Oil Shale Management-General, 42926-42975 [E8-16275]

Agencies

• DEPARTMENT OF THE INTERIOR
• Bureau of Land Management
• Land Management Bureau

[Federal Register Volume 73, Number 142 (Wednesday, July 23, 2008)]
[Proposed Rules]
[Pages 42926-42975]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E8-16275]



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Part II





Department of the Interior





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Bureau of Land Management



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43 CFR Parts 3900, 3910, 3920 et al.



Oil Shale Management--General; Proposed Rule

Federal Register / Vol. 73, No. 142 / Wednesday, July 23, 2008 / 
Proposed Rules

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DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Parts 3900, 3910, 3920, and 3930

[WO-320-1310-OSHL]
RIN 1004-AD90


Oil Shale Management--General

AGENCY: Bureau of Land Management, Interior.

ACTION: Proposed rule.

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SUMMARY: The Bureau of Land Management (BLM) is proposing regulations 
to set out the policies and procedures for the implementation of a 
commercial leasing program for the management of federally-owned oil 
shale and any associated minerals located on Federal lands. The Energy 
Policy Act of 2005 (EP Act) directs the Secretary of the Interior to: 
Make public lands available for conducting oil shale research and 
development activities; complete a Programmatic Environmental Impact 
Statement (PEIS) for a commercial leasing program for both oil shale 
and tar sands resources on the BLM administered lands in Colorado, 
Utah, and Wyoming; and issue regulations establishing a commercial oil 
shale leasing program.
    These proposed regulations would incorporate specific provisions of 
the Mineral Leasing Act of 1920 (MLA) and the EP Act relating to: 
Maximum oil shale lease size; maximum acreage limitations; rental; and 
lease diligence.
    These proposed regulations would also address the diligent 
development requirements of the EP Act by establishing work 
requirements and milestones to ensure diligent development of leases. 
The proposed rule would also provide for other standard components of a 
BLM mineral leasing program, including lease administration and 
operations.

DATES: Send your comments to reach the BLM on or before September 22, 
2008. The BLM will not necessarily consider any comments received after 
the above date during its decision on the proposed rule.

ADDRESSES: Mail: U.S. Department of the Interior, Director (630), 
Bureau of Land Management, Mail Stop 401 LS, 1849 C St., NW., 
Attention: 1004-AD90, Washington, DC 20240.
    Personal or messenger delivery: 1620 L Street, NW., Room 401, 
Washington, DC 20036.
    Federal eRulemaking Portal: https://www.regulations.gov. Follow the 
instructions at this Web site.
    You may also send comments on the information collection aspects of 
this proposed rule directly to: Interior Desk Officer (1004-AD90), 
Office of Information and Regulatory Affairs, Office of Management and 
Budget (OMB), (202) 395-6566 (facsimile); e-mail: oira_
docket@omb.eop.gov. Please also send a copy to the BLM.

FOR FURTHER INFORMATION CONTACT: Mitchell Leverette, Chief, Division of 
Solid Minerals at (202) 452-5088 for issues related to the BLM's 
commercial oil shale leasing program or Kelly Odom at (202) 452-5028 
for regulatory process issues. 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 
leave a message or question with the above individuals. You will 
receive a reply during normal business hours.

SUPPLEMENTARY INFORMATION:

I. Public Comment Procedures
II. Background
III. Discussion of the Proposed Rule
IV. Procedural Matters

I. Public Comment Procedures

A. How do I comment on the proposed rule?

    If you wish to comment, you may submit your comments by any one of 
several methods:
     You may mail comments to U.S. Department of the Interior, 
Director (630), Bureau of Land Management, Mail Stop 401 LS, 1849 C 
St., NW., Attention: 1004-AD90, Washington, DC 20240.
     You may deliver comments to Room 401, 1620 L Street, NW., 
Washington, DC 20036.
     You may access and comment on the proposed rules at the 
Federal eRulemaking Portal by following the instructions at that site 
(see ADDRESSES).

Please make your comments on the proposed rule as specific as possible, 
confine them to issues pertinent to the proposed rule, and explain the 
reason for any changes you recommend. Where possible, your comments 
should reference the specific section or paragraph of the proposal that 
you are addressing.
    The BLM may not necessarily consider or include in the 
Administrative Record for the final rule comments that we receive after 
the close of the comment period (see DATES ) or comments delivered to 
an address other than those listed above (see ADDRESSES).

B. May I review comments submitted by others?

    Comments, including names and street addresses of respondents, will 
be available for public review at the address listed under ADDRESSES: 
Personal or messenger delivery during regular hours (7:45 a.m. to 4:15 
p.m.), Monday through Friday, except holidays. The comments are also 
available for public review on https://www.regulations.gov.
    Before including your address, telephone number, e-mail address, or 
other personal identifying information in your comment, be advised 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 from public review your personal identifying 
information, we cannot guarantee that we will be able to do so.

II. Background

    The BLM is proposing these regulations to implement the EP Act (42 
U.S.C. 15927), which became law on August 8, 2005. Section 369 of the 
EP Act addresses oil shale development and authorizes the Secretary of 
the Interior to establish regulations for a commercial leasing program. 
The MLA of 1920 (30 U.S.C. 241(a)) provides the authority for the BLM 
to allow for the exploration, development, and utilization of oil shale 
resources on the BLM-managed public lands. Additional statutory 
authorities for these proposed regulations are:
    (1) The Mineral Leasing Act for Acquired Lands of 1947 (30 U.S.C. 
351-359); and
    (2) The Federal Land Policy and Management Act (FLPMA) of 1976 (43 
U.S.C. 1701 et seq., including 43 U.S.C. 1732).
    Oil shale is a fine-grained sedimentary rock containing organic 
matter from which shale oil may be produced. Oil shale is a marlstone 
and contains no oil; rather, it contains un-decayed algae called 
kerogen (not oil). In fact, the word kerogen is a Greek word 
interpreted to mean ``to produce wax''--``kero'' (wax), ``gen'' to 
produce. The waxy substance produced from oil shale rock is not the 
same as conventional crude oil. The kerogen only has a market value as 
an energy source after it has been refined and converted to synthetic 
crude oil.
    Oil shale is a solid rock and must be mined or treated in place to 
release the kerogen oil from the rock. Energy companies and petroleum 
researchers have, over the past 60 years, developed

[[Page 42927]]

and tested a variety of technologies on a small scale for recovering 
shale oil from oil shale and processing it to produce fuels and 
byproducts. Both surface processing and in-situ technologies have been 
examined. Generally, surface processing consists of three major steps: 
(1) Oil shale mining and ore preparation; (2) pyrolysis of oil shale to 
produce kerogen oil; and (3) processing kerogen oil to produce refinery 
feedstock and high-value chemicals. This sequence is illustrated below.

Conversion of Oil Shale to Products (Surface Process) Resource -->Ore 
Mining-->Retorting-->Oil Upgrading-->Fuel and Chemical Markets

    For deeper, thicker deposits, not as amenable to surface- or deep-
mining methods, the shale oil can be produced by in-situ technology. 
In-situ processes minimize or, in the case of true in-situ, eliminate 
the need for mining and surface pyrolysis by heating the resource in 
its natural depositional setting. This sequence is illustrated below.

Conversion of Oil Shale to Products (True In-Situ Process) Resource --
>In-Situ Pyrolysis-->Oil Upgrading-->Fuel and Chemical Markets

    The American Association of Petroleum Geologists estimates that the 
total world oil shale resources contain the equivalent of 2.6 trillion 
barrels of oil. According to estimates by the U.S. Geological Survey, 
the United States holds more than 50 percent of the world's oil shale 
resources.
    The largest known deposits of oil shale in the world are located in 
a 16,000 square mile area in the Green River formation in Colorado, 
Utah, and Wyoming (underlying the Piceance, Uinta, Green River, and 
Washakie Basins), which is estimated to contain the equivalent of 
between 1.5 and 1.8 trillion barrels of oil. Federal lands comprise 72 
percent of the total surface of oil shale acreage and 82 percent of the 
oil shale resources in the Green River formation.
    As stated in the June 9, 2005 call for nominations for the 
research, development, and demonstration (R, D and D) (70 FR 33753) 
leases, the BLM opted for a staged oil shale leasing program. The first 
stage is the research and development program followed by these 
proposed commercial leasing regulations.

 BLM oil shale initiatives since 1983.

    In 1973, four leases were issued in the oil shale prototype leasing 
program. During the 1973-74 oil shale prototype program, there were 
expectations of an economic boom in western Colorado which never 
materialized. The oil shale industry collapsed on May 2, 1982, commonly 
referred to as Black Sunday.
    In 1983, the BLM established an Oil Shale Task Force to address:
    (1) Access to unconventional energy resources (such as oil shale) 
on public lands;
    (2) Impediments to oil shale development on public lands;
    (3) Industry interest in research and development and commercial 
opportunities on public lands; and
    (4) Secretarial options to capitalize on these opportunities.
    On February 11, 1983, the BLM published a proposed rule for an oil 
shale leasing program (48 FR 6510). Due to apparent lack of interest in 
the development of oil shale, the BLM withdrew the proposed rule, 
effective September 25, 1985 (50 FR 38867).
    In order to be better able to expand and diversify domestic energy 
production, on November 22, 2004, the BLM published a notice in the 
Federal Register (69 FR 67935) requesting public comments on the 
potential for oil shale development within the Piceance Creek Basin in 
Colorado, the Uinta Basin in Utah, and the Green River and Washakie 
Basins in Wyoming. The Federal Register notice also requested comments 
on a proposed draft oil shale R, D and D lease form. Comments received 
were incorporated, as appropriate, into the final R, D and D lease 
form.
    On June 9, 2005, the BLM published a notice in the Federal Register 
(70 FR 33753) which initiated a R, D and D leasing program by 
soliciting nominations of 160-acre parcels of public land to be leased 
in Colorado, Utah, and Wyoming for conducting oil shale recovery 
technologies. In response to the 19 nominations of parcels that the BLM 
received, the BLM issued 6 R, D and D leases--5 in Colorado that were 
effective January 1, 2007, and an additional R, D and D lease in Utah 
that was effective on July 1, 2007. Each of the R, D and D leases 
contains a preference right for conversion to a commercial lease of 
additional acreage upon demonstration of a successful method of 
producing oil from shale rock.
    One of the purposes of the R, D and D leases, as stated in the 
notice was to provide the BLM, state and local governments, and the 
public with important information that could be utilized as the BLM 
works with communities, states, and other Federal agencies to develop 
strategies for managing the environmental effects of production. The R, 
D and D lease form was published as an attachment (Appendix A) to the 
June 9, 2005, Federal Register notice.

The PEIS and National Environmental Policy Act (NEPA) Compliance

    On December 13, 2005, the BLM published in the Federal Register a 
notice of intent (NOI) to prepare a PEIS (70 FR 73791) for oil shale 
and tar sands resources leasing on lands administered by the BLM in 
Colorado, Utah, and Wyoming. The NOI alerted the public that the BLM 
was intending to amend several resource management plans (RMPs) to open 
lands for oil shale and tar sands resources leasing in Colorado, Utah, 
and Wyoming. The NOI also informed the public of the development of the 
oil shale regulations required by Section 369(d)(2) of the EP Act. The 
RMPs are BLM planning documents prepared under Section 202 of the FLPMA 
that present guidelines for making resource management decisions.
    The draft PEIS evaluates the following RMPs for possible amendment:
    (1) Wyoming: Green River, Great Divide, and Kemmerer;
    (2) Utah: Price River, San Juan, San Rafael, Henry Mountain, Book 
Cliffs, and Diamond Mountain; and
    (3) Colorado: Grand Junction, White River, and Glenwood Springs.
    Although the PEIS covers planning for tar sands, these proposed 
regulations do not address tar sands leasing since the BLM has 
regulations in place that address tar sands leasing (see 43 CFR part 
3140).
    On December 21, 2007, the BLM published the notice of availability 
for the draft PEIS and has made the draft PEIS available for public 
comment (72 FR 72751). The BLM intends to finalize the PEIS before 
these regulations are final. The PEIS is primarily intended to analyze 
the impacts of land use allocation and not site specific oil shale 
leasing.

Advance Notice of Proposed Rulemaking

    The BLM recognizes that the creation of the rules governing the 
development of oil shale would need to address different possible 
technologies that have different associated impacts and costs. 
Therefore, to increase public participation and to aid in the 
development of oil shale regulations, the BLM published in the Federal 
Register an advance notice of proposed rulemaking (ANPR) (71 FR 50378) 
on August 25, 2006. The ANPR requested public comments on the following 
five

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key components of the proposed regulations:
    (1) What should be the royalty rate and point of royalty 
determination?
    (2) Should the regulations establish a process for bid adequacy 
evaluation,i.e., Fair Market Value (FMV) determination, or should the 
regulations establish a minimum acceptable lease bonus bid?
    (3) How should diligent development be determined?
    (4) What should be the minimum production requirement?
    (5) Should there be provisions for small tract leasing?
    On September 26, 2006, the BLM published a Federal Register notice 
reopening the comment period for the ANPR and extending the comment 
period until October 25, 2006 (71 FR 56085). In response to the ANPR, 
the BLM received 48 comments.
    Comments were received from individuals, public interest groups, 
and industry representatives. Although the ANPR focused on the 5 areas 
previously identified, commenters addressed a variety of topics, 
including whether or not they were supportive of a commercial oil shale 
leasing program. Below is a discussion of the ANPR organized by topic. 
Public comments BLM received on the ANPR are discussed in this preamble 
at the appropriate section of this rule.
    Royalty Rate and Point of Royalty Determination--Section 369(o) of 
the EP Act does not prescribe a royalty rate, but does provide that the 
royalty rate for oil shale should encourage development of the resource 
and should ensure a fair return to the United States. The ANPR comments 
received were extremely varied and recommended a wide range of royalty 
rates. Discussion of the ANPR royalty comments can be found in the 
discussion of section 3903.52 of this rule.
    Bid Adequacy Evaluation (Fair Market Value)--It is the policy of 
the United States, stated in Section 102(a) of FLPMA (43 U.S.C. 
1701(a)(9)) and Section 369(o)(2) of the EP Act, that the United States 
receive FMV for the issuance of Federal mineral leases. The BLM's 
purpose for requesting comments on the FMV it should receive for lease 
tracts was to solicit ideas on how FMV would be determined for a 
resource that has little or no history of comparable sales. The public 
comments received on the ANPR are discussed in section 3924.10 of this 
rule.
    Diligent Development--Section 369(f) of the EP Act requires that 
the BLM establish work requirements and milestones to ensure diligent 
development of Federal oil shale leases. The BLM requested public 
comment on diligent development to assist us in determining lease 
diligence requirements for an industry that has yet to be successfully 
established. A discussion of the ANPR comments we received on diligence 
can be found in section 3927.50 of this proposed rule.
    Minimum Production Requirement--The BLM specifically asked in the 
ANPR for suggestions from the public about what the minimum production 
requirement should be to assist us in determining lease production 
requirements for an industry that has yet to be successfully 
established. A discussion of the public comments we received on minimum 
production requirements can be found in section 3903.51 of this 
proposed rule.
    Small Tract Leasing--In the ANPR the BLM requested comments on 
whether there should be small tract leasing or leasing small acreages 
of land for oil shale development. A discussion of the public comments 
we received on small tract leasing can be found in section 3927.20 of 
this proposed rule.
    We also received several comments unrelated to the five questions 
in the ANPR. Those comments are discussed in the respective section 
discussions for the rule.

Listening Sessions With Governor's Representatives From Colorado, Utah, 
and Wyoming

    The BLM, in coordination with the Minerals Management Service 
(MMS), held three ``listening sessions'' with representatives of the 
governors of the States of Colorado, Utah, and Wyoming. The BLM and the 
MMS met with these representatives in Denver, Colorado (December 14, 
2006), Salt Lake City, Utah (April 26, 2007), and Cheyenne, Wyoming 
(August 8, 2007). The purpose of the listening sessions was to provide 
the governors' representatives the opportunity to share their ideas, 
issues, and concerns relating to the proposed commercial oil shale 
leasing regulations.
    Section 369(e) of the EP Act requires the Department of the 
Interior to consult with the governors of Colorado, Utah, and Wyoming, 
representatives of local governments, interested Indian tribes, and the 
public to determine the level of support for conducting oil shale lease 
sales. The BLM plans to consult with the affected states prior to 
conducting the first oil shale lease sale, and following publication of 
the final rule.

Consolidated Appropriations Act of 2008

    A provision in section 433 of the Consolidated Appropriations Act 
of 2008 (Pub. L. 110-161) prohibits the use of funds for the 
preparation or publication of final oil shale regulations, but does not 
apply to a proposed rule. Therefore, the BLM is publishing this 
proposed rule and will analyze comments received on the proposed rule, 
but will not prepare or publish a final rule using fiscal year 2008 
funds as provided by this Congressional directive.

III. Discussion of the Proposed Rule

Part 3900--Oil Shale Management--General

    This part would contain regulations on the general management of 
the oil shale program, including discussions of the descriptions and 
acreage in oil shale leases, qualifications requirements, fees, 
rentals, royalties, bonds and trust funds, and lease exchanges.

Subpart 3900--Oil Shale Management--Introduction

    This subpart would establish competitive oil shale leasing 
administrative procedures for implementing a long-term commercial oil 
shale leasing program.
    The proposed rule would contain specific provisions required by 
Section 369 of the EP Act. Many of the sections of the proposed rule 
contain regulatory requirements similar to the regulations in the BLM's 
existing mineral programs namely, coal, non-energy leasable minerals, 
and oil and gas. In creating a regulatory framework for this proposed 
oil shale commercial leasing program, the BLM proposes to adopt certain 
basic components and processes common to the BLM's leasing programs. 
Most of the BLM's leasing programs are governed by the MLA. The 
regulations governing those programs and this program would include the 
following types of provisions: Pre-lease exploration; leasing 
processes; bonding; operations (including plan of development); 
reclamation; and inspection and enforcement.
    Section 3900.2 would contain the definitions and terms used in 
these proposed regulations. Many of the terms and definitions found in 
this section would be similar to terms and definitions in the 
regulations of other BLM mineral leasing programs. Because most of the 
terms and concepts in this section are well-established, this section 
of the preamble does not address each of the definitions, but focuses 
only on definitions for certain terms that directly affect the reader's 
understanding of the regulatory framework of the oil shale leasing 
program or that are unique to these regulations.

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    The term ``commercial quantities'' means production of shale oil 
quantities in accordance with the approved Plan of Development for the 
proposed project through the research, development, and demonstration 
activities conducted on the lease, based on and at the conclusion of 
which a reasonable expectation exists that the expanded operation would 
provide a positive return after all costs of production have been met, 
including the amortized costs of the capital investment.
    The term ``infrastructure'' means all support structures necessary 
for the production or development of shale oil. The definition lists 
examples of the different types of support structures that the BLM 
would consider to be infrastructure. This term is defined in these 
proposed regulations because it is critical to the BLM's review of 
lease applications. Infrastructure impacts are a key component of the 
plan of operations that the BLM will review when undertaking various 
analyses such as those required by NEPA. Furthermore, the BLM believes 
that a detailed itemization of examples is necessary since installation 
of infrastructure is one of the proposed diligent development 
milestones.
    The term ``oil shale'' means a fine-grained sedimentary rock 
containing:
    (1) Organic matter which was derived chiefly from aquatic organisms 
or waxy spores or pollen grains, which is only slightly soluble in 
ordinary petroleum solvents, and of which a large proportion is 
distillable into synthetic petroleum; and
    (2) Inorganic matter, which may contain other minerals. This term 
is applicable to any argillaceous, carbonate, or siliceous sedimentary 
rock which, through destructive distillation, will yield synthetic 
petroleum.
    The BLM defined the term ``production'' to acknowledge the various 
technologies associated with operations for extraction of shale oil, 
shale gas, or shale oil by-products.
    Section 3900.5 would leave a place holder for the information 
collection requirements in parts 3900-3930 under 44 U.S.C. 3501 et seq. 
The BLM will add the OMB form number once we receive OMB's approval for 
information collection in the final regulations. The table in paragraph 
(d) of this section lists the subparts in the rule requiring the 
information and its title and summarizes the reasons for collecting the 
information and how the BLM would use the information.
    Section 3900.10 would identify which lands would be subject to 
leasing under parts 3900 through 3930. Section 21 of the MLA authorizes 
the issuance of oil shale leases (30 U.S.C. 241(a)).
    Section 3900.20 would address the right to appeal the BLM decisions 
issued under these regulations to the Interior Board of Land Appeals 
under 43 CFR part 4. This section would adopt standard appeals language 
found in the regulations of other BLM mineral programs.
    Section 3900.30 would contain standard language providing that 
documents (i.e., applications, statements of qualification, plans of 
development and supporting information, etc.) required by these 
proposed regulations be filed in the proper BLM office with the 
required fees. The term ``proper BLM office'' is defined in the 
definitions section of this rule.
    Section 3900.40 would address the multiple use mandate of FLPMA, by 
providing that the BLM's issuance of an exploration license or lease 
for the development or production of oil shale would not preclude the 
issuance of other exploration licenses or leases on the same lands for 
deposits of other minerals or other resource uses. This provision is 
similar to regulatory provisions in the BLM's other leasing programs, 
which also promote multiple use of the public lands.
    Section 3900.50 would clarify the relationship of land use plans 
and NEPA to the BLM's proposed commercial oil shale leasing program. 
This section would provide that any lease or exploration license issued 
under these regulations would be issued under the decisions, terms, and 
conditions of a comprehensive land use plan. The land use planning 
process is the key tool used by the BLM to protect resources and 
designate uses for BLM-administered lands. Compliance with NEPA and 
land use planning is required prior to the BLM's issuing a lease or 
exploration license.
    Section 3900.61 would address the procedures the BLM would follow 
concerning consent and consultation where the surface of public land is 
administered by other Federal agencies outside of the Department of the 
Interior and procedures for particular situations where the U.S. has 
conveyed title to or transferred control of the surface. Paragraphs (a) 
and (b) would address those procedures the BLM would follow concerning 
consent and consultation where the surface of public lands is 
administered by other agencies outside of the Department of the 
Interior. Paragraph (c) would provide procedures an applicant may 
pursue in challenging a decision issued by a particular agency outside 
of the Department of the Interior relating to special stipulations or 
refusal of consent. Paragraph (d) would not allow the BLM to issue a 
lease or license on National Forest Service lands without the consent 
of the Forest Service. Under paragraph (d), the BLM's decision whether 
to issue the lease or license is based on a determination as to whether 
the interests of the United States would best be served by issuing the 
lease or license. The provisions of this section closely mirror BLM 
regulations for oil and gas, coal, and non-energy leasable minerals. 
Paragraph (e) would provide that the BLM make the final decision as to 
whether to issue a lease or license in those cases not involving a 
Federal agency, where the United States has conveyed title to any state 
or political subdivision or agency, including a college or any other 
educational corporation or association, to a charitable or religious 
corporation or association, or to a private entity.
    Section 3900.62 would address situations where the BLM may require 
lease or exploration license stipulations to protect lands and 
resources. Stipulations are site specific provisions that the BLM may 
add to standard lease or license terms prior to issuance for the 
purpose of protecting Federal resource values and mitigating impacts to 
other values identified in a NEPA document. Stipulations frequently 
restrict operations on the lease or permit by limiting surface 
disturbance for the purpose of protecting the environment. This 
includes the protection of wildlife, plants, and cultural or other 
resources. This provision is similar to those found in the BLM's other 
mineral leasing programs.

Subpart 3901--Land Descriptions and Acreage

    Section 3901.10 would contain the BLM's requirements for land 
descriptions in applications or documents submitted to the BLM. This 
section is similar to the regulatory provisions addressing land 
descriptions found in other BLM leasing programs and would establish 
consistent standards for land descriptions in applications submitted to 
the BLM.
    Sections 3901.20 and 3901.30 would incorporate the provisions of 
Section 369(j)(2) of the EP Act that 50,000 acres would be the maximum 
acreage of oil shale leases on public lands that any entity may hold in 
any one state and that the oil shale lease acreage would not count 
toward acreage limitations associated with oil and gas leases. Another 
50,000 acres may be held on acquired lands. Since the provisions in 
this section relating to maximum acreage holdings are statutory, the 
BLM

[[Page 42930]]

does not have the authority to revise the requirements in this section.

Subpart 3902--Qualification Requirements

    Sections under this subpart would detail the various statutory 
requirements under Section 27 of the MLA relating to who can hold 
Federal oil shale leases and interests. These proposed regulations 
would mirror many of the qualification provisions of the BLM's other 
mineral leasing regulations, namely oil and gas (43 CFR subpart 3102), 
geothermal (43 CFR subpart 3202), coal (43 CFR subpart 3425), and non-
energy leasable minerals (43 CFR subpart 3502).
    Section 3902.10 would enumerate the requirements of the MLA 
relating to who is authorized to hold leases or interests in leases (30 
U.S.C. 181, 352). These requirements have a longstanding statutory and 
regulatory history and are found in the regulations for the BLM's 
mineral leasing programs.
    Sections 3902.21 and 3902.22 would explain the filing procedures 
for qualification documents, including when and where to file 
documents. Section 3902.21 would also require that all documentation 
submitted to the BLM as evidence of qualifications be current, 
accurate, and complete.
    Sections 3902.23 through 3902.29 would detail the type of 
qualifications documentation that the BLM would require from:
    (1) Individuals (section 3902.23);
    (2) Associations, including partnerships (section 3902.24);
    (3) Corporations (section 3902.25);
    (4) Guardians or trustees (section 3902.26);
    (5) Heirs and devisees (section 3902.27);
    (6) Attorneys-in-fact (section 3902.28); and
    (7) Other parties in interest (section 3902.29).
    The requirements proposed in these sections are similar to the 
standard requirements of other BLM regulations to show evidence of 
qualifications to hold a lease under the MLA.

Subpart 3903--Fees, Rentals, and Royalties

    For payments of required rental and royalties, sections 3903.20 and 
3903.30 would address the acceptable forms of payment (section 3903.20) 
and where to submit payment for processing or filing fees, rentals, 
bonus payments, and royalties (section 3903.30). The acceptable forms 
of payment listed in section 3903.20 would mirror the forms of payment 
accepted in the BLM's other mineral leasing regulations.
    Section 3903.40 would incorporate the requirement of Section 369(j) 
of the EP Act that the annual rental rate for an oil shale lease would 
be $2.00 per acre. Since the statute sets the rental rate, the BLM has 
no discretion to revise it.
    Section 3903.51 would address the minimal annual production 
requirement that would apply to every lease. It also would discuss 
payments in lieu of production beginning with the 10th lease year. The 
BLM would determine the payment in lieu of annual production, but in no 
case would it be less than $4 per acre. Payments in lieu of production 
are not unique to this proposed rule. They are a requirement of other 
BLM mineral leasing regulations and the BLM believes they provide an 
incentive to maintain production.
    Setting the payment in lieu of production at no less than $4 per 
acre should be an adequate payment to the Federal government to justify 
allowing the lessee to continue holding a lease absent production, but 
should not be high enough to cause the lessee to relinquish the lease. 
A payment in lieu of production of $4 per acre for the maximum lease 
size of 5,760 acres equals a payment of $23,040 per year.
    In response to the ANPR, the BLM received comments expressing 
various ideas concerning minimum production amounts and requirements. 
The comments are summarized as follows:
    (1) Minimum production should be 1,000 barrels a day;
    (2) Minimum production should be based on the viability of the 
operation;
    (3) Minimum production levels should be based on resource potential 
and production levels identified in the plan of development;
    (4) Minimum royalties should be assessed at the end of the primary 
term;
    (5) Minimum production should be based on a percentage of the 
projected resource base; and
    (6) There should not be a minimum production requirement.
    We agree with several of the commenter's suggestions. The 
suggestions to base minimum production on the approved plan of 
development and the specifics of the operation were incorporated into 
proposed sections 3930.30(c) and 3930.30(d). The suggestions related to 
defining the minimum production on a percentage of the resource base 
were not incorporated into the proposed rule because of the 
difficulties associated with defining the recoverable resource, the 
variables associated with the different development technologies, and 
the differing kerogen content of the shales. We consider the suggestion 
that identified 1,000 barrels a day as the correct minimum production 
requirement too inflexible a standard because it does not allow for 
differences in shale quality and differences in extraction technology.
Section 3903.52--Royalty Rates on Oil Shale Production
    Section 3903.52 would establish a royalty rate for all products 
that are sold from or transported off of the lease area. The BLM 
recognizes that encouraging oil shale development presents some unique 
challenges compared to BLM's traditional role in managing conventional 
oil and gas operations. We received a wide range of comments presenting 
alternative royalty approaches as part of the ANPR process, and we 
address those comments below. However, while we have narrowed the range 
of options based on the ANPR comments, we have not yet settled on a 
single royalty rate for this proposed rule. Instead, we are presenting 
two royalty rate alternatives in the proposed rule (as outlined later 
in this section), and requesting public comment on those specific 
alternatives. In addition, we are considering a third alternative, a 
sliding scale royalty rate (also outlined in this preamble), and we are 
seeking public comment on the appropriate parameters for the sliding 
scale royalty rate should the BLM choose to adopt this alternative. We 
anticipate adopting one of these alternatives, or variations on one of 
these alternatives, at the final rule stage.
    EP Act (Section 369(o)) directs the agency to establish royalties 
and other payments for oil shale leases that ``shall--
    (1) Encourage development of the oil shale and tar sands resources; 
and
    (2) Ensure a fair return to the United States.''
    The market demand for oil shale resources based on the price of 
competing sources (e.g., crude oil) of similar end products is expected 
to provide the primary incentive for future oil shale development. 
Additional encouragement for development may be provided through the 
royalty terms employed for oil shale relative to conventional oil and 
gas royalty terms, but we recognize that such incentives must be 
balanced against the objective of providing a fair return to taxpayers 
for the sale of these resources. Through the ANPR process, the BLM 
initially examined a wide range of royalty options, including:
    (1) 12.5 percent royalty rate on the first marketable product;

[[Page 42931]]

    (2) 12.5 percent royalty rate on the value of the mined oil shale 
rock, as proposed in 1983;
    (3) 8 percent royalty rate on products sold for 10 years with 
optional increases of 1 percent per year up to a maximum of 12.5 
percent, similar to the rates established by the State of Utah in 1980;
    (4) Initial 2 percent royalty to encourage production and a 5 
percent maximum upon establishment of infrastructure;
    (5) Sliding scale royalty rate tied to timeframes up to a maximum 
of 12.5 percent;
    (6) Sliding scale royalty rate tied to production amounts up to a 
maximum of 12.5 percent;
    (7) Sliding scale royalty rate with royalty rates tied to the price 
of crude oil;
    (8) Royalty rate of 1 percent of gross profit before payout and 
royalty rate of 25 percent net profit after payout--(Canadian oil sands 
model);
    (9) Royalty based on cents per ton as proposed in the 1973 oil 
shale prototype program; and
    (10) Royalty based on British Thermal Unit (Btu) content as 
compared to crude oil.
    In evaluating an appropriate royalty rate system for oil shale that 
would meet the dual EP Act objectives of encouraging development and 
ensuring a fair return to the government, the BLM also reviewed other 
Federal royalty rates for Federal minerals set by statute and under 
existing regulations administered by Department of the Interior 
bureaus, and royalty rates applied to oil shale production in other 
countries.
    The royalty rates for other Federal energy minerals vary. 
Specifically, current royalty rates for Federal energy minerals under 
Department of the Interior leasing programs include:
    (1) Onshore oil and gas (12.5 percent);
    (2) Offshore oil and gas (16.67 percent), Gulf of Mexico Region 
(18.75 percent);
    (3) Underground coal (8 percent);
    (4) Surface coal (12.5 percent) and
    (5) Geothermal (for new leases: 1.75 percent for the first 10 years 
and 3.5 percent thereafter. For leases issued prior to the EP Act, 10 
percent on net proceeds after deductions).
    Many of these programs allow for royalty rate relief under certain 
circumstances.
    The BLM also looked at royalty applications for oil shale and 
similar unconventional fuels in other countries, including:
    (1) For oil sands, Canada applies a royalty rate of 1 percent of 
the gross revenue before payout (before companies have recouped 
investment costs) with a 25 percent net profit royalty rate applied 
after payout;
    (2) Australia has a 10 percent gross royalty on the value of the 
shale oil produced;
    (3) Brazil applies a 3 percent gross royalty rate;
    (4) Estonia does not have a royalty; and
    (5) No information on a royalty rate for shale oil produced in 
China was available.
    It should be noted that Canada produces oil from oil sands, not oil 
shale. The oil in the sands is the same as crude oil, but dispersed in 
sand. Extraction and processing is more expensive than for conventional 
crude oil production, but less expensive than is anticipated for oil 
shale. Canadian operators have never reached the payout point due to 
the continued capital expenditures in new equipment, so to date, Canada 
has received a 1 percent royalty on oil sands production.
    Australian operations are using the Alberta Taciuk Process, which 
is the same type of technology currently used by the Oil Shale 
Exploration Company (OSEC) in Utah. Despite their 10 percent royalty 
rate, the Australian oil shale project (the Stuart Project) was heavily 
subsidized by the Australian government through other means (tax 
incentives). Even the government subsidies could not sustain oil shale 
operations in Australia. The last three operators went into bankruptcy 
after brief operations. Suncor, the founder of the Stuart Project and a 
successful developer of the Canadian tar sands, exited the Australian 
oil shale business after losing approximately one hundred million 
dollars.\1\ For its Utah demonstration project, OSEC is also expected 
to test the Petrosix horizontal retort process, which is currently 
being used by Petrobras, Brazil, for oil shale operations.
---------------------------------------------------------------------------

    \1\ Environmental News Service, July 22, 2005, https://www.ens-
newswire.com.
---------------------------------------------------------------------------

    Australia and Brazil are the only other known countries that are 
producing or have produced oil shale using the same technologies as in 
the U.S. Oil shale developmental efforts in China and Estonia are owned 
by their respective governments. Because no other country has yet 
achieved successful commercial oil shale operations and because of the 
wide variety of oversight and revenue structures employed in each 
country, the BLM's review of these systems did not identify a useful 
model for a royalty system to be used for oil shale development on 
Federal lands in the U.S.
    In the ANPR, the BLM solicited public input on the royalty rate and 
point of royalty determination. The BLM's purpose for requesting 
comments was to solicit ideas on these royalty issues for a resource 
that has little or no history of commercial development.
    There were approximately thirty-one entities that provided comments 
through the ANPR process that were specific to royalty rate and royalty 
point of determination. The comments suggested royalty rates that 
ranged from a royalty rate of zero to a royalty rate of 12.5 percent. 
Of the royalty-related comments, three suggested that the royalty be 
set at 12.5 percent, the same rate as in BLM's oil and gas program, 
while some comments described a 12.5 percent royalty rate as 
unreasonable. It is contemplated that the primary products produced 
from oil shale will compete directly with those from onshore oil and 
gas production, which has a 12.5 percent royalty rate. However, the BLM 
recognizes that the nature of potential oil shale operations differs 
from that of conventional oil and gas operations and that these 
differences may suggest the need for a royalty system other than the 
traditional flat rate of 12.5 percent used for conventional onshore oil 
and gas operations.
    In determining the royalty rate for oil shale, it should be noted 
that there is a significant difference between oil shale mineral 
deposits and a conventional crude oil reservoir. As discussed in the 
Background section of this preamble, oil shale is a marlstone that 
contains no oil, but kerogen, that needs to be refined and converted to 
synthetic crude oil.
    Currently, proposed processes to extract kerogen from an oil shale 
deposit are also considerably different, as well as labor and capital 
intensive. Oil shale is a solid rock that must be mined or treated in 
place to release the kerogen. Two of these processes are discussed in 
the Background section of this preamble.
    Seven of the comments recommended that a ``very low royalty rate'' 
be established until after companies have recouped the costs of their 
investments (debt service and capital investment). Many among the seven 
recommended that a 1 percent royalty rate be the starting point, and 
they used the Canadian oil sands royalty scheme as an example. As 
discussed above, the BLM looked at royalty applications for oil shale 
and similar unconventional fuels in other countries. The Canadian tar 
sand model presents two challenges. First, because of the continual 
infusion of capital to acquire new equipment the payout point is never 
being reached.

[[Page 42932]]

Secondly, because of the complexity of determining when payout may 
occur, such a royalty scheme is subject to easy manipulation and higher 
administrative costs. Therefore, the BLM considered the investment 
payout scheme as inconsistent with the premise of ``a fair return'' to 
the taxpayers as mandated in EP Act.
    Three of the ANPR comments recommended that ``royalties must be 
high enough'' to support local communities and infrastructure; however, 
these comments did not provide specific royalty rates. Oil shale 
royalties are not designated for community and infrastructure support, 
but by statute are required to be split between the Federal Treasury 
and the states (30 U.S.C. 191). Presumably states could choose to 
direct a portion of the royalty revenues they receive to local 
community and infrastructure support, but that would be a state choice, 
and for the purposes of this rulemaking, these comments were not 
considered because they assume a use of royalty revenues not available 
under current law.
    Three comments suggested that royalties should not be charged on 
hydrocarbons unavoidably lost or used on the lease for the benefit of 
the lease, but did not directly address the royalty rate issue.
    One comment suggested the royalty be ``based on the material as it 
exists naturally in the land, and as it is removed from the land.'' 
This comment seems to suggest that royalty should be based on mined raw 
shale. While the BLM acknowledges the inherent differences between an 
oil shale deposit and other deposits from which similar products can be 
produced, this suggestion was not considered because there is no known 
value for raw oil shale since there is no oil shale industry or an 
established market for raw oil shale. However, it should be noted that 
in 1983 the BLM proposed a rule to establish a royalty rate equivalent 
to 12.5 percent of the value of oil shale after mining or resource 
extraction and before processing, as determined by the BLM. The 1983 
proposed rule was published on February 11, 1983 (48 FR 6510). The 1983 
proposed rule provided that ``the derivation methodology for this value 
shall be announced prior to the solicitation of bids.'' The proposed 
rule further stated that ``the royalty rate shall, to the extent 
practicable, not be levied on any value added by the production process 
after the point of resource extraction.'' It would be unreasonable to 
adopt such a proposal today, due to the changes in extraction 
methodology (in situ versus ex situ). It would also be challenging to 
develop a fair and transparent process to calculate the royalty 
equivalent in today's economic environment, and no values were assigned 
to the mined or unprocessed rock and tonnage in the 1983 proposed rule. 
As noted, the 1983 proposed rule deferred the determination of those 
parameters to a later date.
    In addition to ANPR comments received on royalty rates, the BLM 
looked at an initial 2 percent royalty to encourage production and a 
maximum 5 percent rate upon establishment of infrastructure. This 
method recognizes the high costs involved in producing shale oil. 
However, we dismissed this approach because of the difficulty involved 
in determining when necessary infrastructure is in place.
    The BLM also considered the 8 percent royalty rate established by 
the State of Utah for state oil shale leases. It was determined that 
this rate represents the historic base royalty rate for solid fuel 
minerals on the State of Utah School and Institutional Trust Lands 
Administration lands--including asphaltic sands, uranium, and coal. To 
date, none of the state leases in Utah have been developed. Based on 
these facts, the BLM determined that there is not currently a 
sufficient basis for simply adopting the State of Utah's royalty rate 
for oil shale on Federal lands.
    After examining the basis for setting rates, as suggested in the 
ANPR comments, the BLM determined that a flat 12.5 percent royalty rate 
for all future production may not allow oil shale to become competitive 
with traditional oil and gas development and therefore could be viewed 
as inconsistent with the requirements of EP Act. The BLM has decided to 
consider other alternatives in this proposed rule that may provide some 
additional incentive beyond that of a flat 12.5 percent royalty rate 
while also meeting the EP Act objective of providing a fair return to 
taxpayers.
Royalty Rate Alternatives Proposed for Further Consideration
    As noted previously, we are not proposing a single royalty system 
in the proposed rule. Based on the information the BLM has reviewed to 
date and considering the unique challenge of trying to set a royalty 
rate on oil shale production in light of the many uncertainties 
regarding the economics and technology of a potential future oil shale 
industry, we are instead presenting two different royalty rate 
alternatives in the proposed rule text:
    1. A flat 5 percent royalty rate; and
    2. A 5 percent royalty rate on a specific volume of initial 
production beginning within a prescribed timeframe, with a 12.5 percent 
rate applied thereafter.
    In addition, we are seeking comment on the appropriate parameters 
for a third option: A two-three tiered sliding scale royalty based on 
the market price of competing products (e.g., crude oil and natural 
gas). A further explanation of each of these proposals is presented 
below. We are requesting the public to comment on these specific 
options.
Option 1. Flat 5 Percent Royalty
    Although mitigated somewhat by the much greater geographic 
concentration of oil shale resources, there is a significant difference 
between the energy value of oil shale and crude oil. On a per-pound 
basis, very high quality oil shale rock generates 4,300 Btu, coal 
generates an average of 10,600 Btu, while crude oil generates 19,000 
Btu. Even wood has more heating capacity than oil shale rock, 
generating an average of 6,500 Btu. Applying the relative Btu value of 
oil shale to crude oil would result in a 2.6 percent royalty for oil 
shale. Using the same comparison to the royalty rate for underground 
coal would result in a 3.2 percent royalty rate for oil shale. In other 
words, it would require almost 5 times as much oil shale to produce the 
Btu value of crude oil and more than 2 times as much oil shale to 
produce the equivalent Btu value of coal.
    The BLM looked at royalty rates on leases issued under Interior's 
1973 Prototype Leasing Program. The prototype leases provided for 
royalties of $.12 per ton for oil shale with a quality of 30 gallons of 
oil per ton (30 g/t) with the addition of $.01 for every increase in 
gallon per ton of oil shale. In 1973, the average price of a barrel of 
oil was $3.89. At $.24 per ton of 42 g/t or one barrel/ton of oil 
shale, the royalty per barrel of oil would have been 5 percent. This 
rate is similar to the rate derived by comparing production costs to 
royalty rates as recommended by these proposed regulations.
    The BLM also estimated what royalty rates for shale oil might be, 
based on comparisons of production costs for similar products. The cost 
of removing oil from shale rock is currently estimated to be two to 
three times higher than the current cost of producing conventional 
crude oil from onshore operations. The current estimated production 
cost for shale oil ranges from about $37.75-$65.21 a barrel. The 
production cost for conventional onshore crude is

[[Page 42933]]

approximately $19.50 a barrel.\2\ The table below compares the 
estimated cost of shale oil production for different technologies with 
the estimated cost of current onshore U.S. conventional oil production. 
The table also estimates what royalty rates for oil shale production 
might be, for the different production methods, compared to a 12.5 
percent royalty rate for conventional oil production, if the higher 
anticipated production costs for oil shale are taken into account.
---------------------------------------------------------------------------

    \2\ Energy Information Administration, Crude Oil Production, 
dated July 3, 2008. https://www.eia.doe.gov/neic/infosheets/
crudeproduction.html and https://www.eia.doe.gov/emeu/perfpro/tab_
12.htm. The production cost at the time of analysis was 
approximately $18 per barrel.

----------------------------------------------------------------------------------------------------------------
                                                                   Royalty calculation based on       Adjusted
                                              Estimated shale   difference in production cost of a   royalty for
                Technology                    oil production     barrel of conventional oil versus    shale oil
                                             costs per barrel                shale oil                (percent)
----------------------------------------------------------------------------------------------------------------
Surface mining............................              $44.24  $19.50/$44.24 = 44.07% x 12.5% =            5.5
                                                                 5.51%.
Underground mining........................               54.00  $19.50/$54 = 36.11% x 12.5% =               4.5
                                                                 4.51%.
Fracturing and heating in place...........               65.21  $19.50/$65.21 = 29.90% x 12.5% =            3.75
                                                                 3.74%.
Heating only in place.....................               37.75  $19.50/$37.75 = 51.65% x 12.5% =            6.5
                                                                 6.46%.
----------------------------------------------------------------------------------------------------------------

    Adjusting royalty rates based on higher anticipated production cost 
for oil from oil shale is not a new concept and is similar to the 
situation in the coal program where underground coal operations compete 
with surface coal operations, which have lower production costs. 
Congress addressed this disparity in production costs by allowing for 
different royalty rates for coal mined underground versus coal mined at 
the surface.
    Please specifically comment on whether or not the anticipated costs 
of producing oil shale should be considered in establishing the royalty 
rate for all oil shale products and whether the BLM has chosen 
appropriate reference points for this production cost comparison.
    Therefore, one alternative that considers the decreased energy 
content and increased production costs, while encouraging production 
and ensuring an appropriate return to the government is to set a flat 
royalty rate of 5%. This alternative assumes that oil shale will 
continue to be more expensive to produce for many years when compared 
to new conventional oil.
Option 2. A 5 Percent Royalty on Initial Production, With 12.5 Percent 
Thereafter
    This alternative would provide a reduced royalty rate of 5% as a 
temporary incentive for early production of oil shale (similar to 
royalty incentives offered to spur initial Outer Continental Shelf 
(OCS) deepwater production), but with the standard 12.5% onshore oil 
and gas royalty rate applying to all oil shale production after a set 
timeframe and a set amount of production has taken place. Like the 
other royalty options, this option would require oil shale lessees to 
pay royalties on the amount or value of all products of oil shale that 
are sold from or transported off of the lease. This section would 
explain that the standard royalty rate for the products of oil shale is 
12.5 percent of the amount or value of production. However, under this 
option, for leases that begin production of oil shale within 12 years 
of the issuance of the first oil shale commercial lease, the royalty 
rate would be 5 percent of the amount or value of production on the 
first 30 million barrels of oil equivalent produced.
    The advantage of this alternative over a flat 5% royalty (Option 1) 
is that it provides a better return to taxpayers on later production if 
oil prices remain high and oil shale production becomes competitive 
with new conventional oil projects. At $60/barrel, this would amount to 
roughly $1.8 billion in production allowed per lease at the lower 5% 
royalty rate, providing roughly a $135 million in savings per lease 
compared to using the standard onshore oil and gas royalty rate of 
12.5%.
    One potential downside to this alternative is that offering royalty 
incentives without regard to oil prices increases the likelihood that, 
if oil prices remain high, the government will sacrifice revenue 
without affecting actual oil shale development. For example, at $120/
barrel, the savings would be worth $270 million, even though oil shale 
operations would be more profitable than at oil prices of $60/barrel.
    Therefore, we are also requesting comment on whether, if this 
proposal were adopted in the final rule, the temporary 5% royalty on 
initial production should also be conditioned on crude oil and natural 
gas prices (similar to OCS deepwater royalty incentives) and if so, 
what oil and gas price level would trigger payment at the higher 12.5% 
rate if prices exceeded the threshold. We would also like comments on 
the 12 year timeframe for reduced royalty.
Option 3. Sliding Scale Royalty Based on the Market Price of Oil
    Two comments suggested a sliding scale royalty format. One comment 
specifically suggested a sliding scale royalty scheme based on a 
royalty schedule that varies with the price of conventional crude, as 
follows:
    At $10 per barrel of conventional crude, the royalty rate should be 
zero;
    At $15 per barrel, royalty should be 0.25 percent and should 
increase by 0.25 percent for every $5 per barrel increase up to $35 per 
barrel;
    At $40 per barrel, the royalty rate should be 2 percent and should 
increase by 0.5 percent for every $5 per barrel increase in the price 
of conventional crude oil until the price of conventional crude reaches 
$100 per barrel; and
    At $100 per barrel, royalty rate should be 8 percent and should 
remain at 8 percent at prices above $100 per barrel.
    Another comment suggested two approaches to calculating royalty. 
The first part of the comment suggested that a simple way to accomplish 
royalty rates would be to index the value of barrels of oil equivalent 
to some percentage of NYMEX futures (say, 30 day average front month) 
prices. The commenter suggested that the index should be some fraction 
of the price, such as 50 to 65 percent. In the second part of the 
comment, the commenter suggested that, as an alternative to indexing, 
the BLM use a sliding royalty rate that is calculated on the difference 
between product price and the highest-cost production in the industry. 
The commenter cautioned that ``there need to be provisions that 
deferred portions of the royalty do not reduce mineral lease payments 
to the States, if an escalating royalty rate is used.''

[[Page 42934]]

    The BLM, in consultation with the MMS, evaluated these variable 
royalty options, but decided that as presented, they would be highly 
complex, and therefore, cumbersome to administer. With price volatility 
in the crude oil market, an intricate sliding scale royalty scheme 
could make enforcing compliance very difficult for the MMS. In 
addition, there is uncertainty about the types of products that would 
be derived from oil shale refining. Royalties based on oil shale 
quality would also be difficult for the BLM to administer when 
attempting to verify production quantities. For instance, if oil shale 
is extracted in an underground heating system, it would be extremely 
difficult for the BLM to determine how much oil or other product came 
from a particular volume or area of in-place oil shale.
    While the BLM and MMS are concerned about the complexity of 
administering some of the proposed sliding scale royalty proposals, we 
recognize that there is some merit to the sliding scale concept, and in 
a simpler form, a sliding scale royalty may prove useful in meeting the 
dual goals of encouraging production and ensuring a fair return to 
taxpayers from future oil shale development.
    One of the concerns that has been expressed regarding oil shale 
development is that potential oil shale developers may be reluctant to 
make the large upfront investments required for commercial operations 
if they believe there is a chance that crude oil prices might drop in 
the future below the point at which oil shale production would be 
profitable (i.e., competitive with new conventional oil production). A 
sliding scale royalty system could allow the government to at least 
partially mitigate this development risk by providing for a lower 
royalty rate if crude oil prices fall below a certain price threshold. 
The basic concept is that in return for the government accepting a 
greater share of the price risk that an operator faces when prices are 
low (in the form of a lower royalty), the government would receive a 
greater share of the rewards (through a higher royalty) when prices are 
high.
    The BLM has not decided on the specific parameters of a sliding 
scale royalty system, but is considering a simplified, two- or three-
tiered system based on the current royalty rates already in effect for 
conventional fuel minerals and with a 5 percent royalty rate (Option 1) 
representing the first tier. The applicable royalty rate would be 
determined based on market prices of competing products (e.g., crude 
oil and natural gas) over a certain time period. If prices remain below 
a certain point during the applicable period, the royalty rate on oil 
shale products would be 5 percent for that period. If prices are above 
that range for the period, a higher royalty would be charged. In a 
three-tiered system, a third royalty rate would apply if prices rise 
above a second price threshold during the applicable period.
    The BLM seeks comment on the specific parameters that could be 
applied to a sliding scale royalty system, should the BLM choose to 
adopt such a system in the final rule. More specifically, the BLM would 
like feedback on the following questions:
    1. Should a sliding scale system include two or three tiers? 
Assuming a 5 percent royalty for the first tier, what would be 
appropriate royalty rates for the second and/or third tiers?
    2. What are appropriate price thresholds to apply to each tier? 
Should the thresholds be fixed (in real dollar terms), or should they 
float relative to a published index?
    3. Should the sliding scale apply to all products, or should 
nonfuel products pay a traditional flat rate?
    4. Are there other ways to simplify a sliding scale royalty to 
reduce the administrative costs for BLM, MMS, and producers?
    Under a sliding scale system, if prices fall below the lower range, 
producers would have a ``safety net'' in the form of the lower 5% 
royalty rate. Whether or not the lower royalty kicks in at some point, 
simply having it in place provides some added certainty for investors 
that would help encourage oil shale production. In return for this 
``safety net'' that conventional oil and gas producers do not enjoy, 
oil shale producers would be required to pay a higher royalty rate(s) 
when crude oil and/or natural gas prices are high (and where oil shale 
is expected to be substantially more profitable).
    There are a couple of advantages of this alternative. It reduces 
the risk for oil shale operators that oil prices might fall below the 
point that continued oil shale production would be economic. However, 
it also ensures an improved return to the government if prices remain 
within one of the higher expected ranges at which oil shale may be 
profitable. One disadvantage is that taxpayers accept a greater risk of 
lower returns if prices fall and remain well below the lowest 
threshold. However, with the lowest royalty rate step set at 5 percent, 
this risk is no greater than under a flat 5 percent royalty system 
(Option 1).
Other Royalty Issues
    The BLM also received 5 comments specific to the royalty point of 
determination. Two of the comments suggested that royalty should be 
determined ``at the point at which the oil product exits a process 
facility in a marketable state.'' One comment suggested that ``the 
point of royalty determination be at the earliest point of liquid or 
gaseous product marketability.'' Another comment suggested that ``the 
oil produced should be measured at the point at which the oil product 
exits a processing facility in a marketable state.'' The last comment 
did not provide a specific suggestion; rather, it stated that the