22148 Federal Register / Vol. 80, No. 76 / Tuesday, April 21, 2015 / Proposed Rules 

SW., Atlanta, Georgia 30303–8960. The 

telephone number is (404) 562–9029. 

Ms. Spann can be reached via electronic 

mail at spann.jane@epa.gov. 

SUPPLEMENTARY INFORMATION: For 

additional information see the direct 

final rule which is published in the 

Rules Section of this Federal Register. 

A detailed rationale for the approval is 

set forth in the direct final rule. If no 

adverse comments are received in 

response to this rule, no further activity 

is contemplated. If EPA receives adverse 

comments, the direct final rule will be 

withdrawn and all public comments 

received will be addressed in a 

subsequent final rule based on this 

proposed rule. EPA will not institute a 

second comment period on this 

document. Any parties interested in 

commenting on this document should 

do so at this time. 

Dated: April 9, 2015. 

Heather McTeer Toney, 

Regional Administrator, Region 4. 

[FR Doc. 2015–09049 Filed 4–20–15; 8:45 am] 

BILLING CODE 6560–50–P 

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. 

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 


tkelley on DSK3SPTVN1PROD with PROPOSALS
Federal Register / Vol. 80, No. 76 / Tuesday, April 21, 2015 / Proposed Rules 22149 

1The 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). 

2Under 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 

Continued 

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 released 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS
22150 Federal Register / Vol. 80, No. 76 / Tuesday, April 21, 2015 / Proposed Rules 

113–291, Sec. 3022. The BLM has not yet 

implemented that authority. 

3Before 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)). 

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). 

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. 

7PFC Energy, Van Meurs Corporation, and 

Rodgers Oil & Gas Consulting (2011). World Rating 

of Oil and Gas Terms: Volume 1—Rating of North 

receive bids at auction must be made 

available for leasing on a noncompetitive basis to the first qualified 

applicant for a period of two years after 

the lease sale at which those parcels 

were initially offered. These noncompetitive 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. 

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)). 

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; noncompetitive 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. 

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 Departmentmanaged 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, profitinvestment 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. 

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 


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American Terms for Oil and Gas Wells with a 

Special Report on Shale Plays. 

8After ‘‘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. 9Texas General Land Office, Oil and Gas Lease 

Bid Application (Jan. 20, 2015), available at http:// 

www.glo.texas.gov/what-we-do/energy-andminerals/_documents/sealed-bids/bid01-20-15/webnotice-01-15.pdf. 

10University 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. 

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. 

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 thetable 

below shows, the royalty rates on 

production from leases on private or 

State landsvary, but are generally 

believed to be between 12.5 percent and 

25 percent. 

SUMMARY OF STATE & PRIVATE LAND ROYALTY RATES

Jurisdiction Royalty rate Comment 

California (State lands) ...... Negotiated on a lease-by-lease basis, but 

generally not less than 16.67 percent.

The California State Lands Commission does not auction parcels. It 

negotiates 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. § 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 leases; 16.67 

percent for discovery leases.

Information from the December 2014 lease sale notice. 

North Dakota (State lands) 18.75 percent or 16.67 percent depending 

on the county.

Leases in Billings, Divide, Dunn, Golden 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 (§ 85–06–06–05), as amended in 2012, set the higher rates noted above. 

Texas (State lands) ........... 20 to 25 percent depending on the type of 

State land being leased.

By statute (Tex. Nat. Res. Code Ann. § 52.022), the School Land 

Board 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. 


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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). 

12The BLM notes that rulemaking would not be 

required to establish procedures for the periodic 

assessment of the onshore oil and gas fiscal system. 

13See 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). 

14Parties acquiring a lease non-competitively 

must also pay an application fee that is indexed for 

inflation. The fee amount for FY 2015 is $405. 

SUMMARY OF STATE & PRIVATE LAND ROYALTY RATES—Continued 

Jurisdiction Royalty rate Comment 

Wyoming (State lands) ...... 16.67 percent; 12.5 percent if the parcel was 

offered in a previous lease sale but did not 

receive a bid.

Information from the November 2014 lease sale notice. By statute 

(Wyo. Stat. Ann. § 36–6–101(c)), royalty rate must not be less 

than 5 percent of oil and gas produced and saved. 

Private Lands ..................... Generally 12.5 percent to 25 percent ............ Varies by contract. 

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). 

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

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. 

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 noncompetitively. 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. 

What the foregoing illustrates from 

the BLM’s perspective is that selecting 

a royalty rate involves a series of tradeoffs 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). 


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15The 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. 

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

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 noncompetitively 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 noncompetitively. 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 noncompetitively 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 surfacedisturbing 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS
22154 Federal Register / Vol. 80, No. 76 / Tuesday, April 21, 2015 / Proposed Rules 

17Trespass 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). 

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. 

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? 


tkelley on DSK3SPTVN1PROD with PROPOSALS
Federal Register / Vol. 80, No. 76 / Tuesday, April 21, 2015 / Proposed Rules 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 noncompetitively 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS
22156 Federal Register / Vol. 80, No. 76 / Tuesday, April 21, 2015 / Proposed Rules 

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 

DEPARTMENT OF COMMERCE 

National Oceanic and Atmospheric 

Administration 

50 CFR Part 660 

[Docket No. 150305219–5219–01] 

RIN 0648–BE78 

Fisheries Off West Coast States; 

Highly Migratory Species Fisheries 

AGENCY: National Marine Fisheries 

Service (NMFS), National Oceanic and 

Atmospheric Administration (NOAA), 

Commerce. 

ACTION: Proposed rule; request for 

comments. 

SUMMARY: The National Marine 

Fisheries Service (NMFS) is proposing 

to modify the existing Pacific bluefin 

tuna (PBF) Thunnus orientalis 

recreational daily bag limit in the 

Exclusive Economic Zone (EEZ) off 

California, and to establish filleting-atsea requirements for any tuna species in 

the U.S. EEZ south of Point Conception, 

Santa Barbara County, under the 

Magnuson-Stevens Fishery 

Conservation and Management Act 

(MSA). This action is intended to 

conserve PBF, and is based on a 

recommendation of the Pacific Fishery 

Management Council (Council). 

DATES: Comments on the proposed rule 

must be submitted in writing by May 6, 

2015. 

ADDRESSES: You may submit comments 

on this document, identified by NOAA– 

NMFS–2015–0029, by any of the 

following methods: 

• Electronic Submission: Submit all 

electronic public comments via the 

Federal e-Rulemaking Portal. Go to 

http://www.regulations.gov/

#!docketDetail;D=NOAA-NMFS-2015- 

0029, click the ‘‘Comment Now!’’ icon, 

complete the required fields, and enter 

or attach your comments. 

• Mail: Submit written comments to 

Craig Heberer, NMFS West Coast Region 

Long Beach Office, 501 W. Ocean Blvd., 

Suite 4200, Long Beach, CA 90802. 

Include the identifier ‘‘NOAA–NMFS– 

2015–0029’’ in the comments. 

Instructions: Comments must be 

submitted by one of the above methods 

to ensure they are received, 

documented, and considered by NMFS. 

Comments sent by any other method, to 

any other address or individual, or 

received after the end of the comment 

period, may not be considered. All 

comments received are a part of the 

public record and will generally be 

posted for public viewing on 

www.regulations.gov without change. 

All personal identifying information 

(e.g., name, address, etc.) submitted 

voluntarily by the sender will be 

publicly accessible. Do not submit 

confidential business information, or 

otherwise sensitive or protected 

information. NMFS will accept 

anonymous comments (enter ‘‘N/A’’ in 

the required fields if you wish to remain 

anonymous). 

Copies of the draft Regulatory Impact 

Review (RIR) and other supporting 

documents are available via the Federal 

eRulemaking Portal: http://

www.regulations.gov, docket NOAA– 

NMFS–2015–0029, or contact the 

Regional Administrator, William W. 

Stelle, Jr., NMFS West Coast Regional 

Office, 7600 Sand Point Way, NE., Bldg 

1, Seattle, WA. 98115–0070, or 

RegionalAdministrator.WCRHMS@

noaa.gov. 

FOR FURTHER INFORMATION CONTACT: 

Craig Heberer, NMFS, 760–431–9440, 

ext. 303. 

SUPPLEMENTARY INFORMATION: On April 

7, 2004, NMFS published a final rule 

(69 FR 18444) to implement the Fishery 

Management Plan for U.S. West Coast 

Fisheries for Highly Migratory Species 

(HMS FMP) that included annual 

specification guidelines at 50 CFR 

660.709. These guidelines establish a 

process for the Council to take final 

action at its regularly-scheduled 

November meeting on any necessary 

harvest guideline, quota, or other 

management measure and recommend 

any such action to NMFS. At their 

November 2014, meeting, the Council 

adopted a recommendation (http://

www.pcouncil.org/wp-content/uploads/

1114decisions.pdf) to modify the 

existing daily bag limit regulations at 50 

CFR 660.721 for sport caught PBF 

harvested in the EEZ off the coast of 

California and to promulgate at-sea fillet 

regulations applicable south of Santa 

Barbara as routine management 

measures for the 2014–2015 biennial 

management cycle. The Council’s 

recommendation and NMFS’ proposed 

rulemaking are intended to reduce 

fishing mortality and aid in rebuilding 

the PBF stock, which is overfished and 

subject to overfishing (78 FR 41033, July 

9, 2013; 80 FR 12621, March 9, 2015) 

and to satisfy the United States’ 

obligation to reduce catches of PBF by 

sportfishing vessels in accordance with 

Inter-American Tropical Tuna 

Commission (IATTC) Resolution C–14– 

06. (http://www.iattc.org/PDFFiles2/

Resolutions/C-14-06-Conservation-ofbluefin-2015-2016.pdf). 

Resolution C–14–06 requires that ‘‘in 

2015, all IATTC Members and 

Cooperating non-Members (CPCs) must 

take meaningful measures to reduce 

catches of PBF by sportfishing vessels 

operating under their jurisdiction to 

levels comparable to the levels of 

reduction applied under this resolution 

to the EPO commercial fisheries until 

such time that the stock is rebuilt.’’ The 

proposed daily bag limit of two fish per 

day being considered under this 

proposed rule would reduce the U.S. 

recreational harvest of PBF by 

approximately 30 percent, which is 

consistent with the IATTC scientific 

staff’s conservation recommendation for 

a 20–45 percent PBF harvest reduction 

and meets the requirements of IATTC 

Resolution C–14–06. The filleting-at-sea 


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