subsection (d)(2)). Current BLM
rules cap this penalty assessment at 20 days, or a maximum of $500,000
(43 CFR 3163.2(f)).
If a lessee or designated operator of a Federal onshore lease
drills a well without an approved application for permit to drill
(APD), the lessee or operator is liable for civil penalties under
section 109(a) and (b) after notice and failure to timely correct. In
such circumstances, the corrective action would be to obtain approval
of an APD. The maximum penalty under such circumstances is $300,000. A
person who knowingly or willfully drills a well into leased Federal
land when that person is not a lessee or operator of the Federal lease
is liable for civil penalties under section 109(d)(2), which are
subject to a maximum penalty of $500,000. The OIG has questioned
whether these penalty levels, which were established in the mid-1980s,
provide an adequate deterrence given the current costs for completing a
well in places like North Dakota, which the OIG reported as ranging
between $8 to $12 million dollars.\17\ The BLM anticipates updating its
civil penalty regulations and seeks comments on appropriate changes as
discussed further below.
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\17\ Trespass actions involving unleased parcels are subject to
the regulations at 43 CFR 9239.5-2, which provide as follows:
For oil trespass in a State where there is no State law
governing such trespass, the measure of damages will be as follows:
(a) Innocent trespass. Value of oil taken, less amount of
expense incurred in taking the same.
(b) Willful trespass. Value of the oil taken without credit or
deduction for the expense incurred by the wrongdoers in getting it.
Mason v. United States (273 Fed. 135).
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III. Description of Information Requested
Onshore Royalty Rates and Periodic Assessments of the Onshore Fiscal
System
The BLM is interested in receiving feedback on the following
questions related to potential revisions to the royalty rate
regulations governing competitively-issued onshore oil and gas leases:
1. The various reports and assessments of the Federal oil and gas
fiscal system that the BLM has received, prepared, or reviewed, create
potentially inconsistent inferences as to the adequacy existing royalty
rates. What information should the BLM consider that would help it
resolve those inconsistencies?
2. In evaluating whether or not existing royalty rates are
providing a fair return to the public for leased oil and gas resources,
what should the BLM consider, and on what factors should the BLM place
the most weight?
a. Given the uncertainties associated with comparing current
information on government take among countries and at different
commodity prices, should the BLM primarily rely on comparisons to State
and private land royalty rates?
b. To what extent should the BLM factor in the effects on
production in assessing the appropriateness of applying a given royalty
rate?
3. Should the BLM consider other factors in determining what
royalty level might provide a fair return, such as life cycle costs,
externalities, or the social costs associated with the extraction and
use of the oil and gas resources? If the BLM should consider such
factors, please explain how it should do so. The BLM currently offers
all new competitive Federal oil and gas leases at a fixed royalty rate
of 12.5 percent. Should the BLM:
a. Increase the royalty rate on oil and gas production above 12.5
percent to a different fixed royalty rate? If so, what should that rate
be? For example, should the rate be increased to 18.75 percent
consistent with the rate set for recent offshore lease sales? If not,
why not?
b. Consider a sliding-scale royalty-rate structure based on an
established index of oil and gas prices during a given period of time,
as suggested by GAO? If so, how many price tiers would be optimal to
balance administrative complexity with the opportunity to distinguish
between meaningful price swings? What price thresholds would be
appropriate for each tier? Should the thresholds be fixed (in real
dollar terms), or should they float relative to a published index?
4. Whether the BLM keeps royalty rates fixed or adopts a sliding-
scale rate structure, should it:
a. Maintain a national or uniform rate or rate schedule for all new
competitive leases?
[[Page 22155]]
b. Establish potentially different royalty rates or rate schedules
for new leases by region, State, lease sale, formation, resource type
(e.g., crude oil, crude oil from tight formations, natural gas, and
natural gas from shale formations) or other category? In each case, how
should the BLM determine what the royalty rates should be? For
instance, if by region, how would the various rates for different
regions be determined?
5. What other royalty rate structures (not listed previously)
should the BLM consider?
6. Instead of amending the regulations to set a new fixed rate or
impose an adjustable rate structure as part of a new formal regulation,
should the BLM revise its regulations so that the Secretary (through
the BLM) has the authority to set the royalty rate terms for new leases
outside of a formal rulemaking process?
a. One option would be to set the rate terms in individual Notice
of Lease Sale documents in a manner similar to the existing offshore
authorities, but this raises other potential complications (e.g., loss
of transparency, greater challenges in revenue tracking and estimation)
given the frequency and processes used for BLM lease sales compared to
offshore sales. If the terms are set on a lease sale-by-sale basis,
what market conditions or factors should be considered in setting the
royalty rates for a particular sale? What weight should be given to
individual factors?
b. Is there another approach that should be considered to strike a
balance between the competing objectives of flexibility, transparency,
and simplicity? Should the BLM (or the Secretary) maintain a set
national rate schedule that would be updated periodically on a fixed
schedule (e.g., annually) or as circumstances warrant (e.g., when
certain price triggers are hit)?
7. How should the BLM undertake assessments of the oil and gas
fiscal system?
a. What methodologies, information, and resources should it
consider as part of such assessments? In responding, please consider
whether any factor should be given more weight than another.
b. How often should such assessments occur? Every year? Every five
years? Every 10 years? As necessary based on some trigger? If you
recommend a trigger-based approach, please identify the trigger.
Annual Rental Payments
The BLM is interested in receiving feedback on the following
questions related to potential changes to its annual rental payment
requirements:
1. Should the BLM increase the annual rental payments set forth in
43 CFR subpart 3103? If so, by how much? If not, why are current
payment levels sufficient to ensure the diligent development of an oil
and gas lease?
2. If the BLM were to increase annual rental payments, what factors
should it consider in proposing an increase?
a. Should rental payments simply be adjusted to reflect inflation?
b. Are there other factors the BLM should consider?
3. If the BLM were to increase the annual rental payments:
a. How should the BLM implement those changes--e.g., should it
consider a phase-in?
b. Is there another way to have annual rentals escalate over time
besides the current category of years 1 through 5 and then a higher
rental for years 6-10?
4. Are there any other changes or refinements that the BLM should
consider to its current annual rental payment requirements?
5. What are the comparable State practices with respect to annual
rental payments?
Minimum Acceptable Bid
The BLM is interested in receiving feedback on the following
questions related to potential changes to its regulations to increase
the minimum acceptable bid required for oil and gas leases offered
competitively:
1. Should the BLM increase the current minimum acceptable bid of $2
per acre? If so, by how much?
2. If the BLM were to increase the minimum bid:
a. What factors should it consider in proposing an increase? For
any factors, please explain how they relate to: (1) Enhancing financial
returns to the United States; and (2) promoting more efficient
management of oil and gas resources on Federal lands.
b. What are the potential impacts of any such increase? Does it
vary by the magnitude of the increase?
c. Should the BLM amend its regulations to give the Authorized
Officer discretion to adjust the minimum bid based upon market
conditions?
d. Should the BLM raise the rental rates for leases acquired non-
competitively to compensate for not receiving even minimum bids for
such leases? If so, what would a reasonable rental rate be for non-
competitively issued leases?
3. What are the comparable State practices with respect to minimum
bids for leases acquired competitively?
Bonding
The BLM is interested in receiving feedback on the following
questions related to potential changes to its bonding requirements:
1. Should the BLM increase the minimum bond amounts set forth in 43
CFR subpart 3104? If so, by how much? If not, why are current bonding
levels sufficient?
2. If the BLM were to increase minimum bonds amounts, what factors
should it consider?
a. Should bond minimums simply be adjusted to reflect inflation?
b. Should they be adjusted to reflect an estimate of best case,
average, or worst case reclamation and restoration costs? In connection
with this question, the BLM would be interested in receiving estimates
of such reclamation and restoration costs.
c. Are there other factors the BLM should consider? Are there best
practices at the State level that the BLM should consider adopting?
3. If the BLM were to increase the minimum bond amounts:
a. Should it provide a way for those amounts to automatically rise,
such as if they were to track inflation?
b. How should it implement those changes--e.g., should it consider
a phase-in?
c. Existing authorities permit the BLM to adjust bond amounts up
and down, but no lower than the minimum amount. In light of those
authorities, if the BLM were to increase bond minimums, should it
consider provisions to allow a party to request, on a case-by-case
basis, a decrease in its bond amount to below the minimum if, for
example, the BLM were to determine that the potential liabilities on a
particular lease are less than the applicable minimum bond amounts?
Please identify any standards the BLM should use to determine whether
to approve such a request.
4. Are there any other activities for which the BLM should consider
requiring a bond?
a. In the past the BLM has considered adding a new bond for
inactive wells; should the BLM revisit such a proposal?
b. Similarly should the BLM consider adding a royalty bond to
address issues related to unpaid royalties? Adding a royalty bond would
mean that funds available under the other, general bonds would not need
to be used for anything other than reclamation. Currently, the bonds
can address reclamation and royalty issues, among other things.
c. For any new bond types that you think the BLM should consider,
please explain how the bond amounts should
[[Page 22156]]
be set and what the scope of coverage should be.
5. Are there any other changes or refinements that the BLM should
consider to its current oil and gas bonding, surety and financial
arrangement requirements?
Civil Penalty Assessments
The BLM is interested in receiving feedback on the following
questions related to changes to the current caps on civil penalty
assessments:
1. Should the current regulatory caps on the amount of civil
penalties that may be assessed be removed?
2. If regulatory caps on the maximum amount of civil penalty
assessments should remain, at what level should they be set to
adequately deter improper action--in particular, drilling without an
approved APD or drilling into Federal leases in knowing or willful
trespass?
Non-Penalty Assessments and Trespass
1. In addition to the caps on civil penalties set forth at 43 CFR
3163.2, should the BLM consider revising any of the assessments set
forth in 43 CFR 3163.1? If so, what changes should be made and on what
basis?
2. Should the BLM consider revising its oil trespass regulations
set forth at 43 CFR 9239.5-2? If so, what changes should be made and on
what basis?
In addition to the specific information requests identified above,
the BLM is also interested in receiving any other comments you may have
regarding royalty rates, annual rental payments, minimum acceptable
bids, bonding requirements, or the current regulatory caps on civil
penalty assessments for BLM-managed oil and gas leases.
Janice M. Schneider,
Assistant Secretary, Land and Minerals Management.
[FR Doc. 2015-09033 Filed 4-20-15; 8:45 am]
BILLING CODE 4310-84-P