Oil and Gas Leasing; Royalty on Production, Rental Payments, Minimum Acceptable Bids, Bonding Requirements, and Civil Penalty Assessments, 22148-22156 [2015-09033]

Agencies

• DEPARTMENT OF THE INTERIOR
• Bureau of Land Management

[Federal Register Volume 80, Number 76 (Tuesday, April 21, 2015)]
[Proposed Rules]
[Pages 22148-22156]
From the Federal Register Online via the Government Printing 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: https://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: https://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 https://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 https://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 https://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