Oil Shale Management-General, 69414-69487 [E8-27025]

Agencies

• DEPARTMENT OF THE INTERIOR
• Bureau of Land Management

[Federal Register Volume 73, Number 223 (Tuesday, November 18, 2008)]
[Rules and Regulations]
[Pages 69414-69487]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E8-27025]



[[Page 69413]]

-----------------------------------------------------------------------

Part IV





Department of the Interior





-----------------------------------------------------------------------



Bureau of Land Management



43 CFR Parts 3900, 3910, et al.



-----------------------------------------------------------------------



 Oil Shale Management--General; Final Rules

Federal Register / Vol. 73, No. 223 / Tuesday, November 18, 2008 / 
Rules and Regulations

[[Page 69414]]


-----------------------------------------------------------------------

DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Parts 3900, 3910, 3920, and 3930

[LLWO-3200000 L13100000.PP0000 L.X.EM OSHL000.241A]
RIN 1004-AD90


Oil Shale Management--General

AGENCY: Bureau of Land Management, Interior.

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: The Bureau of Land Management (BLM) is finalizing 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 
(Secretary) 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 final regulations incorporate specific provisions of the 
Mineral Leasing Act of 1920 (MLA) and the EP Act relating to: Oil shale 
lease size; Acreage limitations; Rental; and Lease diligence.
    These regulations also address the diligent development 
requirements of the EP Act by establishing work requirements and 
milestones to ensure diligent development of leases. The rule also 
provides for other standard components of a BLM mineral leasing 
program, including lease administration and operations.

DATES: This rule is effective on January 17, 2009.

ADDRESSES: You may send inquiries or suggestions to Director (320), 
Bureau of Land Management, 1620 L Street, NW., Room 501, Washington, DC 
20036, Attention: RIN-AD90.

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. Background
II. Final Rule as Adopted and Response to Comments
III. Procedural Matters

I. Background

    These regulations 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 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 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 from the rock. Energy companies and petroleum 
researchers have, over the past 60 years, developed and tested a 
variety of technologies on a small scale for recovering shale oil from 
oil shale and processing it to produce fuels and by-products. 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) processing 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 processes 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 
Processing >< 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.

BLM Oil Shale Initiatives Since 1973

    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

[[Page 69415]]

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 Research, Development, and Demonstration 
(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 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 contain 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 make 
lands available 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 FLPMA that present guidelines for making resource 
management decisions.
    The draft PEIS evaluated 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 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 
(NOA) for the draft PEIS and made the draft PEIS available for public 
comment (72 FR 72751). On September 5, 2008, the BLM published a NOA 
announcing the availability of the final PEIS (73 FR 51838). The PEIS 
is primarily intended to analyze the impacts of land use allocation and 
not site-specific oil shale leasing. The Record of Decision (ROD) has 
not yet been signed. The ROD will describe and approve the BLM's 
proposal to amend 12 RMPs to identify the most geologically prospective 
public lands in Colorado, Utah, and Wyoming for oil shale and tar sands 
resources, and to designate certain of these lands as available for 
application for commercial leasing and future exploration and 
development of these resources.

Advance Notice of Proposed Rulemaking

    The BLM recognized 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 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. The BLM considered the ANPR comments in drafting the 
proposed and final rules.

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 (Department) 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 this rule.
    On July 23, 2008, the BLM published in the Federal Register a 
proposed rule entitled Oil Shale Management--General (73 FR 42926). The 
comment period on the rule closed on September 22, 2008. The BLM 
received over 75,000 comment letters on the proposed rule from 
individuals, Federal and state governments and agencies, interest 
groups, and industry representatives. Substantive comments on the 
proposed rule are discussed in this preamble in the section discussions 
of this rule. If

[[Page 69416]]

we received no substantive comment on a particular section of the rule, 
that section remains as proposed.

II. Final Rule as Adopted and Response to Comments

Part 3900--Oil Shale Management--General

    This part contains 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 establishes competitive oil shale leasing 
administrative procedures for implementing a commercial oil shale 
leasing program.
    The rule contains specific provisions required by Section 369 of 
the EP Act. Many of the sections of the 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 the oil shale commercial leasing 
program, the BLM is adopting 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 include the following types of provisions: 
Pre-lease exploration; leasing processes; bonding; operations 
(including plan of development (POD)); reclamation; and inspection and 
enforcement.
    Section 3900.2 contains the definitions and terms used in these 
regulations. Many of the terms and definitions found in this section 
are 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.
    The BLM removed the definition for ``Director'' in the final rule 
because the term is not used in the regulatory text.
    The term ``commercial quantities'' was discussed in the proposed 
rule as 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 R, 
D and D 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. One commenter stated that 
the report, Oil Shale Development in the United States, (James Bartis, 
2005) estimates that the minimum size of a commercial scale operation 
will likely be over 100,000 barrels per day. The BLM interprets this as 
a recommendation to define commercial quantities as production of at 
least 100,000 barrels per day. Another commenter stated that an 
alternative method of defining commercial quantities would be to set it 
at no less than 1/2 of 1% of the recoverable resource on the lease. The 
BLM did not adopt these recommendations because ``commercial 
quantities'' does not apply to commercial lease production, but is a 
condition in an R, D and D lease that must be met before an R, D and D 
lessee can convert the R, D and D acreage and preference acreage to a 
commercial lease. One commenter expressed the view that the definition 
in the proposed rule for ``commercial quantities'' was subjective and 
that the definition should be revised to confirm that an oil shale 
lessee will only be required to pay royalties once operations convert 
from the test phase to a commercial operations phase. The definition of 
``commercial quantities,'' applies only to the R, D and D leases and 
mirrors the definition for ``commercial quantities'' that is in the 
existing R, D and D leases. Provisions in the R, D and D leases also 
address the payment of royalties, therefore, we have revised the 
definition for ``commercial quantities'' in the final rule to make it 
clear that the definition only applies to R, D and D leases. Another 
commenter stated that there is an inconsistency between the 
``commercial quantities'' definition and the ``diligent development'' 
definition in that section 3927.50 provides that market conditions are 
not considered a valid reason to waive or suspend the requirements for 
annual minimum production. As stated previously, the definition for 
``commercial quantities'' only applies to R, D and D leases; therefore, 
there is no connection, or inconsistency, between the definition for 
``commercial quantities'' and the diligent development requirements in 
section 3927.50.
    Finally, commenters said that the commercial quantities definition 
needs to take into account all of the related costs. The term 
``commercial quantities'' pertains only to the R, D and D leases. As 
stated in the commercial quantities definition of this rule, the BLM 
will evaluate all costs of production, including the amortized costs of 
the capital investment when determining whether an R, D and D lease 
should be converted to a commercial lease. We did not revise the 
definition of commercial quantities as a result of public comment.
    One commenter requested that the BLM clarify the definition for 
``exploration license'' to indicate that the holder of an exploration 
license does not have an automatic right to a lease to develop oil 
shale. We made a change in the final rule to address this concern by 
making it clear that an exploration license confers no right to a lease 
to develop oil shale.
    One commenter noted the absence of a definition for ``royalty'' and 
suggested that the BLM describe whether royalty is based on net or 
gross revenue and the components thereof. Please see the discussion of 
royalty valuation in subpart 3903 for a response to this comment.
    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 
considers to be infrastructure. This term is defined in these 
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 diligent development milestones.
    We received several comments discussing the need to modify the 
definition of the term maximum economic recovery (MER). The commenters 
pointed out that the oil shale industry is not yet established and 
therefore there currently are no standard industry operating 
procedures.
    The BLM agrees with the commenter in that, at this time, there is 
no established oil shale industry. However, the concept of MER is 
incorporated into many of the BLM's other mineral leasing regulations 
either as MER or as ultimate maximum recovery. The term specifically 
means that there is a need to prevent wasting of resources and that 
there should be requirements to recover the maximum amount of the 
resource that is technologically and economically possible, without 
jeopardizing safety considerations.

[[Page 69417]]

    The commenter also said that the term is used in various sections 
of the regulations and the phrase ``standard operating procedures'' 
needs to be clarified. In response to the comment, the BLM believes 
that even though there is no established oil shale industry and that 
technology in most cases is still untested, once an industry is 
established, there will be standard industry procedures that will be 
evaluated in determining MER taking into account such factors as the 
differences in technologies, resource characteristics, and geologic 
conditions. The BLM will also evaluate economics associated with the 
individual operation, market conditions, and standard operating 
procedures that are appropriate for the technologies of the established 
industry. In the future, the BLM will determine additional standard 
operating procedures that might be adopted for a future oil shale 
industry.
    As a result of the comments submitted on MER, the BLM revised and 
simplified the definition of maximum economic recovery in the final 
rule. The revised definition of maximum economic recovery reads as 
follows: Maximum Economic Recovery (MER) means the prevention of 
wasting of the resource by recovering the maximum amount of the 
resource that is technologically and economically possible, without 
jeopardizing safety considerations.
    We received several comments requesting that the BLM add additional 
definitions in the regulations. Some suggestions included adding to the 
definition section: Raw oil shale, charred spent oil shale, de-charred 
oil shale, char, raw shale oil, raw shale gas, hydrotreated shale oil, 
processed/separated gas, process energy efficiency, energy self 
sufficient effective resource recovery, minimum environmental impact, 
and Fischer Assay (FA)/TOSCO Assay. The suggested terms are used to 
describe various parts and components of shale oil extraction and 
processing. However, the BLM did not include the terms in the final 
rule because they are terms that describe processes, components, or 
items that were not being regulated or were terms that did not need an 
explanation or definition in the final rules. Some of the terms we 
consider subsets of other defined terms.
    The BLM believes that the comment on including a definition for the 
term ``spent shale'' is too restrictive, but decided to address the 
``waste'' resulting from the mining, in-situ, and retorting operations. 
Therefore, the BLM added a definition of the term ``mining waste'' 
because it is more inclusive and could be defined as pertaining to the 
waste from surface, underground, and in-situ operations and oil shale 
retorting operations. In the final rule, mining waste is defined as 
``All tailings, dumps, deleterious materials or substances produced by 
mining, retorting, or in-situ operations.'' The term ``mining waste'' 
is incorporated into both the definitions section 3900.2 and the 
contents of an operating plan in section 3931.11 of the regulations.
    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 explains the information collection requirements for 
the rule. The OMB has reviewed and approved the information collection 
requirements in parts 3900 through 3930 under 44 U.S.C. 3501 et seq. 
and assigned clearance number 1004-0201. 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 will use the information.
    Section 3900.10 identifies which lands are 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)). The final rule expands this 
section to make it clear that certain National Park Service lands are 
not available for oil shale leasing. We also added a new paragraph (c) 
to this section to make it clear that the BLM may not issue oil shale 
leases on lands within incorporated cities and towns and to be 
consistent with the MLA (30 U.S.C. 181).
    Section 3900.20 addresses the right to appeal BLM decisions issued 
under these regulations to the Interior Board of Land Appeals (IBLA) 
under 43 CFR part 4. This section adopts standard appeals language 
found in the regulations of other BLM mineral programs.
    Section 3900.30 contains standard language providing that documents 
(i.e., applications, statements of qualification, PODs and supporting 
information, etc.) required by these 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. Several commenters 
expressed concern about the release of confidential data or information 
and requested greater specificity regarding the information that is 
entitled to confidentiality when it is submitted to the BLM. Section 
3900.30(b) of the proposed and final rule references the Freedom of 
Information Act (FOIA) (5 U.S.C. 552), which includes an exemption for 
confidential data and for certain geological information. This 
exemption under the FOIA is the most common standard that the BLM is 
required to follow concerning proprietary information; other statutory 
grounds for withholding information might apply in particular 
circumstances.
    Section 3900.40 addresses 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. One comment 
suggested that the oil shale lessee should be able to obtain the 
predominant right to develop the oil shale without competing uses. 
Another comment suggested that the BLM should reconsider the extent to 
which it is issuing oil and gas leases in oil shale areas. The BLM must 
manage the public lands under the principles of multiple use as 
mandated by FLPMA (43 U.S.C. 1732) (see also 43 CFR 3000.7), therefore, 
a predominant right should not be considered to have been granted to an 
oil shale lessee. In the event of unavoidable conflict, the Federal 
mineral lease for the same lands with the earlier effective date has 
priority for operations because later lessees have constructive notice 
of the prior lease, unless the prior lease is specifically subordinated 
to later-approved uses. Prior to issuing any mineral lease, the BLM 
considers potential conflicts and the impact on other resources, 
including mineral resources, and takes measures, including adding lease 
stipulations, to ensure that resources are not unnecessarily lost or 
damaged.
    Section 3900.50 clarifies the relationship of land use plans and 
NEPA to the BLM's commercial oil shale leasing program. This section 
provides that any lease or exploration license issued under these 
regulations

[[Page 69418]]

must 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 before BLM can issue a lease or exploration license.
    Section 3900.61 addresses the procedures the BLM will follow 
concerning consent and consultation where the surface of public land is 
administered by other Federal agencies outside of the Department and 
procedures for particular situations where the United States has 
conveyed title to or transferred control of the surface. Paragraphs (a) 
and (b) address those procedures that the BLM will follow concerning 
consent and consultation where the surface of public lands is 
administered by other agencies outside of the Department. One commenter 
expressed confusion regarding consent and consultation as they apply to 
section 3900.61(a), Public lands, and section 3900.61(b), Acquired 
lands. Under this final rule, in most cases leasing public lands does 
not require consent from the surface management agency. However, the 
BLM will consult with the surface management agency prior to leasing. 
Where acquired lands or National Forest System (NFS) lands are 
involved, the BLM will obtain consent from the surface management 
agency prior to leasing.
    Paragraph (c) provides procedures an applicant may pursue in 
challenging a decision issued by a particular agency outside of the 
Department relating to special stipulations or refusal of consent. A 
comment requested clarification of the timeframe for filing an appeal 
with the BLM when a counterpart appeal has been filed with the surface 
management agency. An appeal to the BLM must be timely filed, as 
presumably would an appeal to the surface management agency. When 
appropriate, though, the BLM will issue its decision after the surface 
management agency renders its decision. Paragraph (d) does not allow 
the BLM to issue a lease or license on NFS 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) provides 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 the 
surface 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. Paragraph (e) has been edited for clarity.
    Section 3900.62 addresses 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 mitigating potential impacts to a 
specific non-mineral resource value. 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 contains the 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 establishes consistent standards for 
land descriptions in applications submitted to the BLM.
    Sections 3901.20 and 3901.30 incorporate the provisions of Section 
21(a)(4) of the MLA, as amended by Section 369(j)(2) of the EP Act, 30 
U.S.C. 241(a)(4), that establish 50,000 acres as 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 does not count toward 
acreage limitations associated with other mineral leases such as 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 does not have the authority to revise 
the requirements in this section. We received a comment stating that 
section 3901.20 appears to be in conflict with section 3927.20. We 
disagree. Section 3901.20 concerns the amount of acreage an entity is 
allowed to hold, and section 3927.20 concerns how many acres can be in 
each lease. One comment expressed concern that conceivably one entity 
could hold as much as 300,000 acres in the three states of Colorado, 
Utah, and Wyoming, combined, which could result in speculation. It is 
true that one lessee could potentially hold as much as 300,000 acres, 
however, we believe that the competitive leasing process requiring FMV 
bonus payments up front and the diligent development milestones at 
section 3930.30 will deter speculation. We made no changes to subpart 
3901 as a result of this comment.
Subpart 3902--Qualification Requirements
    Sections under this subpart detail the various statutory 
requirements under Section 27 of the MLA relating to who can hold 
Federal oil shale leases and interests. These regulations 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 3472), and non-energy leasable 
minerals (43 CFR subpart 3502).
    Section 3902.10 enumerates 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. A commenter requested that BLM clarify section 3902.10(b) 
that a foreign citizen could hold a majority or controlling share in a 
domestic corporation. Proposed section 3902.10(b) does not place any 
limits regarding shareholdings; therefore, we have not revised the 
final rule as a result of this comment.
    Sections 3902.21 and 3902.22 explain the filing procedures for 
qualification documents, including when and where to file documents. 
Section 3902.21 also requires that all documentation submitted to the 
BLM as evidence of qualifications be current, accurate, and complete.
    Sections 3902.23 through 3902.29 detail the type of qualifications 
documentation that the BLM will 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).

[[Page 69419]]

    The requirements 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. We received one comment 
regarding section 3902.23(b), which stated that acreage holdings are 
attributed to an individual if that individual holds more than 10 
percent of the stock in a corporation, association, or partnership. The 
commenter thought that this was a low threshold. The 10 percent 
threshold is set in the Act for all leasable minerals (30 U.S.C. 
184(e)(1)). Therefore we made no change to final section 3902.23(b) as 
a result of this comment.
Subpart 3903--Fees, Rentals, and Royalties
    For payments of required rental and royalties, sections 3903.20 and 
3903.30 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 mirror the forms of payment accepted 
in the BLM's other mineral leasing regulations.
    Section 3903.40 incorporates the requirement of Section 369(j) of 
the EP Act that the annual rental rate for an oil shale lease is $2.00 
per acre. One comment stated that the EP Act must be revised so that 
the rental rate is coupled to resource thickness, overburden depth, and 
quality of oil, etc. Since the statute sets the rental rate, the BLM 
has no discretion to revise it. A change in the EP Act is beyond the 
scope of this rulemaking. Another comment we received brought to our 
attention that there is no due date for rental payments. We revised 
final section 3903.40 to reflect that rental payments are due on or 
before the lease anniversary date. The lease anniversary date is the 
anniversary of the effective date of the lease (see section 3927.40). 
We also revised section 3903.40(b) to make it clear that there is only 
one notice sent by BLM demanding payment of late rentals.
    Section 3903.51 addresses the minimal annual production requirement 
that applies to every lease. It also discusses payments in lieu of 
production beginning with the 10th lease year. The BLM determines the 
amount required for payment in lieu of annual production, but in no 
case will it be less than $4 per acre. Payments in lieu of production 
are not unique to this 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 is an adequate payment to the Federal Government to justify 
allowing the lessee to continue holding a lease absent production, but 
should not be so high as 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 POD;
    (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 commenters' suggestions. The 
suggestions to base minimum production on the approved POD and the 
specifics of the operation were incorporated into 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 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 establishes 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 on both the proposed rule and the ANPR, and we 
address those comments below. In the proposed rule we narrowed the 
range of options based on the ANPR comments and did not settle on a 
single royalty rate. Instead, we presented two royalty rate 
alternatives in the proposed rule (as outlined later in this section), 
and requested public comment on those specific alternatives. In 
addition, the rule considered a third alternative, a sliding scale 
royalty rate based on market prices for competing products, and we 
sought public comment on the appropriate parameters for the sliding 
scale royalty rate.
    The 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 the United 
States for 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;
    (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

[[Page 69420]]

    (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 
meets the EP Act's dual 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 
regulations administered by Department 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 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).
    All of these programs allow for royalty rate relief under certain 
circumstances (30 U.S.C. 241 and 209).
    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.
    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 countries known to be 
producing, or to have produced, oil shale using the same technologies 
as in the United States. 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 United States.
    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 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.
    We received a wide range of comments on the appropriate royalty 
rate as a result of the ANPR. 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 Alberta 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 Alberta tar sand model presents two challenges. First, 
because of the continual infusion of capital to acquire new equipment, 
the payout point is being reached only after many years of operation. 
Secondly, because of the complexity of determining when payout may 
occur, such a royalty scheme requires a more robust and costly 
administrative process to guard against manipulation; those costs would 
reduce the net return to the United States. Therefore, the BLM 
considered the investment payout scheme as inconsistent with the 
premise of ``a fair return'' to the United States 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 purpose of this rulemaking, these comments were not 
considered because they assume a use of royalty revenues not available 
under current law.

[[Page 69421]]

    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 
considered an initial 2 percent royalty to encourage production and a 
maximum 5 percent rate upon establishment of infrastructure. This 
method recognized the high costs involved in producing shale oil. 
However, we did not adopt this approach because of the difficulty 
involved in determining when necessary infrastructure is in place.
    In the proposed rule the BLM also considered an 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, several oil shale leases issued by the State of Utah 
are in the infancy stages of research and development. These leases 
were issued with an initial royalty rate of 5 percent for the first 5 
years after production begins. The royalty rate may increase by 1 
percent per year to 12\1/2\ percent.
    After examining the basis for setting rates, as suggested in the 
ANPR comments, the BLM determined that an initial 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.

Royalty Rate Alternatives Proposed for Further Consideration

    As noted previously, we did not propose a single royalty system. 
Based on the information the BLM reviewed, 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 presented different 
royalty rate alternatives in the proposed rule:
    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 sought comment on the appropriate parameters for a 
third option: A two or 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.
    Proposed 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 the 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 published estimated 
production cost for shale oil ranges from about $37.75-$65.21 a barrel. 
Current unpublished estimates are in the $75-$90 range. The production 
cost for conventional onshore crude is 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 
United States 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, adjusted to account for differences in 
production costs.
---------------------------------------------------------------------------

    \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 $19.50 per barrel.

[[Page 69422]]



----------------------------------------------------------------------------------------------------------------
                                                Estimated
                                                shale oil        Royalty calculation based on        Adjusted
                 Technology                    production     difference in production cost of a    royalty for
                                                costs per     barrel of conventional oil versus      shale oil
                                                 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% = 4.51%             4.5
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 
costs 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.
    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.
    Proposed Option 2. A 5 percent royalty on initial production, with 
12.5 percent thereafter.
    As stated in the proposed rule, this alternative would have 
provided 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 have required 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. The proposal established 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 after the issuance of the first 
oil shale commercial lease, the royalty rate would have been 5 percent 
of the amount or value of production on the first 30 million barrels of 
oil equivalent (BOE) 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 a barrel, this would amount 
to roughly $1.8 billion in production per lease at the lower 5% royalty 
rate, providing roughly a $135 million in savings to the lessee 
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 a 
barrel, the savings would be worth $270 million to the lessee, even 
though oil shale operations would be more profitable than at oil prices 
of $60 a barrel.
    Therefore, in the proposed rule we requested comment on whether 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 
also requested comments on the 12 year timeframe for reduced royalty.
    Proposed Option 3. Sliding scale royalty based on the market price 
of oil.
    Two comments on the ANPR 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 increa