[Federal Register Volume 73, Number 223 (Tuesday, November 18, 2008)]
[Rules and Regulations]
[Pages 69414-69487]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-27025]
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Part IV
Department of the Interior
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Bureau of Land Management
43 CFR Parts 3900, 3910, et al.
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Oil Shale Management--General; Final Rules
Federal Register / Vol. 73, No. 223 / Tuesday, November 18, 2008 /
Rules and Regulations
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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.
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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
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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.
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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, http://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. http://www.eia.doe.gov/neic/infosheets/crudeproduction.html and http://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 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 ANPR 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 the New York Mercantile Exchange
(NYMEX) futures (for instance, a 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 uses 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.''
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 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
[[Page 69423]]
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.
At the time of the proposed rule the BLM had not yet decided on the
specific parameters of a sliding scale royalty system, but considered 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
proposed rule explained that 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 and that 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.
In the proposed rule the BLM sought comment on the specific
parameters that could be applied to a sliding scale royalty system.
More specifically, the BLM asked for 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?
As explained in the proposed rule, 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
(proposed Option 1).
Other Royalty Issues
The BLM also received 5 ANPR 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 BLM
``must set the royalty rate and point of royalty determination with
reference to the economic cost of emissions that would be created from
developing, and then burning, the oil shale resource.'' After a careful
evaluation of these comments and consultation with the MMS, we have
concluded that the royalty would be assessed on all products of oil
shale that are sold from or transported off of the lease. This point of
royalty determination is similar to points of royalty determination for
other Interior Department minerals programs.
Currently, there is no oil shale industry and the oil shale
extractive technology is still in its rudimentary stages; as such,
commercial shale oil production does not exist anywhere in the world.
As research and development of oil shale technology progresses, the BLM
will have adequate time to reexamine and readjust royalty rates for oil
shale production, either up or down. In the proposed rule we asked for
specific comment on the time necessary to develop an oil shale
industry.
The proposed rule requested comments on what future royalty
valuation regulations need to contain. In particular, the Department
asked for comments on the potential types of oil shale products, the
most equitable and practical point and method to determine the value on
which to apply the royalty rate, and whether there are or should be
opportunities to determine value by market proxy or indices. The
Department solicited comments on alternative approaches to valuation
and royalty rates.
Several commenters suggested the royalty be based on the material
as it exists naturally in the land, and as it is removed from the land.
One commenter stated that royalties should be assessed at the first
point of sale. Another commenter recommended that the point of sale of
the synthetic crude should be the point of price determination.
Likewise, other commenters stated that the Department should determine
royalties after processing or manufacturing.
We received one comment that said that the BLM should charge
royalty on production that is used on the lease. The comment is based
upon one commenter's estimate that about \1/3\ of the product is likely
to be natural gas and that it would attempt to use natural gas to heat
the shale in subsequent development. One commenter stated that making
this royalty-free- short-changes the public.
One commenter stated that lease production used on or for the
benefit of the lease should not be subject to royalty. The commenter
urged that products of oil shale that are transported off-lease for use
in a facility in the general area to develop resources on the lease
should be viewed as use of that product on the lease.
The ``point of royalty measurement'' and the ``point of royalty
determination'' are two different concepts. The point of royalty
measurement concerns the volume upon which royalty is assessed and is
where the particular mineral product is measured for royalty purposes.
For oil and gas leases, royalty is due on ``all'' oil or gas removed or
sold from the leases except for oil or gas unavoidably lost as
determined by BLM or used on or for the benefit of the lease (see,
e.g.,
[[Page 69424]]
30 CFR part 202, subparts C and D). For coal, royalty is due on ``[all
coal (except coal unavoidably lost as determined by BLM under 43 CFR
part 3400) . * * * This includes coal used, sold, or otherwise disposed
of by the lessee on or off the lease'' (30 CFR 206.153(a)]. Generally,
the BLM determines where the product is measured for onshore minerals
and MMS for offshore minerals.
The point of royalty determination is generally the point at which
value is assessed and is not a specified fixed point under any existing
rules. Under the MLA, the Secretary is required to establish a royalty
rate on the amount or value of the production removed or sold from the
lease (30 U.S.C. 226(b)(1)(A))(see also the Outer Continental Shelf
Lands Act, 43 U.S.C. 1337(a)(1)(A)). The Department has consistently
interpreted this phrase to mean that royalties may be determined at a
point off of the lease (see, e.g., Amoco Production Co. v. Watson, 410
F.3d 722, 729 (D.C. Cir. 2005), cert. denied in relevant part sub nom.
BP America Co. v. Watson, 547 U.S. 1068 2006). The Department then
allows certain applicable transportation and processing deductions from
that off-lease royalty value, to arrive at a value for ``the production
removed or sold from the lease.''
With respect to the first comment that the royalty should be
assessed on the oil shale as it exists in situ, this comment seems to
suggest that the point of royalty determination be based on mined raw
shale. While the Department acknowledges the inherent differences
between an oil shale deposit and other deposits from which similar
products can be produced, the Department did not consider this
suggestion because there is no known value for raw oil shale, there
being no established market for raw oil shale. Similarly, the
Department is not in the position to definitively state that the point
of royalty determination should be on processed or manufactured
products. As many of the commenters acknowledged, there is not enough
information at this date to determine how products will be extracted,
nor is there enough information on the products that will result from
extraction or how those products will be marketed.
It would be premature to fix the point of royalty determination at
the lease or at the tailgate of a processing plant at this time.
Therefore, the Department is retaining the point of royalty
determination it proposed in this final rule as being on all products
that are sold from or transported off of the lease area.
With respect to royalty-free use of fuel on the lease, as discussed
above, for decades the Department's valuation rules have not assessed
royalties on fuel used for the benefit of the lease. However, until the
Department has more information on the extraction processes involved,
it is premature to determine whether the Department will assess royalty
on fuel used on the lease.
One commenter stated that if net royalty is being considered, the
definition of royalty basis should be revenue from sales of hydrocarbon
products, less transportation costs, all direct operating costs (mining
and extraction) and administration costs, together with a deduction for
the capital costs of assets employed based on Internal Revenue Service
amortization methods.
One commenter recommended that the Department define the term
``royalty,'' indicate whether royalty is based on net or gross revenue,
and specify the components thereof.
One commenter stated that MMS's valuation of the products from oil
shale will be significantly less than the market price of the final
refined products because MMS will allow manufacturing/processing
allowances.
One commenter stated that kerogen is worthless unless processed.
The monetary value of kerogen is tied to the net proceeds between the
market price of products and production costs and the technical and
economic effectiveness of the process. The commenter also stated that a
royalty and bonus process should be replaced with a competitive annual
payment from the lessee to the Federal Government based on the value of
the kerogen in the ground and net proceeds (time varying market price
of products minus time varying production cost). One commenter believes
that royalty should be assessed on the first sale.
Several commenters stated that MMS should propose valuation
regulations concurrently with these BLM regulations to give potential
oil shale lessees certainty, which will in turn ``encourage
development.''
This final rule establishes a royalty rate for Federal oil shale
leases; however, the Department is not proposing corresponding MMS
valuation regulations at this time. Because the oil shale industry is
still in the research and development phase, it would be speculative to
predict whether the industry as it matures will predominantly sell from
the leases it mines solid oil shale, shale oil, synthetic petroleum,
shale gas, natural gas, or products in several different forms or
stages of processing. It is also difficult to predict whether or when
multi-buyer/multi-seller markets will develop that would provide FMV
pricing for products of oil shale.
The comment that kerogen is worthless unless processed and, thus
royalty should be based on a market price minus production costs, asks
the Federal Government to share in production costs. Thus, and many of
the comments regarding valuation and the point of royalty determination
discussed above, suggest that MMS should abandon the marketable
condition rule and share in production costs with the lessee. While it
is premature to address this comment directly in this rule, it is
important to note that the Department generally does not share in the
costs of production or the costs of placing production in marketable
condition for minerals produced from Federal leases.
The MMS will promulgate royalty valuation regulations before oil
shale leases are required to begin paying production royalties under
this rule. As stated in the proposed rule, to the extent possible, the
MMS will ensure that any oil shale valuation regulation is consistent
with other valuation regulations and will incorporate principles of
simplicity, early certainty, and reduced administrative costs in the
oil shale valuation regulations it promulgates. In addition, the MMS
will consider the comments submitted to the BLM proposed rulemaking
when formulating oil shale valuation regulations.
For example, the MMS could promulgate regulations similar to the
current Federal oil valuation regulation to value crude oil produced
from oil shale. Under such regulation, the value of oil sold at arm's-
length would be based on gross proceeds less allowable costs of
transporting oil to the point of sale. The value of oil not sold at
arm's-length would be based on a market index price or the affiliate's
arm's-length resale price. In both arm's-length and non-arm's-length
situations, the regulations provide for adjustments for location,
quality, and transportation allowances. Further, lessees also can
petition for alternate valuation agreements that are situation specific
when regulatory provisions do not apply. The regulations promulgated
here, however, do not address those valuation issues.
The Federal Government does not typically require payment of
royalties on potentially valuable minerals or inorganic matter that are
not sold or transported off the lease for commercial purposes. Those
materials would be considered waste, and would be subject to management
and reclamation
[[Page 69425]]
requirements as provided in the lease or in an approved POD.
One commenter suggested that non-fuel products should pay a 12.5%
royalty rate. Another commenter suggested that different minerals
produced may require different royalties. Several commenters
recommended that there be no royalties on spent oil shale. One
commenter stated that royalties should not be assessed on by-products
such as sulfur removed from the gas stream to meet air quality
requirements and sold, whether at a loss or a profit. The commenter
said that items transported off of the lease for recycling or disposal
should not be considered products or by-products. Consistent with
current Department policy, by-products that are not sold or bartered,
including produced water, CO2, ammonia, etc., are not
royalty-bearing. The BLM and the lessee must take measures to minimize
damage or loss of resource by-products and other resources on the
lease.
Finally, one commenter stated that royalty should only apply to all
fuel products and that by-products should be royalty free. The final
rule establishes a royalty for all products that are sold or
transported off the lease. The royalty rate for by-products will be the
same, except for those commodities whose rates are already established
under the mineral leasing laws or regulations. Title 30 U.S.C. 241(4),
states that ``For the privilege of mining, extracting, and disposing of
the oil and other minerals covered by the lease under this section the
lessee shall pay to the United States such royalty. * * *'' The
Secretary has the discretion to reduce the royalty rate for all
products produced from the lease to encourage use or the disposal of a
product stream. The BLM will apply the same royalty rate for all oil
shale products sold or transported off of the lease area.
In the economic analysis for this rule, the BLM analyzed the
royalty implications of a range of royalty rates. Specifically, the BLM
conducted a simulation-based analysis to estimate the revenue, profit,
and royalty implication of a production scenario \3\ using three
discount rates (7 percent, 3 percent, and 20 percent), three world
crude oil price projections (Energy Information Administration's (EIA)
2007 reference, high, and low price projections \4\), and six different
royalty rates (1 percent, 3 percent, 5 percent, 7 percent, 9 percent,
and 12.5 percent). The likelihood of a company, in the face of numerous
technological challenges, having the incentive to develop Federal oil
shale reserves and experiencing economic success will depend on a
number of factors. However, because the simulated scenario analysis is
based on a given production scenario and set production costs, the
analysis did not assist in determining the project(s) economic
viability due to the royalty rate applied. The analysis did, however,
clearly identify world oil prices as a critical variable determining a
project's economic viability. Under the EIA's low price projections,
which project oil prices to be below $36 per barrel through 2030, all
operations are assumed to be uneconomic based on the set production
costs used in the analysis of the rule.
---------------------------------------------------------------------------
\3\ America's Strategic Unconventional Fuels Resources, Volume
III Resource and Technology Profiles, Task Force on Strategic
Unconventional Fuels, September 2007, page III-17, Table III-4.
Potential Oil Shale Development Schedule--Base Case, (http://www.unconventionalfuels.org).
\4\ Department of Energy, Energy Information Administration,
Annual Energy Outlook 2007, Report : DOE/EIA-0383(2007),
February 2007.
---------------------------------------------------------------------------
Public Comments on the Proposed Royalty Rates
The BLM received many royalty-related comments. Few provided
substantial data or rationale for justifying a particular royalty rate.
Many commenters suggested variable-scale or sliding-scale royalty
schemes albeit in various forms (1-3%, 1-5%, 0-6%, 2-12.5%, 5-16.67%).
The industry submitted the majority of the comments that stated that
the flat 5% royalty rate was too high and that it provided no incentive
to encourage oil shale development.
One commenter provided information on a new oil sands royalty
framework proposed in the Alberta Legislative Assembly in the fall of
2008. Under the new framework, the ``base rate is 1% of gross revenue,
and increases for every dollar that oil is priced above $55 a barrel,
to a maximum of 9% when oil is $120 or higher.'' The commenter also
stated ``there are currently 89 active oil sands projects in the
province, of which 39 are in post-payout and 50 in pre-payout.'' In the
proposed rule preamble, the BLM incorrectly stated that ``operators
have never reached the payout point due to the continued capital
expenditures in new equipment. The same commenter also requested the
BLM refer to oil sands operators as ``Alberta operators'' rather than
``Canadian operators.'' We appreciate these corrections.
Other comments on the proposed rule's royalty alternatives are
summarized as follows:
(1) Several commenters suggested that the royalty rate for oil
shale should start at 1%;
(2) A few commenters agreed with a flat 5% royalty rate;
(3) A few commenters suggested a 3% royalty rate;
(4) Some commenters suggested an 8% royalty rate;
(5) A few commenters agreed with a royalty scheme in which the rate
starts at 5% and increases to 12.5%;
(6) A few commenters agreed with a sliding scale royalty rate, but
proposed varying modifications;
(7) Some commenters suggested a 1% royalty rate, with several
commenters suggesting a 1% rate for the first 10 years of production
and an increase to 3% thereafter;
(8) A few commenters suggested a 1% royalty rate to be increased to
5%;
(9) A few commenters suggested a flat 12.5% royalty rate;
(10) A small number of commenters suggested a sliding scale scheme
of 2-12.5%; 0-12.5%; and
(11) The majority of the commenters did not suggest a specific
royalty rate.
The BLM addresses these comments in 4 groups:
(1) Flat royalty rate of less than 5%;
(2) Flat royalty rate equal to or greater than 5%;
(3) Sliding scale royalty rate of 1-5%; and
(4) Sliding scale royalty rate of 0-12.5%.
Flat Royalty Rate Less Than 5%
The commenters who advocated a flat royalty rate of less than 5%
stated that the proposed royalty rates do not take into account the
differences between the economics for oil shale production versus crude
oil production. They stated that no adjustment was made for the
difference in the amount of capital investment required between
conventional oil and oil shale operations. They suggested that the
production royalty rate should be reduced to 3% until the first plant
on each lease is fully amortized in a minimum timeframe of 10 years.
One commenter stated that ``the 5% fixed royalty rate is too high,''
and that ``U.S. oil shale resources have no value if they are
uneconomic to produce.'' The BLM considered the comments and decided
not to adopt the suggested 3% flat royalty rate or any rate below 5%.
The BLM did not adopt the lower rates because the BLM's analysis of
comparable production costs in the proposed rule indicated that the
proposed rate of 5% better reflects the differences between the
economics for oil shale production versus crude oil
[[Page 69426]]
production. The commenters who advocated the suggested royalty rate of
3% did not provide sufficient data to support their analysis.
One comment offered a new royalty rate scheme as an alternative if
the BLM disapproves their suggested royalty rate of 1-3%. The commenter
suggested that ``royalty should reflect the fact that the extracted oil
shale has no economic value of its own. It contains kerogen, which must
be processed to produce a low-quality shale oil.'' The commenter also
suggested that royalty should be based on a mathematical computation
which would incorporate FA, the NYMEX, the price of conventional crude
oil, and a royalty rate of 3%. The commenter suggested that the royalty
payment for a ton of (underground) mined and processed oil shale should
be assessed according to the following formula: (FA/42) x (Current
NYMEX/$100/BBL) of the oil shale that is produced for conversion into
shale oil multiplied by a selected index reflecting the value of the
shale oil. In essence the formula converts the FA into barrels (42
gallons per barrel), multiplies FA by the ratio of NYMEX and a fixed
bench mark price of $100 per barrel of conventional crude oil.
After careful consideration, the BLM did not adopt the comment
because the suggested formula assigns too little a value to oil shale
products, lacks the potential to yield a fair return to the taxpayers,
and would be very complex and expensive for MMS to administer.
A commenter also stated that royalty ``should not be so high as to
stifle the emergence of a new domestic energy industry.'' The BLM
shares this concern and took steps to ensure that the initial royalty
rate for oil shale production will encourage oil shale development
consistent with the requirements of EP Act. The commenter went on to
state that ``increasing production costs, and massive R, D & D costs,
and many taxes, all argue for a royalty rate well below 5%,'' and
therefore, the royalty regime should be simple, transparent, and easy
to administer. The final rule establishes a flat, easy to administer 5
percent royalty rate for the first 5 years of commercial production and
a transparent, simple to understand escalating rate of 1 percent after
year 5 until it reaches a level comparable to the royalty rate on
conventional crude oil (12\1/2\%). This royalty system should provide
some royalty relief during the first years of capital intensive
production activities.
Flat Royalty Rate Equal to or Greater Than 5%
The commenters who advocated a flat royalty rate equal to or
greater than 5% stated that since the processes that will be used to
develop oil shale are similar to the processes used to develop other
solid minerals, the royalty rate for oil shale should be the same. The
commenters who suggested a flat royalty rate greater than 5% asserted
that the State of Utah has a royalty rate of 8% for asphaltic sands,
uranium, and coal. Other commenters stated that ``if royalty will be
set, it should be 12.5%'' because the ``current royalty rate for
conventional oil and gas is 12.5%.''
The BLM did not adopt the suggestions of this group of commenters
who advocated a flat royalty rate greater than 5%. First, an 8% royalty
rate is not an accurate depiction of the royalty structure in Utah. The
royalty rate for oil shale development in Utah begins at 5%, may
increase annually after the first five years, and ultimately reaches
12\1/2\% at some point. The practical implications of the Utah royalty
regime is also undetermined since, no production has occurred on any
Utah State lease. Second, the BLM is concerned that an initial 12\1/2\%
royalty rate may be a disincentive to oil shale development because it
will discourage the much-needed capital investment in the industry.
The BLM believes that the Utah royalty system is worthy of
consideration and provides a comparable domestic royalty rate for oil
shale development. If oil shale development succeeds on State lands in
Utah, a similar Federal royalty system would appear to meet EP Act's
objectives of encouraging development and providing a fair return to
taxpayers. In the final rule, the BLM has chosen to adopt a royalty
rate similar to Utah's by establishing an initial royalty rate of 5%
during the first five years of production. Following five years of
successful production, the rate will rise yearly by 1 percent until it
reaches a level comparable to the royalty rate on onshore conventional
crude oil. This will ensure that over the long-term the taxpayers are
guaranteed a fair return, as required by EP Act, should oil shale
development be economically viable.
Sliding Scale Royalty Rate of 1-5%
The commenters who advocated a sliding scale royalty rate of 1-5%
stated that a 12\1/2\% royalty rate is too high. These commenters
suggested that the oil shale industry is fundamentally a mineral
extraction industry and should be viewed as such when establishing
royalties. These commenters stated that the projects, related
development, and operating costs associated with oil shale development
are typical of mineral extraction industries (i.e., trona and potash).
The commenters believe that due to the similarity of oil shale to other
mineral extraction industries, the BLM should adopt a royalty rate of
1% of the producer's net return at the point of sale of the synthetic
crude oil shale for the first 10 years of production. After 10 years,
they suggested re-evaluating ``the 1% rate to see if 3% net royalty
would be appropriate with a transition step-up period of a 1% increase
every 5 years to impose the 3% net rate after a 10 year transition
period.'' One commenter stated that if BLM adopts option 2 a 5% percent
royalty on initial production with 12.5% thereafter that ``there should
be a floor at which royalties and annual minimum royalties are
automatically suspended if WTI falls below $80'' a barrel. The BLM
reviewed the above suggestions and decided not to adopt them because
while they seek to encourage development, they are difficult as well as
costly to administer. Based on the BLM's analysis of comparable Btu
values and production costs, we also do not believe rates lower than 5
percent represent a fair return to the United States. The BLM agrees
with the commenters that a 12.5% royalty rate is too high if adopted as
an initial rate. Also, the BLM did not adopt the suggestion that asks
for a royalty rate of 1% on the producer's net return at the point of
sale of the synthetic crude oil shale for the first 10 years of
production ``due to the similarity of oil shale to other mineral
extraction industries.'' First, experience shows that there is no
similarity between oil shale extraction and the other extractive
industries (trona and potash) cited by the commenter. Second, the
estimated resource value of oil shale far exceeds the combined values
of trona and potash. Given the economic potential of oil shale, it
would be difficult to ensure a fair return to taxpayers if the royalty
rate is set at 1% of net revenue.
Another commenter stated that the ``5 % royalty rate for option 1
and the 5% and 12.5% rates for option 2 are too high for a frontier
resource.'' The same commenter further stated that unlike coal or oil
and gas, the government is providing access to a solid ore, and that
the investor is responsible for adding value by recovering and
converting the kerogen in the ore to oil. The commenter suggested
setting a royalty rate of 1% for the first 6 years, and 5% thereafter
with assurance from the government that the higher royalty rate
[[Page 69427]]
of 5% would be implemented at a later date. The commenter added that
``royalties should be suspended if the NYMEX crude oil prices fall
below, say $60.''
One commenter suggested that a better alternative would be a 1%
royalty rate for the first 10 years, followed by 3% royalty thereafter,
and concluded that ``Alberta established a similar approach and has
been successful.'' This commenter stated that ``if royalties are too
high during the development phase, the startup costs will be too
prohibitive and the resources won't be developed.''
The BLM agrees that the oil shale industry is subject to high
start-up costs and that the resources would not be developed without an
economically viable technology. This technology could not be developed
if costs become prohibitive. After careful consideration, the BLM does
not agree with the idea of a starting royalty at 1% rate. The BLM's
comparison of Btu values and production costs show a 1 percent rate to
be too low. States and local governments share in Federal royalties and
may view the lower rate (1% royalty rate) as not providing the revenue
necessary to cover related infrastructure concerns and local community
impact concerns. Furthermore, a royalty rate based on a sliding scale
tied to NYMEX would be subject to frequent fluctuations thereby making
it cumbersome and difficult for the MMS to administer.
Sliding Scale Royalty Rate of 0-16.67%
Some commenters advocated sliding scale royalty schemes ranging
from 0% to 16.67%. One commenter specifically suggested that ``reduced
royalty rates should be conditioned on prices similar to OCS deepwater
royalty incentives,'' and stated that ``there is no basis for a 12-year
timeframe based on a reduced royalty rate that is not price
sensitive.'' Instead the commenter suggested that the royalty rate
should be tied directly to NYMEX, and there should be no fixed
timeframe. The same commenter gave an example that if NYMEX is below
$60 a barrel the rate would be 5%, but when it exceeds $60 a barrel, it
would be 12.5%. In the proposed rule, the suggestion for a reduced
royalty rate for production that occurs within 12 years of the issuance
of the first oil shale lease was meant to encourage speedy development,
while providing some royalty relief during the costly up front years of
development. However, the BLM did not adopt this provision in the final
rule. The BLM also did not adopt the suggestion to tie the royalty to
NYMEX prices because to do so would make royalty rates impracticable as
well as cumbersome and costly for the BLM and MMS to administer. On the
other hand, a 16.67% royalty rate will not encourage development, and
without development, there will be no fair return to the taxpayers. To
address comments that support a 16.67 percent royalty rate comparable
to offshore rates, available information shows that shale oil
production costs are much higher than costs of producing conventional
crude oil. Yet, the maximum royalty rate for onshore oil and gas
production is 12.5%. Given the cost differential, it would be a
disincentive to production to set a higher royalty rate (16.67%) for a
product that is costlier to produce.
Another commenter suggested another alternative that would set the
initial royalty rate at 2% or 2.5%, which would ``increase to 12.5%
once 30 million barrels of oil equivalent have been produced.'' Then,
the commenter concluded by stating ``do not adopt a sliding scale since
there are too many unknowns that could thwart development.'' The BLM
did not adopt this proposal because the initial 2% royalty rate is too
low to ensure a fair return considering the available information on
comparable resource values and production costs. The BLM has no
information to determine whether the production of 30 million barrels
of oil equivalent is relevant when establishing a higher rate. The
final rule provides for an increasing royalty of 1 percent per year
that is based on time, rather than on production.
Another commenter stated that ``it is difficult to comment with any
confidence on the merits of various royalty rates without also knowing
the parameters the lessor will use to value production from the lease,
particularly for a mineral resource that have [sic] never been
commercially produced and sold.'' The commenter also stated that
royalty ``should not be so high as to stifle the emergence of a new
domestic energy industry.'' As stated previously, the MMS will address
valuation issues in a future rulemaking, but will apply royalty to the
amount or value of production. The BLM agrees with the commenter that
the royalty rate should not be so high as to stifle the emergence of a
new industry. This comment is consistent with a requirement of the EP
Act that royalty be set in a manner that encourages development.
One comment stated that Option 2 (base of 12.5% with a reduction to
5% for the first million barrels of oil equivalent of any lease that
begins production within 12 years) is ill conceived. This commenter
suggested the following two sliding scale options based on the
following set of assumptions:
Commenter's price-trigger option: First 5 years, rate is 0% with no
adjustment based on price thresholds. After the first 5 years, the base
rate is 1%; provided that the average daily closing NYMEX price for the
calendar year exceeds $150 a barrel. The rate would increase to 3%;
provided further that the average daily NYMEX closing price for the
year exceeds $200 a barrel, the rate for production for that calendar
year would be 5%. All prices would be indexed to 2008 levels.
Commenter's production-trigger option: A 1% rate for the first 60
million BOE operating within the first 20 years of the lease; a 3% rate
for the following 60 million BOE within the first 20 years of the
lease; and a 5% rate for any volume of production above the 120 million
BOE within the first 20 years of the lease. These production triggers
would be subject to the same price thresholds outlined in the price
trigger option above. Therefore, if crude prices exceed the prescribed
levels, the rate would increase by 2 or 4% respectively.
The commenter's options above are based on the assumptions that:
(1) MMS valuation of the products from oil shale will be
significantly less than the market price of the final refined products
because MMS will account for manufacturing/processing allowances;
(2) Lease production used on or for the benefit of the lease will
not be subject to royalty; and
(3) Royalties should not be assessed on by-products such as sulfur
removed from the gas stream to meet air quality requirements and sold
whether at a loss or a profit. Items transported off of the lease for
recycling or disposal would not be considered products or by-products.
These, including produced water, CO2, ammonia, etc., would
not be royalty-bearing.
The BLM considered and opted not to use this sliding scale option
because the initial rates are too low (less than 5%) and such royalty
schemes are not simple, transparent, or particularly easy to
administer. The BLM also found no justification or rationale to support
the price or production trigger thresholds. In addition, a zero percent
royalty for the first 5 years of production would not provide a fair
return to the United States.
Other General Comments
Commenters stated that it was important that royalty rates be
consistent across ownerships in order to prevent oil shale development
from
[[Page 69428]]
concentrating on land with a lesser royalty rate. We agree with this
comment. However, it must be recognized that, other than the State of
Utah, there are no domestic royalty ``rates'' that apply to oil shale
production. They also suggested that the BLM should adjust the royalty
rate more frequently than the 20 year period in the proposed rule. The
BLM cannot adjust lease royalty rates more frequently because the MLA
authorizes the re-adjustment of royalty rates only after the initial 20
year term of a lease and every 20 years thereafter. The BLM can,
however, change the regulatory royalty rate at any time should
information become available that suggest the Federal rate is not
comparable to rates on private or state lands. The new rates would
apply to any lease issued or readjusted thereafter.
Another commenter stated that the BLM based the rates in the rule
on estimated production costs, but provided no support for the cost
estimates that it used in the calculation. The production costs used in
the proposed rule's calculations were obtained from the Strategic
Unconventional Fuels Report (America's Strategic Unconventional Fuels,
Volume III) prepared for Congress and the President. The Task Force
that published those production costs was established by Congress under
Section 369 of the EP Act.
The same commenter suggested that the BLM defer the royalty rate
determination until it has reliable information on the costs, recovery
rate of technologies to be used on a lease, and the value of the
product produced. The BLM disagrees with this suggestion because
establishing a royalty rate early in the life of the oil shale industry
provides the oil shale industry with the level of certainty necessary
to obtain the capital investment required for oil shale development.
Equally significant, delaying the establishment of a royalty regime
until ``reliable information on the costs, recovery rate of
technologies to be used on a lease, and the value of the product
produced'' would not attract investment for oil shale development. The
royalty rate is also a part of fair market value received by the United
States and could affect bonus bids offered for leases. These comments
appear to be inconsistent with Section 369 of the EP Act, which
requires the Secretary to establish royalty rates in a manner that
encourages development and ensures a fair return to the United States.
Other comments were placed in the form of questions or general
statements. Some of these questions/statements include:
(1) Why is ``complexity'' inconsistent with ``fair return?'';
(2) ``Any process that heats with electricity should be banned;''
and
(3) ``There's one way to find out if 12.5% is too high. Put parcels
up for bid based on 12.5% royalty and see if there are any takers.''
The BLM examined the ``complexity'' issue and disagrees because, in
practice, ``complexity'' can be inconsistent with ``fair return.'' The
more complex the system, the more expensive and inefficient it is to
administer and audit. A simple royalty regime promotes certainty and
reduces the administrative costs (audit, compliance and reporting
costs) better than a complex royalty scheme. The BLM did not agree with
the comment which suggested banning any process that uses electricity
to heat/produce oil shale, because the commenter failed to provide any
scientific data or rationale to support their idea. All resource
production requires energy. The BLM also believes that putting oil
shale ``up for bid based on 12.5% royalty and see if there are any
takers'' is an unnecessary expense or gamble. Such an option would not
provide the certainty that industry seeks and could discourage the
investment that is needed now to potentially make oil shale
economically competitive in the future.
One commenter asserted ``specifically, the MLA says that the
royalty is to be ``not less than 12.5% in amount or value of the
production removed or sold from the lease.'' The BLM examined and
disagrees with the assertion because the MLA does not establish a
royalty rate for oil shale nor require that oil shale royalty be set at
par with that of oil and gas. Instead, the EP Act directs the Secretary
to establish a royalty rate for oil shale for the dual purposes of
encouraging production and ensuring fair return to the United States.
The BLM agrees that there is merit in eventually reaching royalty rate
parity with that of onshore oil and gas, as reflected in the royalty
system chosen for these final regulations. As noted elsewhere in this
preamble, the BLM believes that an initial lower royalty rate on oil
shale would be beneficial in spurring investment in developing the
resource, consistent with the EP Act's direction.
Another commenter suggested that no Federal royalty should be
payable on spent shale, even if revenues are generated from the spent
shale. This will encourage development of economic uses of spent shale
and minimize onsite disposal costs. The BLM examined this comment and
affirms its position that royalty is payable on products and by-
products of oil shale produced and sold/removed from the lease. So, if
in the future spent shale becomes a valuable product, the appropriate
royalty will apply at that time.
Oil Shale Production Royalties
After careful consideration of the public comments discussed in
this rule, the BLM determined that a royalty system similar to that of
the State of Utah is best suited to meet the dual requirements of the
EP Act to encourage production and to ensure a fair return to the
United States. In the final rule, the production royalty for oil shale
will have an initial rate of 5% through the first five years of
commercial production and increase by 1% annually beginning in the
sixth year of production until a maximum rate of 12.5% is reached in
the 13th year. By establishing an initial royalty rate of 5% during the
first five years of production, we are encouraging development as
mandated by EP Act. Based on our analysis, this initial rate (1)
reflects the production cost disparity between shale oil and crude oil
production, (2) addresses the high start up costs associated with new
infrastructure required for developing, refining, and transporting oil
shale products, and (3) could promote higher bonus bids to defray
socioeconomic impacts to states and counties. Following five years of
successful production, the rate will eventually rise to a level
comparable to the royalty rate on conventional crude oil. This will
help to ensure that over the term of the lease the United States is
guaranteed a fair return, as required by EP Act, should oil shale
development be economically successful. A more certain royalty scheme,
independent of the NYMEX indices, will lower administrative costs
(lower audit, compliance and reporting cost) relative to a variable
royalty rate tied to NYMEX.
In summary, a low initial rate should encourage development and
production during the early years when costs are high. As the
technology becomes more efficient and cost effective the royalty rates
will increase. If the costs to produce oil shale do not decrease, and
operations become uneconomic, or marginally economic, royalty rate
relief is available under section 3903.54.
Whenever the Secretary determines it necessary to promote
development or finds that the lease cannot be successfully operated
under its terms, the Secretary may waive, suspend, or reduce the
rental, or reduce the royalty, but not advance royalty, on an entire
[[Page 69429]]
leasehold, or on any deposit, tract, or portion thereof, except that in
no case can the royalty rate be reduced to zero percent. A lessee must
apply for any of these benefits. As mentioned previously, the royalty
rates can also be changed by regulation should future information
indicate the need. Leases issued or readjusted after a regulatory
change in the rate will be subject to the new rate. The MLA provides
for readjustment of the royalty rate at the end of the 20th lease year
and each 20 year period thereafter (see 30 U.S.C. 241).
Section 3903.53 requires the filing of documentation of all
overriding royalties associated with a lease and requires that the
filing must occur within 90 days after the date of execution of the
assignment. This section is similar to that of the BLM's other mineral
leasing programs. A comment on the proposed rule pointed out that we do
not define ``overriding royalties.'' Section 3903.53 of the final rule
has been revised to clarify that an overriding royalty is a payment out
of production to an entity other than the United States.
Section 3903.54 contains the requirements for filing an application
for waiver, suspension, or reduction of rental or payments in lieu of
production, or a reduction in royalty, or waiver of royalty in the
first 5 years of the lease. As with the BLM's other mineral leasing
programs, this section is intended to encourage the maximum ultimate
recovery of the mineral(s) under lease. The proposed rule's preamble
erroneously mentioned a cost recovery fee that was not in the
regulation text for the proposed rule. Therefore, in the final rule
there is no cost recovery fee for this section. One comment indicated
that there is some confusion regarding the distinction between a
suspension or reduction in rental or royalty and a waiver of royalty.
The authority for a suspension, waiver, or reduction of rental or a
reduction in royalty is 30 U.S.C. 209 and applies to numerous minerals
under the MLA including, but not limited to, coal, oil, gas, and oil
shale. The authority for a waiver of the rental and royalty for the
first 5 years under an oil shale lease is 30 U.S.C. 241 and only
applies to oil shale.
Section 3903.60 provides that late payments or underpayment charges
are assessed under MMS regulations at 30 CFR 218.202.
Subpart 3904--Bonds and Trust Funds
Sections in this subpart address the requirements associated with
bonding and trust funds, including the:
(1) Types of bonds the BLM requires and when bonds would be
required (section 3904.10);
(2) When and where bonds would be filed (sections 3904.11 and
3904.12);
(3) Acceptable types of bonds (section 3904.13);
(4) Individual lease, exploration license, and reclamation bonds
(section 3904.14);
(5) Amount of bond coverage (section 3904.15);
(6) Default (section 3904.20); and
(7) Long-term water treatment trust funds (section 3904.40).
Since all of the BLM's mineral leasing programs require bonds, the
requirements in subpart 3904 are similar to the regulatory provisions
in the BLM's other mineral leasing programs. The bonding requirements
in this rule are similar to the bonding requirements under the BLM's
mining law program in that both programs require that bonds cover the
full cost of reclamation and allow for the use of long-term trust funds
as a mechanism to address potential long-term water issues.
Bonding ensures performance at a cost up to the bond amount in the
event of default by a lessee or licensee. This subpart requires two
types of bonds; a lease or exploration license bond and a reclamation
bond. This subpart also explains that reclamation bonds will be
required to be in an amount sufficient to cover the entire cost of
reclamation of the disturbed areas as if they were to be performed by a
contracted third party.
Section 3904.10 provides that prior to lease or exploration license
issuance, the BLM requires a lease or exploration license bond for each
lease or exploration license to cover all liabilities on a lease,
except reclamation, and all liabilities on a license. One commenter
requested an explanation of what liabilities the lease bond covers. A
lease bond covers the lessee's compliance with the terms and conditions
of the lease and will be calculated to cover payments for rental,
minimum or production royalty, outstanding bonus bid payments, and
assessments. The bond also could be used to cover any other payments
required of the lessee that are associated with noncompliance with the
terms and conditions of the lease. The bond will be executed by the
lessee and will cover all record title owners, operating rights owners,
operators, and any person who conducts operations on or is responsible
for making payments under a lease or license. This section also
requires the lessee or operator to file a reclamation bond to cover all
costs the BLM estimates necessary to cover reclamation on a lease.
Section 3904.11 requires the prospective licensee, lessee, or
operator to file a lease bond prior to issuance of a lease, file a
reclamation bond prior to approval of a POD, and file an exploration
bond prior to exploration license issuance. This section is similar to
other BLM bonding regulations as it would require the filing of a bond
before liabilities may accrue. We received a comment requesting a
revision to section 3904.11 clarifying when a lease bond is filed.
Section 3925.10 of the rule provides that the successful bidder will
submit a bond as a condition of lease issuance. Therefore, no change is
made to section 3904.11 in the final rule. A commenter requested that
the regulation provide that bonds be ``a condition of'' issuance of
licenses or leases, or of approval of PODs. We did not change the
section because proof of bond coverage is a pre-condition to issuance
or approval of those documents. We revised this section in the final
rule to make it clear that submission of a bond is a condition
precedent of the approvals mentioned in the section.
Section 3904.12 requires that a copy of the bond with original
signatures be filed in the proper BLM office, and section 3904.13
describes the different types of bonds that the BLM will accept.
Section 3904.13 addresses the types of personal and surety bonds
the BLM will accept. Personal bonds are limited to pledges of cash,
cashier's checks, certified checks, or U.S. Treasury bonds. The BLM
state offices have available for public review a Treasury Department
list of qualified sureties for bonds. We received several comments
requesting that the types of personal bonds that will be accepted
should be expanded. We believe that the number and types of bonds
available to lessees and licensees are varied enough to provide
flexibility and accessibility to all holders.
Section 3904.14 provides that the BLM will establish bond amounts
on a case-by-case basis, and sets the minimum lease bond amount at
$25,000. One comment expressed concern that $25,000 is an inadequate
minimum bond amount. The actual bond amount for a lease, as opposed to
the minimum bond amount, will be calculated each year to cover the
rental payments, minimum royalty, outstanding bonus payments,
assessments, if applicable, and other payments that are due for the
lease. The minimum lease bond amount, established by the regulations,
however, is greater than that required in other BLM mineral leasing
programs. The BLM chose this higher minimum bond amount to insure
coverage of
[[Page 69430]]
unpredictable lease liabilities due to the unknown nature of future oil
shale development and the likelihood of large, outstanding bonus bid
payments. In addition to the lease bond, the reclamation bond amount
and the bond amount for a license will be calculated to cover actual
reclamation costs.
Reclamation and exploration bond amounts will be established to
cover the costs of reclamation as if it were to be performed by a
contracted third party. Past oil shale operations have required
extensive reclamation, and this has demonstrated the need to have a
reclamation bond that covers the full cost of reclamation. By requiring
that the bond equal the estimated costs of having a third party perform
the reclamation, the BLM anticipates that the cost of reclamation will
be covered.
This section also provides that the BLM may enter into agreements
with states to accept a state-approved reclamation bond to satisfy the
BLM's reclamation requirements and protect the BLM, to the extent the
bond is adequate to cover all the operator's liabilities on Federal,
state, and private lands. This avoids duplicate procedures and the
inconvenience and cost of filing separate bonds with both the state and
the BLM. Such agreements were recommended by state representatives at
the BLM listening sessions and are also addressed in regulatory
provisions of other BLM mineral leasing programs. We received a comment
suggesting that this section should provide for the establishment of an
escrow account or trust fund as an option to replace bonding as a
method of insuring reclamation. With the exception of special
circumstances, as outlined in section 3904.40 of this rule, the BLM
believes that requiring escrow accounts or trust funds would impose
unnecessary costs on lessees as well as additional administrative costs
to the BLM while offering no advantage to ensure that funds will be
available in case the lessee or licensee cannot meet reclamation
obligations. Although these rules will not specifically provide for
escrow accounts or trust funds, as suggested by the commenter, state
approved reclamation rules may allow for them. In these cases, and
where the BLM has an agreement with the state, the BLM will indirectly
accept escrow accounts and trust funds, but the state will be
responsible for managing them.
Section 3904.15 explains that the BLM may increase or decrease the
bond amount if it determines that a change in coverage is warranted to
cover the costs and obligations of complying with the requirements of
the lease or license and these regulations. This section also explains
that the BLM will not decrease the bond amount below the minimum
established in section 3904.14(a). This section requires the lessee or
operator to submit a revised estimate of the reclamation costs to the
BLM every three years after reclamation bond approval. If the current
bond does not cover the revised estimate of the reclamation costs, the
lessee or operator would be required to increase the reclamation bond
amount to meet or exceed the revised cost estimate. This section is
consistent with the bonding regulations that currently exist for other
BLM minerals programs. A commenter requested a revision to section
3904.15 to require the BLM to audit cost estimates provided by lessees
or operators under this section. In the final rule we revised section
3904.15 to state that the BLM will verify the cost estimates provided
by the lessee or operator. A commenter proposed changes to provide for
incremental bonding. We did not revise the rule because this section
allows the BLM to increase or decrease bond amounts as the need for
coverage changes. This allows for incremental bonding where
appropriate.
Section 3904.20 describes what actions the BLM will take in the
event of a default payment from a lease, exploration, or reclamation
bond to cover nonpayment of any obligations that were not met. It also
requires the bond to be restored to the pre-default level. This section
is similar to sections in the other BLM mineral regulations regarding
default.
Section 3904.21 allows the termination of the period of liability
of a bond. The BLM will not consent to the termination of the period of
liability under a bond unless an acceptable replacement bond has been
filed. Termination of the period of liability of a bond ends the period
during which obligations continue to accrue, but does not relieve the
surety of the responsibility for obligations that accrued during the
period of liability. We received a comment that the proposed rule
contains no provisions regarding bond release procedures. We agree that
explicit bond release provisions will promote the availability of bonds
without endangering the environment. Therefore, in the final rule we
added new paragraphs (c), (d), and (e) to section 3904.21 to allow for
bond releases. Paragraph (c) provides that a lease bond will be
released when the BLM determines that all lease obligations accruing
during the period of liability have been fulfilled. No time frame for
release has been set, because it can take some time to complete any
necessary audits to verify that all the required obligations have been
met. Paragraph (d) provides that a reclamation bond or license bond
will be released when the BLM determines that the reclamation
obligations arising within the period of liability have been met and
that the reclamation has succeeded to the BLM's satisfaction. The time
necessary to verify the success of reclamation activities may differ
according to such local factors as drought or native plant communities
that are difficult to establish.
We note that section 3904.14(c) provides that the BLM may enter
into agreements with states to accept a state reclamation bond to cover
the BLM's reclamation bonding requirements, in which case the state
bond release procedures would be applicable.
A commenter recommended that termination of the period of liability
of a bond should relieve the surety of liability for obligations that
accrued during the period of liability. We disagree because we
distinguish termination of the period of liability (the surety is no
longer accruing obligations) from release of the bond (the surety no
longer has liability under the bond). We do not believe that all
potential sureties for replacement bonds would be willing to accept
liability for activities that occurred before the replacement bond is
issued. Nonetheless, in the event that there are such sureties, in the
final rule we added a new paragraph (e) that allows release of bonds
when the BLM accepts a replacement bond that expressly assumes all
liabilities that arose under the period of liability of the original
bond. The replacement bond must meet the requirements under section
3904.13, and the BLM may require that the replacement bond be for a
different amount under section 3904.13.
Section 3904.40 establishes trust funds or other funding mechanisms
to ensure the continuation of long-term treatment to achieve water
quality standards and for other long-term, post-mining maintenance
requirements. Experience in other mineral programs has shown the need
for a mechanism to ensure the long-term treatment of water. This
provision is similar to regulations in the BLM's mining law program
under 43 CFR 3809.552 and is designed to address similar long-term
water protection issues. In determining whether a trust fund will be
required, the BLM will consider the following factors:
(1) The anticipated post-mining obligations (PMO) that are
identified in the environmental document and/or approved POD;
[[Page 69431]]
(2) Whether there is a reasonable degree of certainty that the
treatment will be required based on accepted scientific evidence and/or
models;
(3) The determination that the financial responsibility for those
obligations rests with the operator; and
(4) Whether it is feasible, practical, or desirable to require
separate or expanded reclamation bonds for those anticipated long-term
PMOs.
The determination that a trust fund is needed and the amount needed
in the fund may be made during review of the proposed POD or later as a
result of further inspections or reviews of the operations.
We received one comment stating that we should require a bond to
assure water quality restoration. We believe the bonding provisions in
this section, as well as the requirement for full reclamation bonding,
address the commenter's concerns.
Subpart 3905--Lease Exchanges
This subpart allows the BLM to approve oil shale lease exchanges.
Section 3905.10 explains that the BLM will approve a lease exchange
if it would facilitate the recovery of oil shale and it would
consolidate mineral interests into manageable areas. It also states
that oil shale lease exchanges are governed by the regulations under 43
CFR part 2200. Section 206 of FLPMA authorizes exchanges of interests
in Federal lands for non-Federal lands (43 U.S.C. 1716).
Part 3910--Oil Shale Exploration Licenses
The regulations in this part address exploration licenses. An
exploration license allows a licensee to enter the Federal land covered
by the license and explore for minerals, but it does not authorize the
licensee to extract any minerals, except for experimental or
demonstration purposes.
Section 3910.21 authorizes the issuance of oil shale exploration
licenses on all Federal lands subject to leasing under section 3900.10,
except lands within an existing oil shale lease or in preference right
lease areas under the R, D and D program. This type of limitation on
which lands the BLM may issue an exploration license is consistent with
that of other BLM minerals exploration regulations.
Section 3910.22 makes it clear that the consent and consultation
procedures under section 3900.61 that apply to leases also apply to
exploration licenses. The BLM will issue licenses under the terms and
conditions prescribed by the surface managing agency concerning the use
and protection of the nonmineral interests in those lands. Section
3910.22 is similar to regulations for BLM's other mineral leasing
programs requiring consent and consultation for exploration licenses.
Section 3910.23 requires the operator to have a lease or license
before conducting any exploration activities on Federal lands. This
section also allows that under an exploration license, small amounts of
material may be removed for testing purposes only; however, any
material removed cannot be sold. This is similar to regulations in
other BLM mineral programs that recognize that some removal of material
is necessary for testing purposes. One comment brought to the BLM's
attention a typographical error in section 3910.23 of the proposed
rule. The cross-reference to section 3904.41 in the proposed rule is
changed to the correct cross-reference, section 3931.40, in the final
rule.
Section 3910.31 identifies specific requirements for filing an
application for an exploration license. Application requirements under
this section include:
(1) Submission of a nonrefundable filing fee;
(2) Description of lands covered by the application;
(3) An exploration plan;
(4) Compliance with maximum acreage limitations for an exploration
license; and
(5) Submission of information to prepare a notice of invitation for
other parties to participate in exploration.
Mirroring the coal regulations, this section establishes an acreage
limit of 25,000 acres as the maximum size allowable for an exploration
license. As is the case for other BLM leasing programs that provide for
exploration licenses, there is no required application form. The $295
filing fee for an exploration license is based on the filing fee for a
coal exploration license at the time the rule was proposed. The BLM
anticipates that the time required to process an oil shale exploration
license will be similar to that for a coal exploration license, and
therefore believes the same filing fee is justified.
We received one comment suggesting that acreage limitations for
exploration licenses (25,000 acres) and leases (5,760 acres) should be
the same. We disagree with this suggestion. An exploration license only
allows a licensee to conduct exploration activities and does not
include an entitlement to a lease. Therefore, there is no reason for
the acreage limitations for a lease and a license to be the same.
Typically, exploration occurs on a broader scale in order to refine and
narrow the lease area to the most promising acreage. The applicant may
want to explore for more than the 5,760 acres that is allowed in one
lease, and the most efficient and economical way to authorize these
exploration activities would be through one license and not multiple
licenses. Therefore, we believe that the larger maximum acreage figure
for licenses is warranted. An additional comment received regarding
section 3910.31 questioned the reasoning for allowing exploration on a
tract of land that would be almost 5 times larger than the acreage
limitation for one lease. There is a precedent in the coal program for
the 25,000 maximum acreage amount for exploration licenses. The Federal
Coal Leasing Amendments Act amended the MLA to allow for as much as
25,000 acres to be included in a single coal exploration license. If
past experience with exploration licenses in the coal program is any
indication, it would be rare for most licenses to reach the 25,000
acreage figure because of the expenses associated with conducting
exploration activities on such a large scale. The BLM also has the
discretion not to approve a license in whole or in part. We did not
revise the acreage limitation provision in the final rule.
Section 3910.32 requires the BLM to perform the appropriate NEPA
analysis before issuing an exploration license. The section also
explains that the BLM will include in an exploration license, terms and
conditions to mitigate impacts to the environment, to protect Federal
resource values of the area, and to ensure reclamation of the lands
disturbed by exploration activities.
Section 3910.40 provides that a licensee must comply with all
applicable Federal laws and regulations, the terms and conditions of
the license and approved exploration plan, as well as applicable state
and local laws not otherwise preempted by Federal laws, such as FLPMA.
The final section adds a requirement that licensees and their operators
keep the BLM informed of changes in names and addresses. That
requirement had been in proposed section 3930.20(c).
Section 3910.41 explains provisions relating to the administration
of the exploration license, including the license term, the effective
date of an exploration license, conditions for approval, and provisions
relating to the modification, relinquishment, and cancellation of an
exploration license. Like exploration licenses for other BLM mineral
leasing programs, the term of an exploration license is 2 years. The
requirements for oil shale exploration licenses are similar to those of
other BLM minerals programs. One commenter requested a revision to
section 3910.41 that would add a
[[Page 69432]]
provision for the BLM to cancel an exploration license in the event
significant adverse impacts to the environment occur. We have not
revised the section to include such a provision because we believe the
regulations address this concern. Prior to issuing an exploration
license, the BLM will perform an environmental review under section
3910.32(a) that will identify impacts to the environment. The impacts
will be addressed by mitigation measures included as terms and
conditions of the license to address any adverse impacts. The BLM can
terminate the license if the licensee does not comply with the terms
and conditions included in the license or the approved exploration plan
(see final sections 3910.32(b), 3910.41, and 3934.30). Under section
3936.20, the BLM will issue notices of noncompliance if a licensee's
operations threaten immediate damage to the environment, the deposit,
or other resources. If the licensee fails to take corrective action,
the BLM can order operations to cease, take actions to terminate the
license (section 3934.30), or order the licensee to pay an assessment
(section 3936.30). In addition, the BLM may also order activities to
cease should health, human safety, resource condition or the
environment be threatened. Another comment suggested that exploration
licenses should be assignable. We agree and have addressed this comment
in subpart 3933.
Section 3910.42 provides that issuance of an exploration license
does not preclude the issuance of a Federal oil shale lease for the
same area. This section also makes it clear that if an oil shale lease
is issued for an area covered by an exploration license, the BLM will
cancel the exploration license effective the date of lease issuance.
The BLM received a comment requesting that we add a provision that
would allow lands to be added to an existing exploration license.
Section 3910.31(e) requires that exploration applicants invite others
to participate in exploration under a license. Adding lands to an
existing license would mean that the amended license could possibly
have two sets of participants, two different terms, and two separate
exploration plans. The simplest way for an entity desiring to explore
lands adjacent to an existing license is to submit a new license
application. The final rule does not include a provision to add lands
to an existing license.
Section 3910.44 addresses collection and submission of data
relating to an exploration license and includes provisions relating to
confidentiality of data. This section is similar to provisions in other
BLM minerals programs. The final rule states that the BLM will consider
data confidential and proprietary until the BLM determines that public
access to the data will not damage the competitive position of the
licensee or the lands involved have been leased, whichever comes first.
Under this rule this means that the data is no longer proprietary, but
that does not necessarily mean that the information is public.
Section 3910.50 addresses the issue of surface damage resulting
from exploration operations and requires that exploration activities
not unreasonably interfere with or endanger any other lawful activity
on the same lands or damage any surface improvements on the lands. This
is similar to other BLM minerals regulations that address surface use.
Part 3920--Oil Shale Leasing
The foundation for the oil shale leasing program is a competitive
leasing process similar to the BLM's coal leasing program. Prior to
making areas available for consideration for leasing through a
competitive lease sale, there is a two-step process that begins with a
call for expressions of leasing interest (section 3921.30), to be
followed by a call for applications (section 3921.60) if the BLM
determines that there is interest in a competitive lease sale. In
addition to contributing to the orderly development of the resource,
this process facilitates compliance with NEPA by focusing the analysis
on areas in which there is active interest in obtaining a lease.
Subpart 3921--Pre-Sale Activities
The sections under this subpart contain regulatory provisions
relating to pre-leasing activities. Many of the sections are similar to
existing provisions of other BLM mineral leasing programs, particularly
coal.
Section 3921.10 explains that a BLM State Director may request in
the Federal Register expressions of interest for those areas identified
in the land use plan as available for oil shale leasing.
Section 3921.20 clarifies that the appropriate NEPA analysis must
be prepared for the proposed leasing area under the Council on
Environmental Quality's (CEQ) regulations at 40 CFR parts 1500 through
1508 and Department policies and procedures developed pursuant to NEPA.
We received several comments regarding the NEPA process and the
opportunity for public participation and review from Federal, state,
and local agencies throughout the process. All NEPA analyses and
documentation will be performed in compliance with the CEQ regulations,
with public participation being an essential part of the process.
Sections 3900.50, 3910.32, and 3921.20 of this rule reinforce the fact
that the BLM will comply with NEPA and other appropriate Federal laws
and regulations to ensure the protection of the resource and the
environment. The BLM also revised section 3931.10(f) to make it
explicit that appropriate NEPA analysis is also required before
exploration plans or PODs are approved. The BLM's NEPA Handbook (H-
1790-1) and Land Use Planning Handbook (H-1601-1) provide extensive
guidance regarding the roles of and opportunities for other Federal,
state, and local agencies and the public to participate in the BLM's
environmental processes. The BLM also affords Federal, state, and local
governments the opportunity to participate, as cooperating agencies,
during the preparation of environmental impact statements. The BLM,
therefore, believes that there are adequate opportunities built into
the BLM's NEPA and land use planning process to provide full and
meaningful coordination with Federal, state, and local government, as
well as opportunities for public participation. In addition, outside
the NEPA process, section 3921.40 requires the BLM to notify the
appropriate state governor's office, local governments, and interested
Indian tribes of the opportunity to provide comments on industry's
responses to the call for expression interest and other issues related
to oil shale leasing.
Several commenters disagreed with the requirement of multiple NEPA
analyses and suggested that the BLM combine the two NEPA analyses. The
environmental analysis referenced in section 3900.50 is used to support
land use planning decisions of all kinds and will, among other things,
determine whether the lands are suitable for leasing oil shale or not.
The analysis under section 3921.20 will specifically address the
impacts of oil shale leasing, hence the need for information requested
in section 3922.20 on the types of oil shale development activities
contemplated by potential lessees. In-as-much as the NEPA analysis
completed for leasing may not always accurately predict the types of
impacts of future oil shale development, additional NEPA analysis will
be required before actual development activities occur to ensure that
impacts not contemplated, planned, or apparent at the time of leasing
are addressed.
[[Page 69433]]
With the commercial oil shale industry in the early stages of
development, it would be inappropriate to combine the NEPA analysis for
leasing and POD stages at this time. At the leasing stage, there may be
uncertainties concerning the level, type, and amount of development and
therefore, a more narrow decision (leasing only decision) may be made,
while at the POD stage, when more specific information is known, the
analysis will be more focused on the lessee's proposed development
activities. It will include specific technology information, exact
mining or surface disturbance acreage, the specific equipment
infrastructure, and the exact on-the-ground footprint of the proposed
operation. However, it is likely that much of the NEPA analysis and
information developed prior to leasing could be used or referenced
during subsequent NEPA analysis.
Several commenters stated that the BLM should collaborate with
state agencies such as the state's department of natural resources,
department of health, and water quality control division and local
municipal governments to protect water resources. As stated above,
Federal, state, and local governments will be afforded multiple
opportunities to participate in the BLM's NEPA and land use planning
process. One commenter stated that the BLM should retain authority to
withdraw specific tracts from leasing should the results of further
NEPA analysis support it. The commenter also stated that the BLM should
retain authority to modify lease terms or add protective stipulations
to a lease after it has been issued.
The BLM has the authority to not approve the leasing of lands that
are identified in a land use planning document as open to application
for future commercial leasing, exploration, and development. The BLM
will conduct pre-lease NEPA analysis to identify necessary controls to
mitigate or eliminate environmental impacts on parcels being considered
for leasing. If, as part of the NEPA analysis, the BLM determines that
leasing and subsequent development of the oil shale resources would
cause significant impacts, the BLM can require the applicant to: (1)
Mitigate the impact so that it is no longer significant; or (2) Move
the proposed lease location. If neither of these options resolves the
anticipated conflicts, the BLM can decide that protection of the
resource outweighs the development of the oil shale resources or vice-
versa. Once a lease is issued, additional mitigation could be applied
based on the further NEPA documentation performed at the POD stage. At
the POD stage, site-specific mitigation measures can be developed and
applied as conditions of approval. In addition, subpart 3932 of this
rule discusses lease modifications and readjustments. Under that
subpart, the BLM has the authority to change lease terms, conditions,
and stipulations at end of the first 20-year period of the lease and,
excepting royalty rates, at the end of each 10-year period thereafter.
Section 3921.30 provides that the notice calling for expressions of
leasing interest would be published in the Federal Register and in at
least one newspaper of general circulation in the affected state. The
notice will allow a minimum of 30 days to submit expressions of leasing
interest, including a legal land description and other specified
information.
Section 3921.40 requires that the BLM notify the appropriate state
governor's office, local governments, and interested Indian tribes of
their opportunity, after the BLM receives responses to the call for
expression of leasing interest, to provide comments regarding the
responses and other issues related to oil shale leasing. The BLM
included this requirement in the rule in response to discussions at the
three listening sessions with the governors' representatives. One
commenter recommended that the BLM expand this section to include
notification to potentially affected Federal land managers. The BLM
does not see the need to include potentially affected Federal agencies
at this stage of the process. The CEQ regulations emphasize cooperation
with other Federal agencies early in the NEPA process. Any other
Federal agency that has ``special expertise'' with respect to any
environmental issue, which will be addressed by the NEPA analysis, may
participate as a cooperating agency. If an affected Federal agency
declines to become a cooperating agency, the agency has the opportunity
to provide scoping comments and review and comment on draft EISs and/or
associated planning documents that would be developed prior to leasing
and approval of PODs.
Section 3921.50 explains that after analyzing expressions of
leasing interest, the BLM will determine a geographic area for
receiving applications to lease. This section also explains that the
BLM may add lands to those areas identified by the public in the
expressions of leasing interest. One commenter stated that the BLM
should also have the authority to remove lands in an application to
lease based on resource protection concerns. As noted above, the BLM
already has the authority to make any necessary adjustments to the area
under consideration prior to holding the lease sale.
Under section 3921.60, the BLM's call for lease applications will
be published in the Federal Register and will identify the geographic
area available for application under subpart 3922. Under this section,
the public will have at least 90 days to submit applications for lease.
Subpart 3922--Application Processing
The sections under this subpart contain regulatory provisions
relating to application requirements. These provisions are similar to
existing regulations of other BLM mineral leasing programs.
Section 3922.10 requires an applicant nominating a tract for
competitive leasing to pay a cost recovery or processing fee that the
BLM will determine on a case-by-case basis as described in 43 CFR
3000.11 and as modified by provisions of section 3922.10. The section
provides that the applicant who nominates a tract will pay to the BLM
the processing costs that the BLM incurs up to the time of publication
of the competitive lease sale notice. That fee amount will be in the
sale notice. If the applicant is the successful bidder, the applicant
would then also pay all processing costs the BLM incurs after the date
of the sale notice. Payment of all cost recovery fees is required prior
to lease issuance.
If the successful bidder is someone other than the original
applicant, the successful bidder will be required to submit an
application under section 3922.20 within 30 days after the lease sale
and be responsible for paying to the BLM the fee amount included in the
sale notice. In such circumstances, the BLM will refund the fees the
original applicant paid to the BLM. The successful bidder is also
responsible for any processing costs the BLM incurs after the date of
the sale notice. If there is no successful bidder, the applicant is
responsible for processing costs, and there will be no refund.
With respect to costs incurred relating to the NEPA analysis to
support a competitive lease sale, the BLM processing fees noted in the
sale notice include, if applicable, the BLM's costs associated with
preparation of the NEPA analysis, which may include BLM costs incurred
in contracting with a third party to perform the NEPA analysis. In
cases where there are several applications that have been filed for the
same area, it is likely that the BLM would prepare a single NEPA
analysis, which would address issues related to
[[Page 69434]]
environmental impacts identified in all applications that were filed in
response to the call for applications.
In the case where the successful bidder for a tract is not the
original applicant, the successful bidder will be responsible for
paying the fee noted in the sale notice and any additional BLM
processing costs, including any additional NEPA analysis. For example,
in the case where a successful high bidder is not the original
applicant and the technology that the successful bidder proposes to use
was not previously analyzed in the NEPA analysis, the successful bidder
is responsible for paying for the cost of the original NEPA analysis
and any additional NEPA analysis that is necessary.
It should be noted that an applicant will not be reimbursed for
moneys the applicant (and not the BLM) may pay directly to third
persons to perform studies, including any required analyses under NEPA.
Under section 3922.10, the BLM adopted case-by-case processing fees
for applications that mirror case-by-case fee requirements applicable
to the leasing of coal and non-energy leasable minerals offered through
competitive lease sales. The BLM's minerals material sales regulations
also contain case-by-case processing fees. Case-by-case fees allow the
BLM to recoup its processing costs by charging an applicant the
reasonable costs the BLM incurs in processing a particular application.
Cost recovery is authorized under the Independent Offices Appropriation
Act of 1952, as amended, 31 U.S.C. 9701, which states that Federal
agencies should be ``self-sustaining to the extent possible'' and
authorizes agency heads to ``prescribe regulations establishing the
charge for a service or thing of value provided by the agency.'' The
BLM also has specific authority to charge fees for processing
applications and other documents relating to public lands, including
EISs, under Section 304(b) of FLPMA (43 U.S.C. 1734(b)). Cost recovery
policies are explained in Office of Management and Budget Circular A-25
(Revised), entitled ``User Charges.'' The general Federal policy stated
in Circular A-25 (Revised) is that a charge will be assessed against
each identifiable recipient for special benefits derived from Federal
activities beyond those received by the general public.
Additionally, this section states that the BLM will not issue a
lease offered by competitive sale without having first received an
application from the successful bidder under section 3922.20. Under
section 3922.10(b)(5) a successful bidder at a competitive lease sale
who was not an applicant must file an application within 30 calendar
days after the lease sale.
A commenter noted that although section 3922.10 requires a cost
recovery fee for lease nominations, there appears to be no fee required
for BLM processing of PODs. The comment further recommended that the
BLM charge a cost recovery fee for processing PODs, particularly in
light of recently enacted legislation requiring the BLM to assess fees
for approval of applications for permits to drill (APDs) on oil and gas
leases.
Since the BLM did not propose a cost recovery fee for PODs, we are
not adopting the recommendation.
Section 3922.20 identifies specific information that an applicant
is required to include in a lease application to enable the BLM to have
sufficient information to prepare the appropriate NEPA analysis to
evaluate the impacts of proposed leasing. The amount of information
requested as part of an oil shale lease application differs from other
mineral leasing programs because the methodology for recovering oil
shale is not as standardized as it is for more conventional fuels.
Although no specific form is required, information the applicant is
required to provide includes, but is not limited to:
(1) Proposed extraction method (including personnel requirements,
production levels, and transportation methods) and estimate of the
maximum surface area to be disturbed at any one time;
(2) Sources and quantities of water to be used and treatment and
disposal methods necessary to meet applicable water quality standards;
(3) Air emissions;
(4) Anticipated noise levels from proposed development;
(5) How proposed lease development will comply with all applicable
statutes and regulations governing management of chemicals and disposal
of waste;
(6) Reasonably foreseeable social, economic, and infrastructure
impacts of the proposed development on the surrounding communities and
on state and local governments;
(7) Mitigation of impacts on species and habitats; and
(8) Proposed reclamation methods.
Several commenters stated that it may be difficult to provide the
detailed level of application information requested in the proposed
regulations prior to tract delineation. The commenters are correct in
their statements that the specific details of a mining operation may
not be completely known, particularly if the lease tracts are
ultimately redesigned prior to leasing. The BLM, however, will still
need as much specific information as possible on proposed technologies
and the potential impacts of these technologies prior to leasing in
order to make reasonable assumptions concerning the level and type of
commercial oil shale activity likely to occur. The applicant must
submit information on its proposed technology, tract location, and
potential environmental impacts, so that the BLM, or a third party
contractor, will have enough data to analyze the direct, indirect, and
cumulative effects should leasing occur and to develop specific
mitigation measures or stipulations to eliminate or mitigate adverse
effects. Additional NEPA analysis will be required prior to approval of
PODs and actual development activities and will benefit from a more
detailed leasing analysis.
Another commenter suggested that the BLM add provisions to ensure
that prospective licensees and lessees identify the full breadth of
potential impacts of operations on activities such as access and power
generation, on resources and values of adjacent National Park Service
and special status lands, and require them to identify specific
measures on how they will avoid such impacts.
Included in the application requirements in the final rule are
requests for the type of information the commenter identified. In
addition, the scoping process required under NEPA will be used to
identify issues and concerns, resources and resource values affected,
connected and reasonably foreseeable actions, and reasonable
alternatives based on the nature and scope of the proposed action. The
scoping process will determine which issues will be analyzed in detail,
while simultaneously eliminating issues from further analysis. As a
consequence of the NEPA analysis, reasonable alternatives,
stipulations, or other mitigation measures will be developed to
mitigate or eliminate any adverse environmental impacts of leasing.
Another comment suggested that the BLM require baseline monitoring
and monitoring of mine or in-situ construction, operational, and post-
operational activities in order to provide accurate information about
the effects that commercial development will have on the environment
and local communities. The regulations provide the flexibility for the
BLM to require monitoring, if necessary, as a condition of exploration
plan or POD approval. It is premature, at the rulemaking stage, to
determine whether and what types of monitoring might be necessary
during the development of oil shale resources;
[[Page 69435]]
therefore, we made no change in the rule as a result of this comment.
We received a comment regarding section 3922.20 that disagrees with
the requirement to gather information for a lease application at the
exploration license phase where anyone can participate. The commenter
believes that the gathering of information should occur after a lease
issues so that only the lessee knows what the resource information is.
While provisions in these regulations allow for exploration on unleased
lands under an exploration license, exploration may also occur on a
lease without a requirement that the resource information be shared.
The information requested in the lease application is needed for the
BLM to adequately assess potential environmental impacts as required by
NEPA. No regulatory changes were made as result of this comment.
Another comment suggested that in order to address multiple mineral
development issues (first in time, first in right), the final rule
should contain a provision to require the applicant to include on the
maps submitted locations of producing, drilling, and abandoned wells,
existing facilities of other lessees, and existing equipment and
pipelines related to other mineral development or the BLM undertake to
provide the information in advance of any lease sale. While we agree
that this information is useful and necessary, this requirement has not
been adopted because the BLM typically has this information and will
ensure that all parties interested in bidding will have access to it
prior to the lease sale.
Another comment concerning section 3922.20 asked that we add to
that section wording similar to that in 3926.10(b)(2) for the R,D and D
leases requiring the applicant to include a ``description of
consultation with the state and local officials to develop a plan for
mitigating the socioeconomic impacts of commercial developments on
communities, services, and infrastructure.'' The BLM has revised final
section 3922.20(c)(11) to require the applicant to include a discussion
of the proposed mitigation measures or a plan to mitigate adverse
impacts, not only to communities, but to services and infrastructure.
Another commenter requested that the BLM use as a model MMS's 30
CFR 285.102, 285.105, 285.203, 285.610, and 285.626 proposed
regulations (see 73 FR 39460). Part 285 is titled ``Alternative Energy
and Alternative uses of existing facilities on the Outer Continental
Shelf.'' Section 285.102 outlines what MMS' responsibilities are,
section 285.105 outlines the responsibilities of the applicant, and
section 285.203 outlines who MMS will consult with before issuing a
lease. We do not believe that the MMS outer continental shelf
regulations meet the objectives of the BLM's oil shale program. This
rule addresses consultation and the responsibilities of the applicant
to provide sufficient information that the BLM needs to prepare the
appropriate NEPA analysis to evaluate the impacts of proposed oil shale
leasing and to delineate tracts for leasing.
Section 3922.30 provides that the BLM could request additional
information from the applicant, and explains that failure to provide
the best available and most accurate information might result in
suspension or termination of processing of the application or in a
decision to reject the application. The BLM's ability to obtain
additional information at this stage is essential to the NEPA analysis
to support leasing. Failure to provide the needed information would
have a direct impact on the adequacy of the NEPA analysis and therefore
could have an adverse impact on the BLM's decision to proceed with a
lease sale.
Section 3922.40 makes it clear that the purpose of tract
delineation for a competitive lease sale is to provide for the orderly
development of the oil shale resource. This section also clarifies that
in addition to adding or deleting lands from an area covered by an
application, where lands covered by applications overlap, the BLM may
delineate those lands that overlap as separate tracts. The BLM may
delineate tracts in any area acceptable for further consideration for
leasing, regardless of whether it received expressions of interest or
applications for those areas. The need to delineate tracts for adequate
development of the mineral resource is recognized in all the BLM
mineral leasing programs, and provisions similar to this are contained
in the other BLM mineral leasing regulations.
Subpart 3923--Minimum Bid
Section 3923.10 implements the policy of the United States under
Section 102(a) of FLPMA (43 U.S.C. 1701(a)(9)) that the Federal
Government should receive FMV for leasing its minerals. Also, Section
369(o) of the EP Act requires that payments for leases under that
section must ensure a fair return to the United States. Under section
3924.10, the BLM sales panel determines if the high bid reflects the
FMV of the tract, which we equate to fair return. We anticipate that
the sales panel will analyze the bids and make a determination, taking
into account the appraisal reports, as explained in greater detail in
the preamble to subpart 3924.
The BLM recognizes the difficulty in determining a value for a
resource (oil shale) that has tremendous potential, but has not yet
been proven to be economic to develop. The risk of setting pre-sale
FMVs that are too high and that would discourage development of a
commercial leasing program is very real. The BLM is also aware that the
oil shale industry is presently in the research and development stage
and comparable lease sales might be rare or unavailable when leasing
first occurs under these regulations, but this will not always be the
case. Competitive lease sales of Federal oil shale leases in the 1970s
resulted in bids of $10,000 per acre, or higher, indicating that even
though development risks are high, the potential reward is also high.
Both the economic and the technological circumstances have changed
since the 1970s, including the withdrawal of substantial subsidies, but
the vast quantities of oil shale on Federal lands weigh in favor of
high minimum bid amounts. For comparison purposes, the coal program has
a minimum bid amount of $100 per acre and the oil and gas program has a
minimum bid amount of $2 per acre. This section sets a minimum bid of
$1,000 per acre.
We received a number of comments on the proposed minimum bid
(subpart 3923) and FMV (subpart 3924) provisions. Comments that
exclusively address minimum bid issues are discussed below. Comments
that address FMV issues on both subparts are discussed under subpart
3924.
A commenter stated that given the FMV requirement, the inclusion of
a minimum bid appears to be superfluous and unnecessary. Other
commenters suggested that the minimum bonus bid must reflect the true
value of the resource. We also received numerous comments stating that
the minimum bid was either too high or too low. Commenters suggested
that with the $1,000 per acre minimum bid and the vague FMV standards,
the BLM could be forced to lease tracts for far less than their true
value. Those advocating a higher minimum bid point to the 1970's
prototype leases as an indicator of value. We also received comments
that the $1,000 per acre minimum bid is an unrealistically high
minimum. One commenter pointed out that bids on the tar sand leases
issued by Utah's School and Institutional Trust Land Administration
ranged from $1.38 per acre to $212.29 per acre. Several other
commenters suggest the $100 per acre coal minimum bid or the $2 per
acre oil and gas minimum bid are more
[[Page 69436]]
reasonable floor values, especially given the infancy of the industry
and the Congressional mandate to promote oil shale development. Another
commenter pointed out that a $1,000 per acre minimum bid does not
account for differences in the potential oil yields. For example, it
favors thick deposits over thinner deposits, as it represents a smaller
share of the value of the thick deposits. The commenter suggests that
this could hinder resource development. The commenter also said that
minimum bids should be posted for individual leases at the time of
offering or be based on a yield figure such as $0.005 per barrel.
The bonus bid represents one part of the FMV to be received by the
Federal Government. Rental, royalties, and other considerations
influence FMV. In some instances, the minimum bid may ultimately be
determined to represent FMV and the acceptable high bid for the lease.
The minimum bid requirement does not ensure that the United States
receives FMV for the use of the oil shale resource, but rather
establishes a floor to minimize the participation of bidders that are
not likely to be serious about developing the oil shale. As discussed
in the proposed rule, the BLM will employ a well-established appraisal
process to determine each tract's FMV. In the proposed rule, we
specifically asked for comments on the appropriateness of the proposed
$1,000 per acre minimum bid. As noted above, we received suggestions
that the $1,000 per acre bid amount was either too high or too low;
however, for the most part we received little information to support
those positions. The argument that a per acre minimum favors tracts
with thicker seams, in certain instances, is valid. However, the agency
has a history of using a simple standardized per acre unit, e.g., $100
per acre for coal leasing, for minimum bids to avoid any confusion that
the minimum bid amount equates to the actual tract FMV. Also, it needs
to be noted that the prospective lessee is responsible for nominating
the prospective lease tracts. To the extent that the minimum bid may
actually exceed FMV for certain thin-seam tracts, the prospective
lessee will avoid nominating such lands. As such, we have decided to
keep the minimum bid at $1,000 per acre.
Subpart 3924--Lease Sale Procedures
Provisions of this subpart identify the process by which tracts of
land are made available for competitive lease sale. The BLM will lease
oil shale through a competitive bidding leasing procedure that mirrors
competitive lease sales procedures currently in place for other solid
minerals leasing programs, particularly coal.
Section 3924.5 details the contents of the sale notice that the BLM
would publish in the Federal Register and newspapers of general
circulation in the area of the proposed lease. The purpose of the
notice is to alert the public that the BLM will be holding an oil shale
lease sale and to provide enough of the details about the proposed
lease terms and conditions, lease area, and leasing limitations for the
public to make an informed decision whether to participate in the lease
sale. This section is similar to other BLM mineral leasing regulations
that require notification of the lease sale and is a necessary part of
the oil shale leasing program. One commenter thought that section
3924.5 should be revised to require the BLM to provide at least 6
months' advance notice to bidders of a proposed lease sale to allow
bidders a realistic opportunity to conduct due diligence. We believe
that the public notice requirements associated with the presale
environmental review process will provide ample advance notice that a
sale is imminent. However, we revised the rule to state that the lease
sale will not be held until at least 30 days after the notice of lease
sale is posted in the BLM state office. This 30-day notice mirrors the
other solid mineral leasing processes such as coal and non-energy
leasable minerals.
Section 3924.10 details competitive lease sale procedures,
including receipt and opening of sealed bids, submission of one-fifth
of the amount of the bonus bid, requirements for future submission of
remaining installments of the bonus bid, and post-sale procedures for
determining the successful bidder. This section also addresses the
actions of the sales panel in determining whether or not to accept the
high bid, including a FMV determination. This section is similar to the
BLM's competitive leasing regulations for coal and non-energy leasable
minerals. The BLM chose to adopt this process because it has been
successful in other mineral leasing programs and because we believe
this process is appropriate for oil shale leasing. One comment
requested an explanation of why the BLM is allowing the successful
bidder to pay the balance of the bonus bid on a deferred basis. The
bids received in the early 1970s ranged from $9,000 per acre to $41,000
per acre, indicating that future bonus payments could be large. Because
of the large dollar amounts that may be associated with future lease
sales, the BLM believes it is reasonable to allow the companies to pay
the bonus payments in installments. Also, as mentioned previously, the
BLM has adopted for the oil shale commercial leasing program some
components of the competitive leasing process in place for the coal,
which allows for deferred bonus payments, which experience has shown
has worked well.
When evaluating the adequacy of a high bid, the sales panel will
rely on the appraisal process to estimate the FMV for commercial oil
shale leases. An appraisal is an unbiased estimate of the value of
property. The appraisal process is a systematic approach to property
valuation. It consists of defining data requirements, assembling the
best available data, and applying an appropriate appraisal method. The
principles of property valuation that the BLM will apply are presented
in the ``Uniform Appraisal Standards for Federal Land Acquisitions and
in the Appraisal of Real Estate.'' The term ``fair market value'' is
defined in the Uniform Appraisal Standards for Federal Land
Acquisitions as the amount in cash, or on terms reasonably equivalent
to cash, for which in all probability the property would be sold by a
knowledgeable owner willing, but not obligated, to sell to a
knowledgeable purchaser who desired, but is not obligated, to buy.
In ascertaining that figure, consideration should be given to all
matters that might be brought forward and substantial weight given to
bargaining by persons of ordinary prudence. Factors that will affect
the market value of an oil shale lease include the lease terms which
encompass rental and royalty obligations. The bonus bid for the lease
must be equal or greater than the lease FMV.
There are three methodologies generally used in appraising real
property: The comparable sales approach, income approach, and
replacement cost approach. Normally, the replacement cost approach is
not applied to appraisals involving mineral leases and similar
property.
In the comparable sales approach, the value of a property is
estimated from prior sales of comparable properties. The basis for
estimation is that the market would impute value to the subject
property in the same manner that it determines the value of comparable
competitive properties. When reliable comparable sales data are
available, it is generally assumed that the comparable sales approach
will provide the best indication of value.
In the income approach, the value assigned to the property is
derived from the present worth of future net income benefits. If
sufficiently similar sales are not available, the FMV determination
[[Page 69437]]
will generally rely on the income approach.
The FMV determination follows a pre-existing valuation standard,
which utilizes the circumstances of place, time, the existence of
comparable precedents, and the evaluation principles of each involved
party. In determining the FMV under this rule, our determination will
be based on comparison with identical or similar past, actual, or
expected services and goods relating to oil shale. 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 proposed to establish oil shale lease FMV using a process
similar to that used in the Federal coal leasing program. This process
relies on the appraisal process in an attempt to estimate the market
value for those leases. As such, the process relies on many of the
procedures used in private sector valuations, and where available, will
rely on private sector transactions to establish the market value for
Federal oil shale leases. The Federal coal leasing program and this
rule utilize competitive bidding, specifically sealed bidding, for
determining who receives the lease.
In the rule, the BLM is establishing a minimum acceptable bonus bid
for Federal oil shale leases. The amount is not a reflection of FMV,
but is intended to establish a floor to limit or dissuade nuisance
bids. The rule requires a minimum acceptable bonus bid of $1,000 per
acre. The BLM requested further comments on the minimum bid proposed.
As per comments on specific values, the rule does not attempt to
establish actual FMV for bidding on future Federal oil shale leases.
Values received in the 1970s may not be an accurate indicator for
future values.
We received a number of comments on the proposed minimum bid
(subpart 3923) and FMV (subpart 3924) provisions. Comments that
exclusively addressed minimum bid issues are discussed under subpart
3923. Comments that address FMV issues or both subparts are discussed
below.
Several commenters suggest that the proposed FMV provision provides
unreasonably vague standards and does not establish definitive
procedures for determining FMV. Commenters also said that the
provisions in the rule for establishing FMV would not help the BLM
decide whether or not to accept a bonus bid. As noted in one comment,
of the three methodologies, there are no comparable sales, there is no
commercial production so there isn't any income, and the replacement
cost approach doesn't make sense as an appraisal method for mineral
properties. Commenters also observed that the proposed appraisal
process requires significant data that is not currently available and
that without knowing how the resource will be developed, it is
impossible for the BLM to determine FMV. Commenters suggested that the
BLM should wait on commercial leasing until the R, D and D program has
had a chance to identify and answer the development, technology, and
economic questions of oil shale development. One of the benefits of the
R, D and D program is that it provides a better understanding of the
development technologies and costs; it was suggested that this will
enhance the agency's ability to determine FMV.
The regulations call for the use of well-established appraisal
procedures and methodologies. The limitations are not with the process,
as one commenter stated, but with the available information. The BLM
readily acknowledges the difficulty in determining FMV for commercial
oil shale leases where there isn't an active industry. We agree with
the comments that suggested that with the future success and
commercialization of R, D, and D efforts, data will be more readily
available to support FMV determinations for future commercial leasing.
We received a comment that the EP Act does not require nor intend
for the recovery of FMV. A commenter stated that in the proposed rule
the BLM failed to identify any valid statutory authority to impose FMV.
We received comments suggesting that the BLM should forego attempting
to estimate FMV. We also received a comment suggesting that the BLM
should forego the bonus bid requirement altogether. Commenters said
that the BLM should let the market determine value, i.e., the highest
bidder wins. Another commenter stated that FMV should be equal to a
minimum bid of $100 per acre. Other comments suggested that bid
acceptance should include demonstrated technology development
capability. Commenters wanted the BLM to consider additional factors
such as the time it takes to develop a property, resource recovery,
recovery of other minerals, and the environmental disturbance
associated with oil shale development. Another commenter suggested that
in deciding the bid acceptance, the BLM must also consider the large,
negative, and long-term impacts (e.g., greenhouse gas emissions)
associated with commercial oil shale development.
The BLM is required by Section 102(a) of FLPMA (43 U.S.C.
1701(a)(9)) to receive FMV for mineral leases. Although Section 369(o)
of the EP Act uses the term ``fair return,'' we interpret fair return
to mean FMV, as required by FLPMA. As mentioned in the proposed rule,
FMV is defined in the Uniform Appraisal Standards for Federal Land
Acquisitions as the amount in cash, or in terms reasonably equivalent
to cash, for which in all probability the property would be sold by a
knowledgeable owner willing, but not obligated, to sell to a
knowledgeable purchaser who desired, but is not obligated, to buy.
Because FMV is not a precise calculation, but rather an interpretation
of the market, under the final rule the BLM will use sales panels to
analyze bids. The BLM will also use other factors such as geology,
market conditions, mining methods, and industry economics, in making a
determination whether the high bid reflects FMV. The BLM will consider
all matters that may potentially affect the market value of the lease.
The purpose of the bonus bid, however, is to obtain FMV for the United
States; it is not to impose an environmental tax. Ultimately, FMV is
determined by the market. However, in the absence of competition, the
highest bid may not reflect FMV. Many of these comments raise sale and
lease specific issues that are beyond the scope of these regulations.
A commenter suggested a specific provision be added to the
regulations to allow for the appeal of FMV determinations to the IBLA.
Any adversely affected party has the right to appeal any decisions
under part 3900 of this rule. Section 3900.20 addresses appeal rights.
A commenter stated that the BLM should determine FMV by the time of
the sale. The commenter suggests that establishing FMV after the sale
could take months, even years, and that this delay would add to the
uncertainty. The BLM generally makes an estimate of FMV based on
available data in advance of any sale. This estimate will not be
disclosed. However, because of the importance of market transaction
information in establishing FMV, the bid acceptance decision will not
be made until the sales panel has had an opportunity to review and
consider the information from that sale.
Subpart 3925--Award of Lease
Section 3925.10 provides that the lease will ordinarily be awarded
to the qualified bidder submitting the highest
[[Page 69438]]
bid which meets or exceeds the BLM's estimate of FMV. We revised
paragraph (a) of this section to make it consistent with paragraphs (d)
and (e) of section 3924.10 in that the winning bid must be equal to or
greater than FMV as determined under those provisions. This section
also contains requirements for the submission of the necessary lease
bond, the first year's rental, any unpaid cost recovery fees, including
costs associated with the NEPA analysis, and the bidder's proportionate
share of the cost of publication of the sale notice. The provisions in
this section are similar to regulations in the BLM's competitive
leasing regulations for coal and non-energy leasable minerals. One
commenter requested that this section include terms that would: (1)
Place potential bidders on notice that a lease can be terminated in the
event that vital information has been overlooked or misapplied,
including environmental information; and (2) Identify the components of
a liquidated damage award in order to avoid protracted litigation and
unrealistic expectations on the part of potential lessees in the event
a lease must be cancelled for public purpose reasons, like
environmental protection. Although we recognize that there are
situations beyond a lessee's control that that may require the BLM to
cancel a lease, the potential for lease cancellation is no greater in
this program than in other BLM mineral leasing programs. As in other
leasing programs, there is always the possibility that a lawsuit could
be filed by a party that is opposed to lease issuance. It is a risk
that a potential lessee assumes in conjunction with participation in
the program and the competitive leasing process. To maintain
consistency with regulatory provisions in other BLM mineral leasing
programs, we are not adopting these recommendations. The BLM believes
that potential lessees are aware of the possibility of cancellation and
therefore did not include a provision in the final rule putting
``potential bidders on notice'' of this issue. Another commenter stated
that the BLM must clear up the confusion between ``nominators,''
``original applicants,'' and ``applicants.'' Although the terminology
``nominator'' and ``original applicant'' does not appear in this
subpart, section 3925.10 refers to ``successful bidder'' and
``applicant.'' The term ``applicant,'' which is first referenced in
section 3922.10, pertains to a party who nominates a tract for
competitive leasing in response to the BLM's call for expression of
leasing interest under section 3921.30 or applies for a tract for
competitive leasing under subpart 3922. The term ``original applicant''
applies to a party who submitted an application in response to the call
for applications under section 3921.10, and is used to distinguish that
party from a party who submits a bid at the time of the competitive
lease sale, but did not previously submit an application under subpart
3922. We did not adopt the comment since we believe that the
distinction between an applicant and a successful bidder is clear,
especially in light of the cross-reference in section 3925.10(e) to
section 3922.20 which clarifies who is an applicant.
Subpart 3926--Conversion of Preference Right for Research, Development,
and Demonstration Leases
Section 3926.10 provides application procedures or requirements to
convert R, D and D leases and preference right acreage to commercial
leases. Under this section, a lessee of any R, D and D lease is
required to apply for conversion to a commercial lease no later than 90
days after the BLM determines that commencement of production in
commercial quantities has occurred. As stated in Section 23 of the R, D
and D leases (issued in response to the BLM's call for nominations of
parcels for R, D and D leasing 70 FR 33753 and 33754, June 9, 2005), R,
D and D lessees can acquire acreage contiguous to the remaining
preference right lease area up to a total of 5,120 acres. In order to
acquire the contiguous acreage and convert to a commercial lease, the
lessee is required to demonstrate to the BLM that the technology tested
in the original lease has the ability to produce shale oil in
commercial quantities. In addition, the lessee, as required in R, D and
D leases, is required to submit to the BLM:
(1) Documentation that there have been commercial quantities of oil
shale produced from the lease, including the narrative required by
Section 23 of the R, D and D leases;
(2) Documentation that the lessee consulted with state and local
officials to develop a plan for mitigating the socioeconomic impacts of
commercial development on communities and infrastructure;
(3) A bid payment no less than that specified in section 3923.10
and equal to the FMV of the lease; and
(4) Bonding as required by section 3904.14.
Additionally, the section lists those items that are necessary for
the BLM to determine whether to approve an application for conversion.
We received several comments on this section recommending either
revisions or the need to clarify specific requirements relating to the
application process. Commenters included current R, D and D lessees,
some of whom noted in their comments the significance of section
3926.10 and its relationship to Section 23 of the R, D and D leases,
which contains requirements for conversion of an R, D and D lease to a
commercial lease. Comments relating to section 3926.10 generally
focused on the following areas: Definition of commercial quantities;
timeframe for filing an application for conversion; documentation of
production of oil shale in commercial quantities from an R, D and D
lease; consistent use of the same technology in an R, D and D lease as
a condition for conversion; bonus payment equivalent to FMV; appeal
rights associated with FMV determination; consultation with Federal,
state, and local officials; NEPA compliance; the requirement that
commercial scale operations be conducted without unacceptable
environmental consequences; term of the newly converted lease; and
flexibility to exchange preference areas with other commercial oil
shale lease sites.
Comments relating to the definition of commercial quantities are
addressed in this preamble in the discussion of section 3900.2
Definitions.
Several comments expressed concern with the requirement under
section 3926.10(b)(1) that an R, D and D lessee must document to the
BLM's satisfaction that it has produced commercial quantities of oil
shale from the lease. A commenter stated that an R, D and D lessee
should be allowed to obtain the preference lease area without being
required to demonstrate that a profit had been made on the oil shale
produced exclusively in the 160-acre R, D and D lease area. According
to the commenter, if the goal of the R, D and D program is to
demonstrate that commercial development of oil shale is feasible, it
should not matter that the retort was actually located on nearby or
adjacent lands. We disagree. The quality of an oil shale deposit will
vary with location and therefore we believe that the location could
affect the feasibility of a commercial oil shale project. The
requirement in Section 23 of the R, D and D leases to produce in
commercial quantities on an R, D and D lease is a key component of the
BLM's R, D and D program. As the intent of subpart 3926 is not to
establish new or different application requirements for conversion than
those listed in Section 23 of R, D and D leases, but rather to be
consistent with those provisions in the regulations, we are not
eliminating the requirement
[[Page 69439]]
for an R, D and D lessee's to produce commercial quantities.
We received one comment stating that the application of the
commercial quantities requirement to the conversion process of an R, D
and D lease is confusing, thereby creating risk to an R, D and D lessee
of inadvertently losing its rights to convert to a commercial lease.
Another comment stated that as a practical matter, the lessee will be
unable to make the required demonstration until results of the pilot
tests are fully evaluated and therefore ``commercial quantities'' is
not readily determinable by an R, D and D lessee. The commenter
recommended that section 3926.10(b) be revised to require that an
application for conversion be filed no later than 90 days after the R,
D and D lessee concludes the evaluation of the pilot test. The comment
further suggested that in order to assure that the results of the pilot
test have been adequately analyzed by the lessee, the final rule should
not restrict an R, D and D lessee to a 90-day timeframe for filing an
application for conversion and therefore the regulations should include
a provision that would allow the BLM and the R, D and D lessee to agree
to a later date for filing an application for conversion. We recognize
that the determination that an R, D and D lease is producing in
commercial quantities entails quantitative analysis. As stated in the
preamble discussion relating to the clarification of the definition of
the term ``commercial quantities,'' it is the BLM's position that
evaluation of data is necessary in order to make a determination
whether the lease is capable of producing commercial quantities.
However, it is envisioned that the POD for R, D and D leases will
contain provisions that will acknowledge this evaluation process and be
considered when the lessee determines and the BLM confirms that
commercial quantities have been achieved. It is also important that a
timely decision to convert occurs once commercial production commences
to ensure that R, D and D leases do not inadvertently become de facto
commercial leases. We made no revisions to the final rule as a result
of this comment.
We received a comment stating that section 3926.10 needs to clarify
what action the BLM would take on an application that is not timely
filed, since the proposed rule did not address the issue. The
requirement to file for conversion within 90 days after commencement of
production in commercial quantities is a provision in the R, D and D
leases. The consequences for failure of an applicant to comply with the
regulations or terms of the R, D and D lease, are stated in the lease
and regulations, and include suspension, bond forfeiture, and/or
cancellation of the R, D and D lease. The penalty for failure to comply
with any of the requirements of section 3926.10 is also a basis for
rejection of an application for conversion. The final rule does not
adopt this comment.
Several commenters expressed concerns about the provisions of
section 3926.10 requiring that an R, D and D lessee submit a one-time
payment equal to or greater than FMV or $1000 per acre. A comment urged
the BLM to abandon the requirement for payment of the FMV for
conversion of an R, D and D lease, in addition to payment of rentals
and royalties, as being inconsistent with Congress' express intention
in enacting the oil shale provisions of the EP Act and as being beyond
the BLM's authority under the MLA. The commenter also recommended that
if the final rule does require payment of FMV in conjunction with an
application for conversion, that the payment be offset against future
royalties from production from the same leasehold. We are not adopting
the commenter's recommendations and we re-emphasize the statements in
the preamble of the proposed rule (73 FR 42939) that, Section 369(o)(2)
of the EP Act requires that payments for leases under that section must
ensure a fair return to the Unites States. Furthermore, the proposed
rule's preamble pointed out that Section 102(a) of FLPMA (43 U.S.C.
1701(a)(9)) requires that the United States receive FMV for the
issuance of Federal mineral leases (73 FR 42940). There is no provision
to credit bonus bids against future royalties, as the bonus bid is
considered part of FMV and the price a potential lessee would pay for
the lease right, in addition to royalties paid on production.
Another comment stated that although it supports the BLM's efforts
to choose an appraisal methodology with a rational basis, in the
interest of fairness and economics, the final rule needs to make a
distinction on the determination of FMV for potential commercial
lessees as compared to FMV determinations for R, D and D lessees
applying for conversion. In drawing the distinction, the commenter
stated that unlike R, D and D lessees, applicants for a commercial
lease offered through the competitive leasing process have not incurred
the same expenses or risks associated with testing and developing
technologies and environmental impacts, and therefore, the FMV for R, D
and D lessees needs modifying in order to account for the risk-adjusted
investment to date. The comment further stated that if an income-based
method is adopted, the net cash flows should include research and
development expenses and capital investments incurred by R, D and D
lessees prior to conversion, plus risk-adjusted rate of return. In
response to this comment, we note that the BLM's process of making FMV
determinations for competitive leasing, as well as FMV determinations
for conversion of an R, D and D lease to a commercial lease, will take
into account the value of the resource, which is a longstanding
practice. Costs associated with developing technology and producing in
commercial quantities are costs of doing business. As we stated in the
preamble of the proposed rule, ``[o]il shale development is
characterized by high capital investment and long periods of time
between expenditure of capital and the realization of production
revenues and return on investment'' (73 FR 42946). While the financial
risks associated with proving technologies is greater than that in
other BLM mineral leasing programs that have established extraction
technologies, the BLM's appraisal process is a systematic approach to
property valuation. The FMV determination will be based on comparison
with identical or similar past, actual, or expected services and goods
relating to oil shale. An R, D and D lessee will also have the
advantage of a right to a noncompetitive commercial lease.
We also received a comment stating that there are seemingly
inconsistent provisions in the proposed rule and Section 23 of the R, D
and D lease relating to the payment of FMV. According to the comment,
section 3926.10(c)(2) provides that the bid payment for the lease must
meet or exceed FMV, while Section 23(a)(2) of the R, D and D lease
requires ``Payment of a bonus based on the Fair Market Value of the
lease, to be determined by the lessor through the rulemaking described
in subsection (b) or other process for obtaining public input.'' The
comment recommended that the words ``or exceeded'' be removed from
section 3926.10(c)(2) and stated that if the BLM must determine FMV for
the lease in advance of conversion, the lessee would never pay an
amount that would exceed that value. We agree that the payment
requirement for an R, D and D lessee should not exceed FMV. We are
therefore adopting the comment and in section 3926.10(c)(2) and have
removed the phrase ``or exceeded'' to be consistent with section
3926.10(b)(3)
[[Page 69440]]
and Section 23(a) of the R, D and D leases.
One commenter stated that the BLM will have no way to assess
whether the bonus payment is equal to the FMV in the absence of a
competitive leasing process for the preference right lease area and
that in such a case, the rule is subject to arbitrary application.
Another comment stated that, although the proposed rule defined the
term FMV, it did not provide any process for determining FMV. The
commenter recommended that the bonus bid amount for conversion of an R,
D and D lease to a commercial lease be determined through an open and
fair process where the BLM and the R, D and D lessee would each select
an appraiser, who would then select a third appraiser if the first two
appraisers disagree. As acknowledged in the preamble to the proposed
rule (73 FR 42939), the BLM recognizes the difficulty in determining a
value for oil shale, a resource that has tremendous potential, but has
not yet proven to be economic to develop. At the time that applications
for conversion of existing R, D and D leases are filed, we anticipate
that more information relating to oil shale will be available in a
variety of areas, including mining methods, market conditions, etc.
Determination of FMV has been a long-established process that exists in
many BLM mineral related programs as well as those that are non-mineral
related, such as rights-of-way. We recognize that Section 102(a) of
FLPMA and Section 369(o) of the EP Act require that the Federal
Government receive a fair return. Although the BLM anticipates that R,
D and D lessees will play a role in providing data to be used in the
appraisal process to determine FMV, the BLM will follow uniform
appraisal standards and will not address in this rule the details of
agency procedures for determining FMV or minimum acceptable bid values.
To do so would ensure that the BLM's minimum bid, or the best estimate
of what the bid should be, would never be exceeded during a competitive
lease sale.
A comment on FMV determination recommended that section 3926.10
should include a provision to allow appeal of the BLM's FMV
determination to the IBLA. Although the section does not include
specific language relating to the right of appeal of the FMV
determination, section 3900.20 addresses appeals and provides that any
party adversely affected by a BLM decision made under parts 3900 and
3910 through 3930 may appeal the decision under 43 CFR part 4. Since
section 3900.20 already covers appeals relating to FMV determinations
under subpart 3926, we are not adopting this comment.
With respect to the consultation provision of section
3926.10(c)(3), a commenter was concerned that the section did not
provide guidance as to the form or result of this consultation. A
similar comment stated that it agreed with the requirement in this
section that an R, D and D lessee consult with state and local
officials to develop a plan for mitigating the socioeconomic impacts of
commercial development on the communities and infrastructure, but that
the final rule should go on to require the BLM to make a determination
that the R, D and D lessee did, in fact consult with state and local
officials. Since the particular provision requires ``documentation that
the lessee consulted with state and local officials,'' the BLM's review
of that documentation will likely result in a determination of whether
or not the consultation did, in fact, occur. For this reason, we are
not adopting the recommendations made in these comments.
We also received another comment relating to the same consultation
provision that recommended that section 3926.10(c) also require
consultation with Federal, state, and local officials on environmental
impacts. The NEPA analysis that is required prior to the conversion of
an R, D and D lease to a commercial lease will address environmental
impacts and will provide the opportunity for public participation. We
are not adopting the comment.
With respect to NEPA analysis, some commenters stated that the BLM
should expand section 3926.10 to clarify that conversion of an R, D and
D lease to a commercial lease is preceded by adequate NEPA analysis.
The commenters did not believe that the requirement of NEPA analysis
was clearly stated in the section. Section 3926.10(a) requires
conversion applicants to meet all requirements in parts 3900, 3910,
3920, excepting those provisions related to the competitive leasing
process, and 3930, including NEPA analysis and the submission of
application information (see final section 3900.50).
With respect to the provision in section 3926.10(c)(5) that the BLM
will approve an application for conversion to a commercial lease if the
commercial scale operations can be conducted, subject to mitigation
measures to be specified in stipulations or regulations, ``without
unacceptable environmental consequences,'' a commenter recommended that
the BLM apply this standard in a manner that is consistent with
guidance set forth in published legal opinions issued by the Solicitor
of the Department and decisions of the IBLA. The comment noted that
FLPMA requires the Secretary to ``take any action necessary to prevent
unnecessary or undue degradation of the lands (43 U.S.C. 1732(b)).''
The comment further noted that based on the Solicitor's Memorandum
Opinion, Surface Management Provisions for Hardrock Mining, M-37007
(October 23, 2001) and the IBLA decision, The Colorado Environmental
Coalition v. The Wilderness Society, 165 IBLA 221 (2005), the FLPMA
standard applies to mineral development on public lands, whether the
rights to conduct such development are created pursuant to a valid
mining claim established under the mining laws or a lease issued under
the MLA, and that it does not authorize the BLM to deny an operation on
public lands that is proposed to be conducted pursuant to the standards
generally applicable to such operations. In noting that ``unacceptable
environmental consequences standard'' is also a provision in Section 23
of the R, D and D lease, the comment further stated that the final rule
should clarify that the BLM will approve an application to convert an
R, D and D lease if the lessee's operations under the proposed
conversion lease will be conducted in a manner that complies with
applicable law or regulations, prudent management and practice, or
reasonable available technology. We adopted the commenter's
recommendation to revise section 3926.10(c) as it relates to applicable
law or regulation. However, we did not adopt the rest of the
commenter's suggestion because the BLM does not regulate management
practices or technology choices unless Federal resources are adversely
affected.
With respect to the lease term of an R, D and D lease, we received
a comment recommending that the term be extended by the time necessary
for the BLM to approve an application for conversion and that the final
rule should clarify that the lease term for an R, D and D lease is not
counted toward the 20-year lease term of a commercial lease, once the
R, D and D lease is converted. We are not adopting this comment since
we believe that it is clear in the regulations that the lease term of a
commercial lease is not dependent upon or connected to the lease term
for an R, D and D lease. Furthermore, section 3926.10 does not address
either the term of an R, D and D lease or the term of a commercial
lease. Once an R, D and D lessee meets the terms and conditions for
conversion, the BLM will
[[Page 69441]]
issue a commercial lease that will be subject to the regulatory
requirements of this final rule, including the lease term.
A commenter made the recommendation that the scope of subpart 3905
Exchanges be expanded to allow R, D and D lessees the opportunity to
exchange their preference right acreage with acreage in alternative
lease sites. The basis for the recommendation is that R, D and D lease
sites and their respective preference areas were designated and granted
long before proper site characterization could be conducted and that R,
D and D lessees should be rewarded for their contributions rather than
``locking them into'' prematurely designated preference areas.
Designation of preference areas has been a key component of the BLM's
R, D and D program. In light of the fact that each R, D and D lessee
was given the opportunity to designate a preference area, and because
upon conversion to a commercial lease there is an opportunity to apply
for a lease exchange, we are not adopting the comment in the final
rule.
One commenter suggested that the BLM should not approve the
development of the same technology on more than one R, D and D lease.
The BLM agrees with the commenter that one technology can be used to
convert only one lease and not multiple leases. For example, if one
entity held multiple R, D and D leases, each approved for the use of a
different technology, that entity would not be allowed to perfect the
technology to convert one lease and then use that same technology to
convert the other leases. That would be contrary to the intent of the
program, which is to encourage research, development, and demonstration
of oil shale technologies. The BLM will approve a lessee's application
to convert the R, D and D lease to a commercial lease and acquire the
preference right lease only if the lessee complies with the terms of
the lease. The commenter also suggested that a preference right
commercial lease should not be granted in association with an R, D and
D lease unless the prospective lessee uses the technology that was: (1)
Approved in a development plan; and (2) Tested on the associated R, D
and D lease. The BLM agrees with the suggestion, because the R, D and D
leases are meant to be technology-specific, meaning that a lease is
granted for the sole purpose of testing and proving a particular
technology, but with the knowledge that the BLM retains the flexibility
to approve changes or modifications to proposed technology and the POD.
Another commenter suggested that ``if technology is demonstrated on
the BLM RD [lease] that was not proposed in the BLM RDD [lease]
application then no conversion is possible, and furthermore that
technology not proposed shouldn't have been allowed to be demonstrated
on the BLM RDD lease either.'' This commenter further stated ``in order
to acquire the contiguous acreage and convert to a commercial lease,
the lessee would be required to demonstrate to the BLM that the
technology tested on the original lease would have the ability to
produce shale oil in commercial quantities.'' The BLM does not agree
with the first part of the comment that stated if technology is
demonstrated on the BLM R, D and D lease that was not proposed in the
R, D and D lease application then no conversion is possible and that
technology not proposed shouldn't have been allowed to be demonstrated
on the lease. These propositions are inconsistent with the terms of the
R, D and D lease. In fact, the BLM believes that the terms of the R, D,
and D leases anticipate that changes in the technology or the R, D and
D development plan may occur; hence we designated the leases as R, D
and D leases. For instance, where a lessee assigns its lease to another
entity, under the terms of an R, D and D lease, the assignee may obtain
BLM's approval to substitute the research, development, and
demonstration of another technology not currently being utilized in the
Green River Formation. Furthermore, Section 8 of the lease requires
that ``the operator must submit to the authorized officer an
exploration, mining plan, or in situ development plan describing in
detail the proposed exploration, prospecting, testing, development or
mining operations to be conducted'' and states that ``after plan
approval, the Lessee must obtain the written approval of the authorized
officer for any change in the plan approved under subsection (a).''
Finally, Section 23(a) of the R, D and D lease states ``the Lessee
shall apply for conversion of the research, development and
demonstration lease to a commercial lease no later than 90 days after
the commencement of production in commercial quantities. The Lessee
shall have the exclusive right to acquire any or all portions of the
preference lease area for inclusion in the commercial lease, up to a
total of 5,120 contiguous acres, upon (1) documenting to the
satisfaction of the authorized officer that it has produced commercial
quantities of shale oil from the lease.'' In other words, the lease
terms require the lessees to perfect the technology approved in the R,
D and D exploration, mining, or development plan for which the lease
was granted in order to obtain the preference right lease acreage to
that lease.
The BLM agrees with the commenter that the terms of the lease allow
the lease to convert to a commercial lease and acquire the contiguous
acreage upon commencement of production in commercial quantities.
Subpart 3927--Lease Terms
Sections in this subpart address lease form, lease size, lease
duration, effective date of leases, diligent development, and
production.
Section 3927.10 provides that the BLM will issue oil shale leases
on a standard form approved by the BLM Director. This section mirrors
similar requirements in other BLM mineral leasing regulations.
Section 3927.20 sets the maximum oil shale lease size at 5,760
acres, which is the maximum size authorized under Section 369(j) of the
EP Act. The maximum lease size contained in this section is not
discretionary since it was established by statute (see Section 369(j)
of the EP Act)). One commenter on the proposed rule requested that the
maximum size for an R, D and D lease should be increased to 5,760 acres
from 5,120 acres to reflect the EP Act. The existing R, D, and D leases
were offered prior to passage of the EP Act and contain the maximum
lease acreage allowable at the time under the MLA of 5,120 acres.
Revising the maximum acreage for an R, D and D lease in the rule would
create an inconsistency between the rule and existing R, D and D lease
terms. Section 369(j) of EP Act allows the BLM to issue leases up to
5,760 acres, but gives the BLM discretion to issue leases with less
acreage, therefore, the BLM has not made this change in the final rule.
In the final rule we revised section 3927.20 by removing the
minimum lease size requirement for oil shale leases. Please see the
discussion of comments under the Regulatory Flexibility Act discussion
in the procedural matters section for this rule for an explanation of
the change.
The proposed rule specifically asked for comment on whether or not
the final rule should include provisions for the establishment of
logical mining units (LMU) for oil shale leases. We received several
comments on whether the regulations should provide for LMUs. A
commenter recommended that the BLM amend the proposed rule to
incorporate provisions for consolidation of leases ``in order to
enhance efficiency of development by reducing capital and operating
costs while at the same time maximizing recovery of the private
[[Page 69442]]
resource which might otherwise go undeveloped.'' Another commenter
stated that it believes that there are legal, environmental, and policy
reasons for the regulations to promulgate a rule on LMUs, similar to
the BLM's coal program, and there is no public policy rationale to
defer promulgation. The commenter contended that the preamble
discussion of the proposed rule frequently identifies the Federal coal
leasing regulations as a model for many of the provisions and that ``in
spirit of consistency and governmental alignment,'' it recommends that
the BLM adopt the same three preconditions which must be satisfied for
lease consolidation: ``single operator, single operation, and
continuity.'' Additionally, the commenter noted in the case of an R, D
and D lessee holding several leases, if the lessee had the ability to
consolidate multiple leases into an LMU type of project, which
cumulatively might produce several projects, the surface disturbance at
a given time would be minimized. The comment went on to state that
additionally, ultimate recovery of the resources should be greater as
the single operation could operate up to and across lease boundaries
without the constraint of artificial boundary lines, and reclamation of
the surface should be more effective and successful. Another comment
expressed the viewpoint that it seems premature to incorporate
provisions for LMUs when there currently are no standardized extraction
methods and no history of production to determine if regulatory
provisions are necessary. The comment further stated that there will
likely be no need for LMUs if future oil shale development utilizes in
situ, or in place technology, but if future development resembles a
coal operation in terms of surface mining or subsurface mining, then
LMU provisions could be adopted to resemble the coal program. The BLM
interprets these comments as a recommendation to establish a mechanism
similar to that of a coal LMU. As defined in the coal leasing
regulations at 43 CFR 3480.0-5(a)(19), ``Logical mining unit (LMU)
means an area of land in which the recoverable coal reserves can be
developed in an efficient, economical, and orderly manner as a unit
with due regard to conservation of recoverable coal reserves and other
resources.'' The BLM supports the establishment of logical mining units
that consolidate and make operations more efficient, but we do not
understand how oil shale development that does not yet have
standardized extraction methods, and may have operations with different
diligence requirements, can be effective. It is the BLM's position that
establishing a mechanism similar to a LMU is not warranted at this
time. After the methods for developing oil shale are better
established, if the BLM determines that the creation of a mechanism
similar to an LMU is warranted, the BLM would then pursue rulemaking to
adopt this recommendation. Therefore, no provisions for the
establishment of LMUs are included in the final rule.
Section 3927.30 provides that an oil shale lease will be for a
period of 20 years and so long thereafter as the condition of annual
minimum production is met. Section 21 of the MLA (30 U.S.C. 241(a)(3))
authorizes issuance of oil shale leases for ``indeterminate periods.''
The BLM chose a 20-year period for the original lease term for ease of
administration because Section 21 of the MLA (30 U.S.C. 241(a)(4))
specifies that the royalty rate for leases should be subject to
readjustment at the end of each 20-year period. Lease readjustment is
common to other BLM mineral leasing programs, including coal and
certain non-energy leasable minerals. The final section also contains a
requirement that the operator and lessee notify the BLM of changes in
names or addresses. That requirement was relocated from section
3936.20(c) of the proposed rule.
Section 3927.40 identifies the effective date of the lease and the
process used to determine the effective date of the lease. This section
is similar to regulations on the effective dating of leases under the
BLM's coal program.
Section 3927.50 requires lessees to meet diligent development
milestones and annual minimum production requirements. The BLM
considers continued minimum annual production a necessary part of
diligent development of the lease. This requires that a company
continue to produce the minimum annual requirement or make payments in
lieu of production in order to hold the lease. Diligent development is
a component of other mineral leasing programs such as coal and oil and
gas and is required under Section 369(f) of the EP Act.
Part 3930--Management of Oil Shale Exploration Licenses and Leases
Sections in this part address the requirements for exploration
licenses and for leases related to: general performance standards,
operations, diligent development milestones, PODs and exploration
plans, lease modifications and readjustments, assignments and
subleases, relinquishments, cancellations and terminations, production
and sale records, and inspection and enforcement.
Sections 3930.10 through 3930.13 explain the performance standards
for exploration, development, production, and the preparation and
handling of oil shale under Federal leases and licenses. Additional
standards may be required at the time of lease issuance and as
operations proceed. The BLM used the coal program as basis for many of
the performance standards for these sections because of the similarity
of the mining and exploration methods and the possible impacts
associated with those methods. The performance standards for in situ
operations were derived from aspects of the standards used for
exploration and standards applicable to the BLM's oil and gas program.
Section 3930.20 establishes the standard operating requirements for
the development of an oil shale lease, including requirements
concerning the MER of the resource, how to report new geologic
information, and the compliance with Federal laws. The section also
addresses measures necessary to protect resources, including proper
disposal and treatment of solid wastes. These operational requirements
are common to other BLM mineral leasing programs.
Section 3930.30 lists the milestones for diligent development of an
oil shale lease. The requirement for establishing milestones is in
Section 369(f) of the EP Act. The BLM determined that the milestones
should be the series of steps necessary for the development of the oil
shale. Defining milestones this way is logical because the steps are
necessary to begin production and the BLM believes the requirements
will encourage development. This section requires a lessee to meet the
following five diligent development milestones:
(1) Within 2 years of lease issuance, submit to the BLM a proposed
POD which would meet the requirements of subpart 3931;
(2) Within 3 years of lease issuance, submit a final POD;
(3) Within 2 years after the BLM approves the POD, apply for all
required permits and licenses;
(4) Before the end of the 7th lease year, begin permitted
infrastructure installation, as described by the BLM approved POD; and
(5) Begin production by the end of the 10th lease year.
Each of the milestones in this section is an opportunity for the
lessee or operator to fulfill the statutory requirements and provide
evidence of
[[Page 69443]]
its commitment to diligent development of the resource.
The BLM received several comments indicating the need to recognize
that milestones may not be achieved due to time delays that are not
within the control of the operator or lessee such as NEPA delays and
delays in acquiring permits from the BLM and other agencies. Several
comments suggested the need for establishing maximum time limits for
government processing of permit applications as a solution to BLM
permitting delays. Placing time constraints on the analysis of oil
shale permitting may not allow for a thorough, comprehensive, and
legally defensible analysis of the application. The suggestion to have
an automatic extension of time if the BLM does not meet a processing
deadline does not address those instances when other Federal or state
agencies are the cause of the delay. Final section 3930.30(b) allows
the BLM to grant additional time to complete milestones and therefore,
we did not revise the rule to impose time limits for BLM processing.
The BLM received comments questioning the need for milestones,
suggesting that deadlines are arbitrary, and that diligence should be
established based on good faith efforts. The EP Act specifically
required establishing a commercial leasing program that contained
milestones. The proposed and final rules incorporate the milestones as
part of a diligent development scenario. The requirement for diligent
development is not unusual. Other BLM mineral leasing programs such as
the coal program have a diligent development component as part of their
operating regulations. Diligent development requirements are necessary
to encourage development and prevent speculation. The BLM based each
milestone on the normal sequence of development that a company would
follow to proceed from lease acquisition, through development, to
production. The time required to accomplish each milestone is based on
the typical development schedules for other minerals and the proposed
development schedules that companies submitted as part of the R, D and
D nomination process. The BLM rejects the suggestion that diligence be
based on good faith efforts. This standard is too vague for a
regulatory provision and could cause implementation problems.
The BLM received comments stating that the milestones are too weak
and do not result in screening out operators that have no intention of
going into production. The BLM's milestones were created to ensure that
an operator will be diligently developing the lease. As stated above,
the milestones are based on typical development schedules for other
minerals and the schedules that companies submitted as part of the R, D
and D nomination process, and, therefore, we believe they are
reasonable. The BLM believes the payment we may assess for missing a
milestone will encourage development and discourage speculation.
One commenter suggested that due to the tight time-frames
associated with the milestones, exploration will most likely have to
occur prior to nominating an area for leasing under an exploration
license. The BLM agrees that most exploration should take place prior
to nominating an area for leasing. The regulations do, however, allow
the lessee to further explore under an exploration plan or POD once the
lease is issued.
Several comments pertained specifically to section 3930.30(a)(4)
Milestone 4, which states that before the end of the 7th year after
lease issuance, the lessee must begin infrastructure installation, as
required by the BLM approved POD; and section 3930.30(a)(5) Milestone
5, which states that before the end of the 10th year after lease
issuance, the lessee must begin oil shale production. The commenters
were concerned that both milestones are dependent on acquiring needed
permits in a timely manner and that action and reviews by regulatory
agencies are not under the control of the lessee and may be very time
consuming. Section 3930.30(b) recognizes the need to account for delays
beyond the control of the operator and provides the BLM the ability to
grant additional time to complete each milestone.
The BLM received comments concerning the requirement to begin
production prior to the end of the 10th lease year. Some commenters
stated that the milestone is unnecessary since, once infrastructure is
in place, it is unlikely that a lessee will let a multi-million dollar
investment sit idle and therefore the requirement should be deleted.
Other commenters suggested that the regulations should allow production
to begin at a later date and suggested 15 years after lease issuance,
or as an alternative, as soon as practicable. The BLM believes that the
requirement to begin production prior to the end of the 10th lease year
is necessary to insure that companies will diligently pursue
development and will continue to produce once the operation is capable
of commercial production. Section 3930.30(b) allows the BLM to grant
additional time to complete the milestones, so there is no need to
alter the 10th year requirement or use a less prescriptive standard
such as ``as soon as practicable.''
The BLM received comments suggesting revision of section
3930.30(a)(4) to acknowledge that delays in permitting may cause delays
in infrastructure installation. We addressed the comment by revising
section 3930.30(a)(4) to acknowledge that construction of
infrastructure may not begin before approved permits have been issued.
The BLM received comments indicating a need to clarify how the
impacts of the possible delays would affect each milestone. Although
the proposed regulations anticipated the need to account for delays
that are beyond the control of the operator and provided a mechanism at
section 3930.30(b) to address those delays, the proposed rule was
unclear as to how the allowable extensions of time would affect
subsequent milestones. Milestones 1 and 2 pertain to the submittals
that are under the control of the operator and not dependent on the
timing of other agencies decisions. Milestone 3 allows a lessee 2 years
to apply for permits, although a prudent operator would likely apply
before or immediately after their POD was approved. Milestones 4 and 5
are dependent, to some extent, on timely processing by agencies, and an
extension of time applied to milestone 4 would likely force the need to
extend the 10 year production deadline in milestone 5. To clarify how
the BLM would address this if an application for a milestone 4
extension is approved, section 3930.30(b) is revised to provide that
allowable time extensions to meet milestone 4 will extend the
requirement to begin production in the 10th lease year by an amount of
time equal to the extension granted for milestone 4. We also added a
sentence to paragraph (b) to explain that any extension made under this
section also extends the requirements for payments in lieu of
production and minimum production under paragraphs (c), (d), and (e) of
this section.
It should also be noted that under certain conditions the BLM may
grant suspensions that toll diligence and other lease requirements (see
section 3931.30).
The requirement to maintain production under an approved POD is
also in this section. Although it is not a milestone, the BLM will
require yearly production as part of the diligent development of the
lease. This section also allows payments in lieu of production to meet
the requirement of yearly production. Minimum annual production is
required starting the 10th
[[Page 69444]]
year of the lease unless the lease has been suspended or the BLM has
approved an extension of diligence milestone 4. Payment in lieu of
production in year 10 of the lease satisfies the milestone requiring
production by the end of the 10th year of the lease.
Section 3930.40 identifies the assessments for not achieving the
required milestones. The proposed regulation included a civil penalty
of $50 per acre per year for each missed milestone. In response to
comments, the BLM agrees that there is no specific statutory authority
to impose civil penalties for missed milestones. The final rule
therefore provides for assessments to serve as liquidated damages for
the costs, damages, and delays of income that the BLM would otherwise
not have suffered. Under this rule, the BLM will assess $50 per acre
for each missed diligence milestone for each year, prorated to daily
assessments until the operator or lessee reaches the diligence
milestone. The rule thus retains the $50 per acre per year that was in
the proposed regulations, but the proration to daily assessments more
accurately reflects the BLM's additional costs of administering the
lease and the government's increased risk of delays in receiving
royalty payments. Larger leases would face larger daily assessments in
part because the government's expected royalty receipts are higher from
larger leases. The assessments also provide incentives for diligent
development of the resource and should discourage speculation.
We received comments indicating that the proposed penalties were
not high enough and should mirror the oil and gas regulations, which
allow for fines as high as $25,000 per day and also include criminal
penalties. There is no statutory authority for the BLM to impose civil
or criminal penalties for noncompliance with the regulations. The
assessment that the BLM is imposing will serve as non-penal
compensation for the BLM's increased costs and expenses of
administering the lease, and for loss of timely royalty income caused
by the lessee's lack of diligence as demonstrated by failure to meet
the milestones.
Subpart 3931--Plans of Development and Exploration Plans
Sections in this subpart provide requirements for submission of a
plan of development (POD) (section 3931.10), required contents of a POD
(section 3931.11), reclamation of all disturbed areas (section
3931.20), suspending operations and production on a lease (section
3931.30), exploration on a lease prior to POD approval (section
3931.40), information to be included in the exploration plan (section
3931.41), modification of exploration or development plans (section
3931.50), maps of underground and surface mining workings and in situ
surface operations (section 3931.60), production reporting (section
3931.70), geologic information (section 3931.80), and boundary pillars
and buffer zones (section 3931.100).
Section 3931.10 requires submission of a POD that details all
aspects of development of the resource and protection of the
environment, including reclamation. It also identifies the need for a
similar plan for exploration activities. The POD is a key document that
details the specifics of all activities associated with developing or
exploring the lease. Section 3931.10(d) has been edited for clarity.
The BLM may require additional information or changes to the plan
before it can be approved. The BLM may disapprove a plan, in which case
it will explain why disapproval was necessary. In response to comments
concerned about mitigation of specific impacts of development, we have
revised section 3931.10(f) to make it clear that appropriate NEPA
analysis is required prior to exploration plan or POD approval.
Section 3931.11 lists and describes the contents of a POD. Some of
the contents include a general description of geologic conditions and
mineral resources, maps or aerial photography, proposed methods of
operation and development, public protection, well completion reports,
quantity and quality of the oil shale resources, environmental aspects,
reclamation plan, and the method of abandonment of operations. The
information in the POD is necessary so that the BLM can review the plan
and ensure that operations, production, and reclamation will occur
consistent with Federal law and regulation and to ensure the protection
of the resource and the environment through appropriate NEPA analysis
and resulting mitigation measures. In the final rule we added a new
paragraph (d)(11) to section 3931.11 that requires that a description
of the methods used to dispose of and control mining waste be included
in the statement of the proposed methods of operation and development.
In the final rule we also added a definition of the term ``mining
waste'' to the definitions section. The reason for revising this
section and adding the new definition is discussed in the preamble
discussion of the definitions section of this rule.
Section 3931.20 describes the requirements for reclamation of all
disturbed areas under a lease or exploration license. This section is
similar to requirements in other BLM mineral program regulations for
prompt reclamation of disturbed areas. Several commenters expressed
concern with the reclamation provision in section 3931.20 (a) of the
proposed rule where the BLM states that the operator or lessee must
reclaim the disturbed lands to their pre-mining or pre-exploration use
or to a BLM-determined higher use. Commenters suggested that ``BLM-
determined higher use'' should be removed and another commenter
expressed concerns that the provision could require the applicant to
perform more expensive reclamation than what would be required to
reclaim the disturbed area to pre-mining or pre-exploration levels. The
BLM agrees that the phrase is not very specific and could have a
negative impact on the lessee or operator. In the final rule we revised
section 3931.20(a) to state that the operator or lessee must reclaim
the disturbed lands to their pre-mining or pre-exploration use, or to a
higher use, as agreed to by the BLM and the lessee.
Section 3931.30 details the requirements for suspending operations
and production on a lease. Under this section, if the BLM determined it
was in the interest of conservation, it may order or agree to a
suspension of operations and production. If the BLM approved the
suspension, the lessee or operator would be relieved of the obligation
to pay rental, to meet upcoming diligent development milestones, or to
meet minimum annual production, including payments in lieu of
production. The term of the lease would be extended by the amount of
time the lease is suspended. The need to suspend operations is well
established and similar provisions are found in other BLM mineral
leasing regulations.
Section 3931.40 provides the requirements necessary for the BLM to
authorize exploration on an exploration license or on a lease prior to
POD approval. Often, exploration is necessary after lease issuance to
acquire the geologic information necessary to prepare a POD.
Section 3931.41 lists the information required for an exploration
plan. The information required is similar to that required in other BLM
mineral programs and is necessary for adequate evaluation of the
proposed exploration activities and the measures needed to mitigate
environmental impacts in accordance with applicable laws. We received
comments suggesting that the rule is inconsistent in that this section
requires
[[Page 69445]]
information on vegetative cover, but the information is not required
for PODs. Information on vegetative cover is usually obtained at the
preleasing stage, so it is not usually needed again at the POD stage.
The BLM requires information on vegetative cover for exploration plans
because it is possible that the exploration is proposed on unleased
lands that have never been analyzed for exploration under NEPA. The
commenter also asked if the vegetative cover requirement would be used
as a reclamation standard. The NEPA analysis that will be completed
prior to exploration or development of oil shale will determine what
reclamation standards or levels of mitigation related to vegetative
cover would be required.
We received several comments suggesting that prospective licensees
provide information on potential impacts on National Park Service
units. There is no need to require additional information to
specifically address National Park Service lands since potential
impacts on all lands affected by the exploration will be analyzed and
mitigation measures addressed in the required NEPA document that
evaluates the proposed action. We made no change to this section as a
result of this comment.
Section 3931.50 explains how the operator or lessee may apply for a
modification of exploration or development plans to address changing
conditions and situations that might develop during the course of
normal exploration activities or to correct an oversight. This section
also explains that the BLM may, on its own initiative, require
modification of a plan. Finally, this section explains that the BLM may
approve a partial exploration plan or POD in circumstances where
operations are dependent on factors that would not be known until
exploration or development progresses. These modification provisions
are similar to those in other BLM minerals programs. We received
several comments suggesting that the BLM should expand the reasons for
modifying exploration or development plans to include ``new
information, improved methods, and technology.'' The BLM agrees with
the suggestion and in the final rule we revised section 3931.50(a) to
include ``new information, improved methods, and new or improved
technology'' in the list of reasons that the BLM will consider
modification of an exploration plan or POD.
Section 3931.60 contains information relating to the format and
certification of required maps of underground and surface mining
workings and in situ surface operations. These maps are necessary for
the BLM properly to assess the potential impacts associated with
exploration and mining.
Section 3931.70 explains the requirements for production reporting,
the associated maps and surveys for mining operations, and maps showing
the measurement systems for in situ operations. This section requires
accurate maps and production reports and explains the requirements for
production reporting. These are necessary requirements for the Federal
Government to track lease production accurately. We received several
comments that indicated that the timeframes for reporting production
and exploration were too short and suggested quarterly reporting with
submittals no later than the end of the quarter. For comparison
purposes, the production reporting period for coal and for oil and gas
is monthly. Oil shale production methodology ranges from methods that
closely resemble the coal program to methods that are more similar to
oil and gas operations. To account for the variance in the methods, we
revised the reporting period to more closely align the reporting
requirements with those of the coal program. In the final rule, the
reporting period is quarterly, with the submittals no later than 30
days after the end of the reporting period.
We received several comments asking for clarification of the
requirement to report production of all oil shale products and by-
products. The commenter is not clear what products and by-products to
which it is referring. The requirement to report production is a
requirement of all of BLM's mineral leasing programs. Verification of
reported production and sales are necessary components of the royalty
collection program. The term ``oil shale products and by products''
means all salable products derived from the mining and retorting or in-
situ extraction and processing of oil shale. Potential products or by-
products may include oil, gas, sulfur, raw shale, spent shale, CO2,
ammonia, and produced water. At this point in time it is not possible
to know all of the possible salable products; however, as required by
subpart 3935 of this rule, all products that are produced for sale and
all products that are sold must be reported. The intent of production
reporting is to ensure that the production volumes of various products
and by-products can be accounted for at all points in the production
process. For example, an underground oil shale mining operation with a
surface retort is required to report under subpart 3935 of these
regulations the volume of raw shale that is mined or removed from the
mine for further processing. All volumes entering the retort must
balance with all volumes mined and reported to the BLM. Additionally,
since there most likely will be volumes of various gaseous materials
being produced and ultimately sold, these volumes must also be
reported. We did not revise this section as a result of these comments.
Section 3931.80 addresses requirements for handling geologic
information resulting from exploration activities. Additional
requirements related to abandonment operations, well conversions, and
blow-out prevention equipment are also addressed in this section. This
section contains requirements similar to those in the BLM's oil and gas
operations regulations.
Several comments indicated that the timeframes for reporting core
hole results were too short and suggested quarterly reporting, with
submittals no later than 90 days after the end of the quarter. The BLM
agrees that analysis of the cores may take more time than originally
estimated and that reporting the results no later than 90 days after
the end of the exploration is a more realistic requirement. Therefore,
in the final rule we revised section 3931.80 so that it requires that
the operator or lessee submit to the BLM records of all core or test
holes within 90 calendar days after drilling completion.
Section 3931.100 details the standards for boundary pillars and
provisions to protect adjacent lands. This section allows for the
recovery of the pillars if the operator provides evidence to the BLM
that the recovery activities will not damage the Federal resource or
those of the adjacent lands. These provisions are similar to those in
the BLM's coal program.
The BLM received comments suggesting that the final rule should
state that the boundary pillar provision should only apply to
underground mining operations. The BLM agrees with the commenter that
boundary pillars should only apply to underground mining. However, the
BLM also believes that it is necessary to create buffer zones for in
situ operations. Both the boundary pillars and buffer zones are
necessary to protect against any unauthorized removal of oil shale
resources from Federal lands by surrounding operations without adequate
compensation to the taxpayers. Under in situ operations, oil shale
formation fractures allow energy and fluid migration, and without the
buffer zone, fluid could migrate across lease lines only to be captured
by adjacent
[[Page 69446]]
operations. Therefore, the BLM has revised final section 3931.100(a) to
make it clear that boundary pillars and the buffer zones apply to
underground mining and in situ operations, respectively.
Subpart 3932--Lease Modifications and Readjustments
Sections in this subpart provide requirements for lease size
modification, (section 3932.10), availability of lands for a lease
modification (section 3932.20), terms and conditions of a modified
lease (section 3932.30), and the readjustment of lease terms (section
3932.40).
Section 3932.10 provides the requirements for lease size
modifications and is similar to sections in the other BLM mineral
program regulations. This section explains that the lands in the
modified lease must not exceed the acreage limitation in section
3927.20. The section also explains what items are necessary for a
complete application, including the filing fee and qualifications
statements. One commenter requested that we add a provision to this
section requiring NEPA review for modification of a lease. The final
rule addresses the NEPA issue at section 3932.20(c). Therefore, the
final rule is not revised as a result of this comment.
Section 3932.20 explains the conditions under which the BLM would
grant a lease modification, and that the BLM may approve the
modification (adding lands to the lease) if there is no competitive
interest in the lands. This section explains that before the BLM will
approve a modification application, the applicant must pay the FMV (or
bonus bid) for the interest to be conveyed. This section also makes it
clear that the BLM will not approve a lease modification prior to
conducting the appropriate NEPA analysis and receipt of the processing
costs.
Section 3932.30 provides that the terms and conditions of any
modified lease will be adjusted so that they are consistent with law,
regulations, and land use plans applicable at the time the lands are
added by the modification. The BLM revised section 3932.30(b) to
clarify that the royalty rate of the new lease is the same as that in
the lease that is being modified. This change will prevent confusion
where lease rates have been readjusted. Bonding and lessee acceptance
requirements are also addressed in this section. This section is
similar to those in other BLM minerals program regulations.
Section 3932.40 provides that all oil shale leases are subject to
readjustment of lease terms, conditions, and stipulations, except
royalty rates, at the end of the first 20-year period (the primary term
of the lease) and at the end of each 10-year period thereafter. Royalty
rates are subject to readjustment at the end of the primary term and
every 20 years thereafter. The procedures for the readjustment of the
lease are detailed in this section. Under this section, the BLM will
provide the lessee with written notification of the readjustment. This
section also allows lessees to appeal the readjustment of lease terms.
One commenter recommended that the BLM should allow for the adjustment
of the lease terms at more frequent intervals than the 20 year
statutory period to allow for compensation for unknown production and
mining techniques. One commenter recommended that the lease terms
remain certain for the life of the lease. Another commenter recommended
that the royalty rate adjustment should be subject to the same time
periods as other lease terms. One commenter stated that if the royalty
rate is adjusted after 20 years, it will create uncertainty and that
would discourage investment. One commenter stated that there are no
criteria by which a lessee can identify under what conditions or to
what extent the lease terms may be adjusted.
The BLM did not revise the final rule as a result of these
comments. The MLA (30 U.S.C. 241(a)(4)) only provides the BLM the
authority to readjust the royalty rate at the end of the primary term
and then every 20 years after that. Readjusted royalty rates will be
set at the regulation rate in effect at the time of readjustment. The
public will have the opportunity to comment as part of the rulemaking
process on any future changes to the royalty rate set by these
regulations.
Subpart 3933--Assignments and Subleases
Sections in this subpart address various requirements related to
assignments or subleases of record title (section 3933.31) and
overriding royalty interests (section 3933.32). This subpart also
addresses requirements for:
(1) Assigning or subleasing leases or licenses in whole or part
(section 3933.10);
(2) Filing fees (section 3933.20);
(3) Account status and assumption of liability (section 3933.40);
(4) Bonding (sections 3933.51);
(5) Continuing responsibility (section 3933.52);
(6) Effective date (section 3933.60); and
(7) Extensions (section 3933.70).
The sections in this subpart are similar to the regulatory
requirements of BLM's other mineral leasing programs.
The BLM received a comment suggesting that exploration licenses be
assignable. We agree. Therefore, provisions for assigning licenses are
included in this subpart.
Section 3933.10 now provides that all leases may be assigned or
subleased, and all exploration licenses may be assigned, in whole or in
part to any person, association, or corporation as long as the
qualification requirements are met. Section 30 of the MLA requires an
assignee to obtain BLM approval for an assignment.
Section 3933.20 requires payment of a $60 non-refundable filing fee
for processing an assignment, sublease of record title, or overriding
royalty. The filing fee is the same fee required by the coal
regulations for filing an assignment. The BLM anticipates that
assignment, sublease of record title, or overriding royalty activities
associated with an oil shale lease or license will be similar to the
same activities in the BLM's coal program, and therefore believes the
same filing fee is justified.
Section 3933.31 requires that assignment applications be filed with
the BLM within 90 days of the date of final execution of the
assignment, and lists what must be included in the assignment
application, including the filing fee. This section also explains that
the assignment of all interests in a specific portion of a lease or
license creates a separate lease or license. We received one comment on
this section, which recommended that the section also address standards
for assignments of operating rights. We interpret this comment as
recommending that the regulations separately list all information that
BLM requires in conjunction with an application for approval of an
assignment of operating rights. Standards for approval of assignments
are already covered by section 3933.31(b), which also requires
assignees to meet the qualification standards set forth under subpart
3902. In addition, sections under this subpart that apply to
assignments address overriding royalty interest, lease account status,
bond coverage, and continuing responsibility of assignors. We are
therefore not adopting this comment.
Section 3933.32 explains that overriding royalty interests do not
have to be approved by the BLM, but will be required to be filed with
the BLM. The filing of overriding royalty interests provides a more
complete record of the financial transaction affecting the Federal
lease. The BLM has found this
[[Page 69447]]
information to be useful in other mineral leasing programs, especially
in making rent and royalty reduction determinations.
Section 3933.40 requires that the lease or license account be in
good standing before the BLM will process an assignment.
Section 3933.51 requires that assignees have sufficient bond
coverage before the BLM will approve the assignment. This is a
necessary component of the bonding program and is similar to
requirements of other BLM solid mineral leasing programs.
Section 3933.52 addresses the responsibilities, obligations, and
liabilities of the assignor and assignee. In addition to stating
expressly that an assignor is responsible after an assignment for
accrued obligations, this section addresses joint and several
liabilities of the lessee and operating rights owner. After the
effective date of the sublease, the sublessor and sublessee are jointly
and severally liable for the performance of all lease obligations,
notwithstanding any term in the sublease to the contrary.
Section 3933.60 explains that the effective date of an assignment
and sublease is the first day of the month following the BLM's final
approval, or if the assignee requested it in advance, the first day of
the month of the approval. This is the customary effective date for an
assignment in other BLM leasing programs.
Consistent with other BLM mineral leasing programs, section 3933.70
provides that the BLM's approval of an assignment or sublease does not
extend the term or readjustment period of the lease or the term of the
license.
Subpart 3934--Relinquishments, Cancellations, and Terminations
Sections in this subpart contain requirements for relinquishments
(section 3934.10), termination of leases and cancellation and/or
termination of exploration licenses (section 3934.30), written notice
of default (section 3934.21), cause and procedures for lease
cancellations (section 3934.22), payments due (section 3934.40), and
bona fide purchasers (section 3934.50). Sections in this subpart are
similar to sections found in regulations for other BLM mineral leasing
programs.
Section 3934.10 provides that the record title holder of a lease
may relinquish all or part of the lease if the requirements in this
section are met. This section also contains provisions for the
relinquishment of an exploration license. Prior to relinquishment, the
licensee must give any other parties participating in the exploration
license an opportunity to take over operations under the exploration
license. We received a comment expressing concern that this section
allows a record title holder to relinquish a lease without approval
from an owner of a working interest in the lease. According to the
commenter, this section should be modified to require consent from any
owner of any working interest (operating rights) associated with a
lease in order to avoid the risk that the lease may be relinquished
without its knowledge. With respect to working interests or operating
rights, the BLM is not a party to an agreement between a lessee and a
party holding a working interest in the lease. Because the contractual
agreement is strictly between the lessee and the holder of the working
interest, it is not appropriate for the BLM to impose the requirement
on the lessee that a holder of a working interest must provide consent.
We are therefore not adopting this comment.
Section 3934.21 requires the BLM to notify the lessee or licensee
in writing of any default, breach, or cause of forfeiture, and the
corrective actions that could be taken to avoid defaulting on the lease
terms and lease cancellation.
Section 3934.22 explains the procedure for the BLM to cancel a
lease. Section 31 of the MLA requires that lease cancellation take
place in the United States District court for the district in which all
or part of the lands covered by the lease are located.
Section 3934.30 provides the reasons that the BLM may terminate a
license, including:
(1) The BLM issued it in violation of law or regulation;
(2) The licensee is in default of the terms and conditions of the
license; and
(3) The licensee has not complied with the exploration plan.
Unlike leases, the BLM may terminate an exploration license
administratively.
Section 3934.40 provides that if a lease is canceled or
relinquished for any reason, all bonus, rentals, royalties, or minimum
royalties paid will be forfeited and any amounts not paid would be
immediately payable to the United States.
Section 3934.50 addresses the rights of bona fide purchasers and
provides that the BLM will not immediately cancel a lease or an
interest in a lease if, at the time of purchase, the purchaser could
not reasonably have been aware of a violation of the regulations,
legislation, or lease terms.
Subpart 3935--Production and Sale Records
Section 3935.10 addresses books of account. Operators and lessees
must maintain accurate records. This section explains what records must
be maintained, and that the records must be made available to the BLM
during normal business hours.
Subpart 3936--Inspection and Enforcement
Like other BLM minerals inspection and enforcement (I and E)
programs, the objective of BLM's oil shale I and E program is to:
(1) Ensure the protection of the resource;
(2) Ensure that Federal oil shale resources are properly developed
in a manner that would maximize recovery while minimizing waste; and
(3) Ensure the proper verification of production reported from
Federal lands.
The BLM is also responsible for lease inspections to determine
compliance with applicable statutes, regulations, orders, notices to
lessees, PODs, and lease terms and conditions. These terms and
conditions include those related to drilling, production, and other
requirements related to lease administration.
This subpart addresses inspection of underground and surface
operations and facilities (section 3936.10), issuance of notices of
noncompliance and orders (section 3936.20), enforcement of notices of
noncompliance and orders (section 3936.30), and appeals (section
3936.40).
Section 3936.10 requires operators or lessees to allow the BLM to
inspect underground or surface mining and in situ operations and
facilities and exploration operations at any time both to determine
compliance with the POD and to verify oil shale production.
Section 3936.20 advises the operator, licensee, or lessee of the
procedures the BLM follows when issuing orders and notices of
noncompliance. The section also addresses delivery of notices and
verbal orders. The proposed section had required lessees and operators
to notify the BLM of any change of name or address. That requirement
has been moved from section 3936.20(c) to sections 3927.30 for leases,
and 3910.40 for licenses.
Section 3936.30 explains the procedures the BLM follows when
enforcing notices of noncompliance. This section explains the action
the BLM may take in cases of noncompliance, including orders to cease
operations and the initiation of lease or license cancellation or
[[Page 69448]]
termination procedures. An example of the type of non-compliance that
might warrant the BLM issuing a cease operations order will be
noncompliance with the BLM-approved POD and refusal to comply with the
notice of noncompliance.
Section 3936.40 allows a lessee or operator to appeal BLM decisions
under 43 CFR part 4. This section also provides that the BLM decisions
and orders remain in full force and effect pending appeal, unless the
BLM or the IBLA decides otherwise. Appeals language in this section
mirrors regulatory provisions in other BLM minerals programs.
The BLM received several comments questioning the BLM's authority
to assess penalties and the need for an opportunity for a hearing
regarding an assessed penalty. We agree with the commenter in part.
There is no clear statutory authority for civil penalties for
noncompliance with the regulations. Accordingly, the final regulations
do not provide for penalties. The BLM, however, has authority under
Section 31 of the MLA to pursue an action in Federal court to cancel a
lease for noncompliance with that Act, the lease, or the regulations
(see 30 U.S.C. 188). The Department, though, has recognized for many
years that lease cancellation is too drastic a remedy in most cases.
The same section of that Act allows the BLM to provide for
``appropriate methods for the settlement of disputes or for remedies
for breach of specified conditions'' (30 U.S.C. 188(a)). Under that
authority, the BLM levies assessments as remedies for acts of non-
compliance with oil and gas regulations, leases, permits, notices or
orders pursuant to 43 CFR 3163.1.
Assessments as remedies for non-compliance are appropriate as
liquidated damages both for the BLM's costs and expenses which would
not have been incurred but for the noncompliance, and for the
Department's losses, as the lessor for damages to resources and for the
loss of the royalties from production that would have commenced sooner
but for the noncompliance. See M. John Kennedy, 102 IBLA 396, 399-400
(1988) (emphasizing BLM's costs and expenses); 52 FR 5384, ---- (1987)
(emphasizing compensation for the lessor).
The BLM received several comments indicating that the proposed
penalties were not high enough and indicated that they thought the
penalties should mirror the oil and gas regulations which allow for
fines as high as $25,000 per day and which could also include criminal
penalties. There is not a statutory provision for the BLM to impose
civil or criminal penalties for noncompliance with these regulations.
The assessment that the BLM is imposing is designed to cover costs and
expenses of administering the lease which would not have been incurred
but for the noncompliance and to cover threats, if any, to BLM
resources. Payment of an assessment, however, does not relieve an
operator of the duty to correct a violation.
Accordingly, final section 3936.30(a)(2) has been rewritten to
provide for assessments of $500 per day for each non-corrected
noncompliance.
III. Procedural Matters
Executive Order 12866, Regulatory Planning and Review
This document is a significant rule and the Office of Management
and Budget (OMB) has reviewed this rule under Executive Order 12866. We
have made the assessments required by E.O. 12866 and the results are
available by writing to the address in the ADDRESSES section.
(1) This rule will have an effect of $100 million or more on the
economy. It will not adversely affect in a material way the economy,
productivity, competition, jobs, the environment, public health or
safety, or State, local, or tribal governments or communities. Please
see the discussion below.
(2) This rule will not create a serious inconsistency or otherwise
interfere with an action taken or planned by another agency. The rule
addresses the issuance and administration of Federal oil shale leases,
which by statute is under the jurisdiction of the Department. The BLM
worked closely with the MMS in drafting the royalty provisions of this
rule, but the rule should have no effect on other agencies.
(3) This rule does not alter the budgetary effects of entitlements,
grants, user fees, or loan programs or the rights or obligations of
their recipients. The rule will not affect any of these except that the
rule institutes certain fees (discussed earlier in the preamble to this
rule and in the economic and threshold analyses for the rule) in a
manner that is consistent with BLM and Departmental policy.
(4) This rule does not raise novel legal or policy issues. As
stated earlier in this preamble, the legal and policy issues addressed
by this rule are already dealt with in a similar manner in other BLM
regulations currently in effect. Therefore, they are not novel.
A commenter suggested that the proposed rule does raise novel legal
and policy issues. For example, the leasing, technology, economics,
environmental impacts, and legal issues surrounding oil shale
development will be novel.
The potential leasing and development of oil shale resources on
public lands will present many unique challenges. However, we do not
believe there are any unique or novel legal and/or policy issues. As we
noted above, the oil shale regulations reflect practices employed in
other BLM energy and mineral programs.
Executive Order 12866 requires agencies to assess, where practical,
the anticipated costs and benefits of regulatory actions to determine
if the regulation is significant. As has been noted above, there is no
domestic oil shale industry to help substantiate or form the basis for
the projections and assumptions concerning what the future might hold
for the leasing and development of oil shale resources on Federal
lands. In addition, the assumption is that any significant production
of shale oil is not likely to occur for a number of years. The
potential events described, if they occur at all, may be in the distant
future. Therefore, future costs and benefits must be discounted. The
OMB's Circular A-94 states that a real discount rate of 7 percent
should be used as a base-case for regulatory analysis. In addition to
analyzing the potential future costs and benefits using a 7 percent
discount rate, the BLM also used a discount rate of 20 percent to
reflect these substantial risks and associated uncertainties in the
opportunity costs that would not be reflected in the historic industry
average of 7 percent. We also analyzed the future costs and benefits
using a 3 percent discount rate.
The regulations have the potential to generate net economic
benefits to the United States by allowing for the development of our
vast domestic oil shale resources, though there is substantial
uncertainty about the magnitude and timing of these benefits. The most
substantial direct benefit of this regulatory action is to provide a
vehicle for the leasing and development of Federal oil shale resources.
Operators will have the opportunity to obtain leases with the right to
develop the oil shale and ultimately produce shale oil in an
environmentally sound manner. Companies' willingness to take advantage
of the leasing and development opportunities provided by this rule will
determine the level of production of shale oil, exploration,
development and production costs incurred, and conceivably the profits
(or losses) to be enjoyed.
[[Page 69449]]
The lack of a domestic oil shale industry makes it speculative to
project the demand for oil shale leases, the technical capability to
develop the resource, and the economics of producing shale oil.
Projections that have been prepared vary significantly in not only the
potential volume of shale oil that could be produced, but also the
assumptions used to generate those projections. The recent report
prepared by the Strategic Unconventional Fuels Task Force (Task Force)
provided shale oil production projections under three scenarios. For
our simulation-based analysis, we focused on the Task Forces' base case
as a plausible scenario. This scenario presents a future without any
subsidies in the form of tax credits or cost-sharing. The base case
production of a half million barrels per day is approximately 182.50
million barrels per year, all from true in-situ projects. The Task
Force's base case scenario assumes production commencing in 2015, with
full production reached by 2020. In the proposed rule we asked for
comment on the uncertainty surrounding the quantity and quality of
recoverable oil shale, specifically as it relates to potential
production of shale oil. We did not receive any comments specific to
the availability and reliability of recoverable reserve data.
The Task Force estimates that resulting production could reduce the
cost of oil imports by $0.41 billion per year in 2015 to $4.21 billion
per year in 2035. This estimate is based on EIA's 2006 oil price
projection. In their report, the Task Force also provides estimates of
oil shale development's contribution to Gross Domestic Product (GDP).
In the base case, annual direct contributions to GDP for the oil shale
industry activity rises from $0.65 billion per year in the early years,
to $5.72 billion per year in 2035.
We estimated the revenue, profit, and royalty implication of the
Task Force's base case production scenario using three discount rates
(7 percent, 3 percent, and 20 percent), three world crude oil price
projections (EIA's 2007 reference, high, and low price projections) and
6 different royalty rates (1 percent, 3 percent, 5 percent, 7 percent,
9 percent, and 12.5 percent). The following summarizes the findings
based on the 7 percent discount rate and a 5 percent royalty rate. The
full range of calculations is presented in the Economic Analysis.
We estimate the value of the forecasted production, using EIA's
2007 reference case assumptions, could be approximately $9.5 billion
for 2020, up to $11 billion by 2035. The gross present value, using a 7
percent discount rate, of all shale oil produced for the period of
analysis (2007 to 2035) is estimated at about $50 billion. The gross
present value of production for the year 2020 is estimated at about
$3.9 billion using a 7 percent discount rate. The gross present value
of the shale oil produced in 2035 would be approximately $1.7 billion
with a 7 percent discount rate.
Oil shale development is characterized by high capital investment
and long periods of time between expenditure of capital and the
realization of production revenues and return on investment. The Task
Force estimated the breakeven price for true in-situ operations at
$37.75 per barrel. Using the base case production projection, the cost
to produce 182.50 million barrels annually would be almost $6.9
billion. The present value of the production costs for 2020 would be
about $2.9 billion using a 7 percent discount rate. For production
occurring in 2035, the present value of those production costs would be
about $1 billion. For the period of analysis (2007 to 2035), the
present value of all production costs is estimated at about $34 billion
using a 7 percent discount rate. In the proposed rule we specifically
asked for comment on the state of technology necessary to recover or
produce oil from shale and the associated production costs.
We received several comments on the data used in the economic
analysis. Commenters suggested that some of the data, specifically
production cost estimates, are dated and inaccurate. Commenters noted
recent production cost estimates in the $75-$90 per barrel range.
We readily acknowledge that the economic analysis does not reflect
the latest projections, including production cost estimates. However,
when the analysis was prepared we used the most recent published
estimates from independent third party sources, e.g., government or
academic sources. We also note that when we considered these higher
production cost estimates, in conjunction with higher world oil prices,
the specific projections changed, but the general findings and
conclusions of the analysis did not change.
With the opportunity to lease and ultimately develop Federal oil
shale resources, companies would be expected to generate profits from
their commercial activities. Using the base case production scenario,
cost projection assumptions, and EIA's reference oil price, by the year
2020 lessees/operators could see profits from oil shale development of
over $2.6 billion per year, with a net present value of $1 billion with
a 7 percent discount rate. For 2035, we estimate the present value of
the potential profit could be approximately $670 million using a 7
percent discount rate. The net present value of shale oil produced in
the period of analysis (2007 to 2035) is estimated at approximately
$16.2 billion.
Using EIA's high crude oil price scenario, calculated profits were
substantially high. Total undiscounted profits for the period of
analysis were $187 billion, with a present value of $50.6 billion using
a 7 percent discount rate. For EIA's low oil price projection all
operations are uneconomic regardless of the discount rate and/or
royalty rate applied. In addition to these monetary costs and benefits
associated with potential oil shale development, there could be varying
degrees of environmental and socioeconomic costs and benefits. These
potential costs and benefits could affect a wide range of resources,
including groundwater quality and quantity, air quality, cultural
resources, wildlife habitat, competing land uses, and local employment
and infrastructure.
Impacts on livestock grazing activities are generally the result of
activities that affect forage levels, of the ability to construct range
improvements, and of human disturbance or harassment of livestock
within grazing allotments. Using the Task Force's base case scenario of
three in-situ operations, with total maximum lease acreage of 17,280,
and some highly conservative and simplifying assumptions, there could
be a loss of approximately 5,700 animal unit months. However, it is
more reasonable to assume that only specific portions of the lease area
(5,760 acres) will be disturbed at any one time. It is therefore
possible that 3,120 to 4,970 acres within a 5,760-acre lease would
remain available for grazing in undeveloped or restored portions of the
lease. These figures are based on the assumption for a surface mine
with surface retort with a production of 50,000 bbl of shale oil per
day (see in section 4.1 and appendix A of the PEIS). The footprint of
development ranges from 600-2,000 acres, Table 4.1.1-1 in the PEIS
(page 4-4) and with long-term facilities (office buildings, retorts,
etc.) covering 100 acres. It was assumed that grazing activities would
be precluded on the leases that were undergoing active development, in
preparation for future development, undergoing restoration after
development, or occupied by long-term surface facilities. The actual
figures are discussed in section (4.2.1.3 Grazing Activities, PEIS page
4-20).
[[Page 69450]]
Recreational use of BLM-administered lands within the three-state
study area (Colorado, Utah, and Wyoming) is varied and dispersed.
Impacts on recreation could be considered locally significant if
potential oil shale development results in long-term elimination or
reduction of recreation opportunities, activities, or experience, or
they compromise public health and safety. While recreational use could
be possible in undeveloped or restored portions of a lease area, the
amount of land that would be available would vary from project to
project. As such, the significance of the potential impacts of oil
shale development could have on recreational opportunities will depend
on the location of potential development and on the nature of the
recreational activity precluded from portions of the lease area.
In addition to oil shale, the study area contains a wide range of
energy and mineral resources. Mineral resource development conflicts
may occur with oil shale development. The issuance of oil shale
exploration licenses and leases does not preclude the BLM from issuing
licenses and leases for other minerals, if the applicant can
demonstrate that the technology to be used would allow recovery of oil
shale resources without destroying or preventing the recovery of the
other mineral resource. Conflicts among competing resource uses are
generally considered and resolved when processing potential leasing
actions or evaluating requirements for approval of PODs. In general,
stipulations or conditions of approval could be developed to mitigate
resource conflicts. It is the BLM's policy to optimize recovery of
natural resources in an effort to secure the maximum economic return to
the public and energy production, prevent avoidable waste of the
public's resources utilizing authority under existing statutes,
regulations and lease terms, and honor the rights of lessees, subject
to the terms of existing leases and sound principles of resource
conservation.
Many multiple use outputs from BLM land are not traded in markets
and might not have measurable onsite expenditures associated with them.
The absence of market price does not, however, mean an absence of value
to society.
In addition to land use conflicts, water consumption is a major
concern in the arid intermountain region. Certain types of oil shale
development are anticipated to consume large quantities of water.
Increasing the demand for water resources in the arid West must be
considered a major opportunity cost to society associated with oil
shale development and fully analyzed before commercial development is
allowed to proceed. Demand for reliable, long-term water supplies to
support oil shale development could lead to the conversion of water
rights from current uses. While it is not presently known how much
surface water will be needed to support future development of an oil
shale industry, or the role that groundwater would play in future
development, it is likely that additional agricultural water rights
could be acquired, but only in compliance with state law. Depending on
the locations and magnitude of such acquisitions, there could be a
noticeable reduction in local agricultural production and use.
Prospective oil shale developers would need to employ appropriate
control technologies to reduce potential air emissions which otherwise
could result from construction and operation of surface facilities. In
addition to the emissions associated with the operations themselves,
extraction of oil from shale could consume immense quantities of
electricity. This would necessitate the building of new power plants,
which could further contribute air emissions. Impacts on air quality
would be limited by applicable local, state, Tribal, and Federal
regulations, standards, and implementation plans established under the
Clean Air Act and administered by the applicable air quality regulatory
agency, with Environmental Protection Agency oversight.
Using the assumption of 3 in-situ projects, solid waste generated
would be the drill cuttings and those would be handled as they are for
oil and gas, which is to bury them on-site, in compliance with the
Solid Waste Disposal Act, as amended by the Resource Conservation and
Recovery Act and the Hazardous Solid Waste Amendments of 1984 (42
U.S.C. 6901 et seq.).
Aquatic habitats include perennial and intermittent streams,
springs, and flat-water (lakes and reservoirs) that support fish or
other aquatic organisms through at least a portion of the year may
experience potential impacts. Impacts to wildlife species that may be
associated with any particular project would depend on the specific
location of the project and on the plant communities and habitats
present at the site.
A total of 210 plant and animal species are either federally (U.S.
Fish and Wildlife Service (USFWS) and BLM) or state-listed (Colorado,
Utah, and Wyoming) and these species occur or could occur in counties
within oil shale basins. In the study areas, 32 species are listed or
candidates for listing by the USFWS under the Endangered Species Act
(ESA); 78 species are listed as sensitive by the BLM; 24 are listed by
the State of Colorado; 33 are listed by the State of Utah; and 121 are
listed by the State of Wyoming. Species listed by the USFWS under the
ESA have the potential to occur in all oil shale basins. Nothing in the
rule changes existing processes and procedures that ensure the
protection of listed or proposed species or designated or proposed
critical habitat. The rule is an administrative task that does not
cause any impact to listed species or critical habitat. The rule does
not commit the BLM to a particular course of action or authorize any
ground-disturbing activity; it merely allows the BLM to establish a
regulatory framework for oil shale leasing and development. A complete
evaluation of listed species in the study areas will be made before
leasing occurs or project activities begin. Project-specific NEPA
assessments, ESA consultations, and coordination with state natural
resource agencies will address project specific impacts more
thoroughly. These assessments and consultations will result in required
actions to avoid or mitigate impacts on protected species.
Oil shale development, in the western states of Colorado, Wyoming,
and Utah, requires infrastructure to support industry development and
operation, including refining capacity, pipelines, and sources of
natural gas and electricity.
The socioeconomic environment potentially affected by the
development of oil shale resources includes a region of influence in
each state (Colorado, Utah, and Wyoming), consisting of the counties
and communities most likely affected by development of oil shale
resources. Construction and operation of oil shale facilities could
have a major effect on the local communities, with impacts on the
economy and the social and demographic make-up of the affected
communities. For example, oil shale industry development could result
in the addition of thousands of new, high-value, long-term jobs in the
construction, manufacturing, mining, production, and refining sectors
of the domestic economy. Construction and operations could result in a
direct loss of recreation employment in the recreation sectors and
indirect effects such as declining recreation employee wage and salary
spending and expenditures by the recreation section on materials
equipment and services.
The Task Force provided employment projections for their production
[[Page 69451]]
scenarios, including their base case. Direct employment could range
from 120 to 9,700 personnel in the base case. The total number of
petroleum sector jobs (including indirect employment), estimated by the
Task Force, ranges from 2,930 employees in 2015 to 20,830 in 2035 for
their base case.
The final rule does not authorize any ground disturbing activities
and is not an irreversible and irretrievable commitment of resources
under NEPA. However, irreversible and irretrievable commitments of
resources could occur as a result of future commercial oil shale
projects that are authorized, constructed, and operated. The nature and
magnitude of these commitments would depend on the specific location of
the project development as well as its specific design and operational
requirements. The construction of future commercial oil shale projects
could result in the consumption of oil shale, sands, gravels, and other
geologic resources, as well as fuel, structural steel, and other
materials. Water resources could also be consumed during construction,
although water use would be temporary and largely limited to on-site
concrete mixing and dust abatement activities. The impact on biological
resources from future project construction and operation could
constitute an irreversible and irretrievable commitment of resources.
We received a comment concerning our statement in the proposed rule
that ``the impact on biological resources from future projects
construction and operation would not constitute an irreversible and
irretrievable commitment of resources.'' The commenter observed that
given the unknowns associated with oil shale development, such a
statement was not justified.
We agree with the commenter. Future project construction and
operations could result in an irreversible and irretrievable commitment
of those resources. Such decisions will be subject to future NEPA
analysis. However, the establishment of these regulations does not
involve any commitment of those resources.
It can be assumed that the potential effects of developing the oil
shale resources are likely to be adverse; however, at this point, with
the significant unknowns as to what may be developed and how it may be
developed, plus where and when development may occur, there is no
practical way to quantify the level or degree of the potential
environmental and socioeconomic consequences, much less put a monetary
value on them.
Before oil shale development could occur, additional project-
specific NEPA analyses would be performed at two points in time: (1)
Prior to leasing; and (2) Prior to POD approval. These analyses would
address environmental impacts of oil shale production including impacts
to livestock grazing, recreation uses, energy and mineral resources,
socioeconomics, water use, air, aquatic habitat, and wildlife and would
be subject to public and agency review and comment.
The Act requires the Secretary to establish royalties, fees,
rentals, bonuses, or other payments for oil shale leases that encourage
development of the resource, but also ensure a fair return to the
government. As a result of any leasing and development, the Federal and
state governments will benefit from the revenue generated through the
bonuses, rents, and eventually royalties. These bid, rental, and
royalty payments are revenue to the public, but a cost to the lessee/
operator of obtaining, holding, and producing from the Federal leases.
Monetary payments, such as rents, royalties, and bonus bids, from the
lessee to the government, do not affect total resources available to
society and in the context of a benefit-cost analysis are considered
transfer payments.
The bonus is the amount paid by the successful high bidder when a
parcel is offered for lease. By statute the parcel must be leased for
FMV. The bonus is a part of the FMV paid for the lease and lease
resources. At this point in time there is no practical way to generate
a meaningful estimate of the potential bonus bids or fair market values
for potential lease parcels.
Until the operation starts paying a production royalty, the lessee
is required to pay the government a rental. The regulations include a
rental rate of $2 per acre. Maximum lease acreage is 5,760 acres for a
maximum annual rental payment per lease of $11,520 (constant-dollars)
per year until an operation commences shale oil production. Based on
the Task Force's base case of three in-situ operations, with total
maximum lease acres of 17,280 acres, those three leases could generate
a rental income of $34,560 per year.
Producing leases will be required to pay a production royalty. The
royalty rate for the products from oil shale leases is 5% of the amount
or value of production removed or sold from the lease for the first 5
years of production. The royalty rate will increase by 1% each year
starting the 6th year of commercial production to a maximum royalty
rate of 12% in the 13th year of commercial production. Using the
production projections, EIA reference oil prices, and other assumptions
discussed in the economic analysis, royalty payments for the period of
the analysis (2007-2035) could have a net present value of $4.4 billion
with a 7% discount rate. We also analyzed the Federal revenue
implications of alternative royalty rates given constant production and
production cost assumptions. These alternative royalty revenue
calculations are presented in the economic analysis for the proposed
rule.
Beginning in the 10th lease year, for leases that have not
commenced production, the lessee is subject to a payment in lieu of
production of no less than $4 per acre. For an operation with 5,760
acres under lease and no production by the end of the eleventh lease
year, the payment in lieu of production would be $23,040 (constant-
dollars) per year. Based on the Task Force's base case of three in-situ
operations, with total maximum lease acres of 17,280 acres, should
operations on those three leases not commence production, the payment
in lieu of production could generate payments to the Federal Government
of $69,120 per year.
The regulations require license and lease bonds for exploration
licenses and oil shale leases. These bonds are intended to guarantee
payments (rents, royalties, and deferred bonuses) the lessee may owe
the government. The bond amount will be determined on a case-by-case
basis. The minimum lease bond is $25,000. The operator is also
obligated to provide the BLM with a reclamation bond. The amount of
these bonds will be based on the estimated cost for the government to
contract with a third party to reclaim the operation should the
operator be unable or unwilling to fulfill its reclamation obligations.
The amounts of these reclamation bonds are likely to be quite
significant; however, at this point there is no practical way to
estimate the amount of these reclamation bonds.
There will be increases in BLM administrative costs associated with
the issuance of leases and licenses and review and approval of
operational plans. Most of these costs are relatively minor and will be
subject to cost recovery that will be paid for by the benefitting
party. There will be some BLM actions that will not be subject to cost
recovery, including increased costs associated with ongoing inspection
and enforcement responsibilities.
There are various costs and benefits associated with the final
rule. Some effects are directly tied to the provisions
[[Page 69452]]
found in the regulations, such as the royalty rate. Other costs and
benefits are tied to companies' ability and willingness to take
advantage of the opportunities provided by the leasing regulations. The
most significant of these costs and benefits include the value of shale
oil that may be produced, the cost to produce the shale oil, and the
environmental and socioeconomic consequences of resource development.
The present values of the quantified monetary effects are expected to
be in excess of the $100 million annual threshold.
We estimate the net present value of the potential monetary costs
and benefits considered in this analysis to be approximately $13.6
billion using a 7 percent discount rate, $28.5 billion using a 3
percent discount rate, and $1.8 billion using a 20 percent discount
rate. This conclusion is based on the calculated present value of the
profit from shale oil produced from our analysis period (2007 to 2035)
using EIA's reference oil price.
This conclusion includes one significant caveat. The socioeconomic
and environmental costs and benefits associated with oil shale
development are likely to be large. As has been noted above, we have no
reasonable way to generate meaningful scenarios to quantify the
potential impacts for an industry that does not exist or technologies
that have not been deployed. As such, the net present value of the
benefits of the rule may be significantly larger or smaller than the
estimates presented in this analysis.
Small Business Regulatory Enforcement Fairness Act (SBREFA).
This rule is a major rule under 5 U.S.C. 804(2), the Small Business
Regulatory Enforcement Fairness Act. This rule:
(1) Has an annual effect on the economy of $100 million or more.
Please see the discussion of Executive Order 12866, above.
(2) Will not cause a major increase in costs or prices for
consumers, individual industries, Federal, state, or local government
agencies, or geographic regions. Should production from Federal oil
shale resources occur, it is anticipated that if there is any impact to
costs or prices as a result of additional production entering the
market, it would be to decrease them.
(3) Does not have significant adverse effects on competition,
employment, investment, productivity, innovation, or the ability of
United States-based enterprises to compete with foreign-based
enterprises. The issuance of Federal oil shale leases and production of
oil shale resources from those Federal leases would not lead to adverse
effect on any of the above because an increase in products from oil
shale would tend to lead to a decrease in prices and potentially lead
to increased competition, employment, investment, productivity, and
innovation and the increased ability of United States based enterprises
to compete with foreign-based enterprises.
National Environmental Policy Act
The BLM has prepared an environmental assessment (EA WO-300-07-009)
and has found that this final rule does not constitute a major Federal
action significantly affecting the quality of the human environment
under Section 102(2)(C) of the National Environmental Policy Act of
1969 (NEPA), 42 U.S.C. 4332(2)(C). A detailed statement under NEPA is
not required.
The Assistant Secretary for Land and Minerals Management has
selected the Proposed Action to amend 43 CFR subtitle B Chapter II, by
adding parts 3900, 3910, 3920 and 3930, as discussed in this rule based
on the analysis in the EA and the information contained in this
preamble. The Assistant Secretary's final decision associated with this
rule incorporates the Decision Record for the EA. The BLM has placed
the EA and the rationale for the Finding of No Significant Impact/
Decision Record on file in the BLM Administrative Record at the address
specified in the ADDRESSES section. We received several comments on the
draft EA. Substantive comments are summarized and responses are
provided below. As appropriate, the EA was modified based on the
comments received.
Comment EA-1: The draft EA was based on a lack of information and
incomplete environmental analysis. Without understanding critical
issues and options for protecting air and water an informed decision
cannot be made. The draft EA does not increase the BLM's understanding
of the environmental consequences of commercial development.
The EA is based on the available information. It demonstrates that
the BLM understands the critical issues and options and that the BLM
has sufficient understanding of the environmental consequences of
promulgating the regulations.
The EA contains the prerequisite level of information necessary to
make a reasoned choice among the alternatives based on the scope and
nature of the proposed action, in this case, the promulgation of a
rule. The proposed action is very limited in scope--the establishment
of a fixed, largely procedural framework for the administration of an
oil shale program, which governs the general manner in which industry
and the BLM will operate. Congress mandated the Secretary to publish
final regulations establishing a commercial oil shale leasing program.
This congressional mandate is the basis for the underlying purpose and
need for proposing the specific regulatory alternatives as well as for
the decision to be made. Consistent with this purpose and need, for its
``no action'' alternative, the draft EA evaluates an alternative that
is not to promulgate regulations, rather than a ``no leasing''
alternative. The EA also objectively evaluates alternatives for a
competitive and a preference right leasing program, as well as an
alternative, that increases the bonding requirements and fully applies
environmental best management practices (BMP).
The EA incorporates by reference information from the
``Environmental Consequences'' discussion from the PEIS, in order to
provide the decision maker with additional information on the nature of
the effects of possible future development of these resources, if there
were to be future commercial leasing of oil shale resources, to allow
the Department to make a more informed decision (see Response to
Comment EA-2), however, the decision addressed by the EA is whether to
promulgate regulations.
The rule, provides for appropriate NEPA analysis for future actions
that may have environmental consequences, and outlines specific
environmental processes and standards to put the lessee or operator on
notice of what is required. For example, a provision at section 3900.50
reinforces the requirement that NEPA documents must be prepared prior
to issuance of a lease or exploration license. The environmental
analysis will include the consideration of direct, indirect, and
cumulative effects of the proposed lease or exploration license
issuance, reasonable alternatives, and mitigation measures to protect
resources and resource values, as well as what level of development may
be anticipated. This specific analysis may include mitigation measures
such as BMPs, specific protections, or avoidance to mitigate or
eliminate impacts to sensitive species or resources, such as air and
water quality.
The EA demonstrates that the BLM has enough information and
understanding to establish a regulatory program. The regulations are
not a commitment to issue any lease or to approve any POD.
[[Page 69453]]
Comment EA-2: The draft EA does not contain any substantive
analysis and makes broad conclusory statements, it is impossible to
anticipate with any certainty the environmental consequences of
development. The draft EA relies on the PEIS for its evaluation of the
environmental consequences, and therefore gaps in the PEIS such as no
in-depth analysis of direct, indirect, and cumulative impacts or the
identification of actions are carried forward to the draft EA, as such,
the BLM did not take a ``hard look'' at the environmental consequences
of the proposed rule.
The EA takes a hard look at the environmental consequences of oil
shale development, even though the regulations being promulgated do not
in and of themselves have an impact on the environment. As discussed in
Response to Comment EA-1, the scope and nature of the proposed action
and alternatives is the establishment of a regulatory framework for an
oil shale program. The analysis looks at the effects of the various
components, requirements, and processes outlined in the rule's
provisions. These rules are primarily procedural and do not commit any
resources or authorize any BLM action that would have a direct,
indirect, or cumulative impact on the physical, biological, or
socioeconomic environment. (Also, see Response to Comment EA-8.) Any
commitment of resources or approval of exploration, development, or
production activities would be based on future decisions made in
compliance with the BLM's land use planning and NEPA procedures, as
required by the various sections of the rule and is outside the scope
of this EA.
Although the EA is only evaluating the impacts of a regulatory
framework and is not required to analyze the impacts of commercial
development, the EA incorporates by reference information and analyses
from the PEIS to provide the decision-maker with additional information
and a general understanding of the nature of the environmental
consequences that can be expected from future commercial development.
Chapter 4 in the PEIS presents an analysis of oil shale technologies
and their potential environmental and socioeconomic impacts, as well as
potential mitigation measures that may be considered, if warranted,
prior to the issuance of a lease.
We disagree that the PEIS contains significant ``gaps'' that could
be filled with analysis of available data. To the extent that the
comment pertains to portions of the PEIS that are not incorporated by
reference in the EA, it is not relevant to this decision.
The PEIS discusses the potential direct, indirect, and cumulative
impacts of oil shale development based primarily on BLM professional
expertise and experiences with surface-disturbing activities from other
types of mineral development (e.g., coal mining, and oil and gas).
Because there is no commercial oil shale industry in the United States,
there is no data available on what, if any, extraction process will be
commercially viable, and thus there is uncertainty about the precise
impacts from commercial oil shale development. Nonetheless, based on
BLM's experience with other types of mineral development, the types of
impacts discussed in the PEIS may occur. Using comparable data from
other mineral programs, the BLM determined that there was sufficient
information on the nature of the effects for a land use allocation
decision, but not sufficient information to support a lease sale. The
analysis discloses potential effects associated with leasing and
development to provide the decision-maker the available, essential
information to make an allocation decision. In view of this limited
scope, the PEIS, in particular, in Chapter 6 of that document, fulfills
the requirement to take a ``hard look'' at the direct, indirect, and
cumulative consequences of the allocation alternatives described in
Chapter 2 of the PEIS. The EA was modified to make it clear that it was
BLM's intent to incorporate by reference the impact analysis, and not
tier to the PEIS.
Comment EA-3: Stating that subsequent NEPA analysis will be
required cannot be used to avoid compliance with NEPA.
The EA does not purport to avoid compliance with NEPA by stating
that subsequent NEPA analysis will be required. The EA fully assesses
and discloses the environmental consequences of the adoption of this
rule and other reasonable alternative regulatory approaches and is in
full compliance with NEPA. The EA presents sufficient information to
the decision-maker to aid in deciding upon the requirements that will
govern the leasing of oil shale and the process for review and
conditioning of oil shale operations. As stated in the EA, the
regulations make no commitment on the part of the BLM to approve any
action, grant any permit or issue any lease. The regulations are
primarily procedural, establishing a framework in which specific
development proposals will be subject to intensive scrutiny and
project-specific regulation in the form of conditions of approval,
rather than define the specific activities authorized or prohibited or
the conditions under which they can occur, except in the broadest
terms.
As the EA explains, prior to any leasing or development taking
place in accordance with the procedural requirements of the rule,
several other decision points will need to be reached. Each of these
decision points will involve a new proposed action, which will be
subject to appropriate NEPA analysis, and will occur prior to any
impacts to the environment. These decision points are land use planning
allocations, such as those analyzed in the PEIS on a programmatic
level, issuance of exploration licenses, identification of parcels for
offering at a lease sale, conversion of the R, D and D leases to
commercial leases, and approval of on-the-ground projects or
activities. The required analysis of environmental consequences at each
of these future decision points, or stages, will be facilitated by the
availability at that decision point of more site-specific information,
about the exact location, technology and process proposed for the
operation, which will allow for that analysis to focus on the issues
relevant to the specific proposal. As a consequence, specific measures
to mitigate or eliminate impacts identified at that time can be
developed.
Comment EA-4: The BLM is performing a piecemeal approach to NEPA
compliance by proceeding without an assessment of multiple actions
where each may individually have an insignificant environmental impact
but which collectively have a substantive effect.
The BLM is not ``piecemealing'' its compliance with NEPA. The BLM
is engaged in staged decision making. The unavailability of data
regarding the technologies that might become commercially viable in the
future and the requirements of the EP Act to adopt regulations for a
commercial oil shale leasing program combine to render staged decision
making and NEPA analysis for commercial oil shale leasing and
development the most effective approach. The appropriate NEPA analysis
will accompany each stage of the decision making.
The EA looks at the impacts of this rule. The PEIS analyzes, at a
programmatic level, the decision to allow lands to be open to oil shale
lease and therefore, examines possible impacts of development of these
resources over the planning area. At each decision point, or stage,
from leasing to development of individual projects, the scope of the
analysis under
[[Page 69454]]
NEPA will be consistent with the proposed action contemplated at that
decision point. Such analysis would necessarily include, particularly
in the cumulative impacts analysis, the past, present, and reasonably
foreseeable future actions that are appropriately included in relation
to the proposed action presented for analysis at that time. Although
there is no available data that could support a non-speculative
cumulative effects analysis at this time, such information will start
to become available when the industry is ready to commit to
technologies and processes to develop oil shale. A more specific
analysis of the impact of oil shale activities, including any possible
``collective'' impacts, will be performed, and a Reasonably Foreseeable
Development Scenario for oil shale development will be prepared to help
focus the analysis. In this way, the BLM will avoid a ``piecemeal''
approach (see Response to Comment EA-3).
Comment EA-5: The draft EA does not provide the detailed analysis
or cumulative analysis as required by NEPA analysis.
The EA provides the analysis appropriate for the decision to
promulgate the regulations. Given that purpose and need, the discussion
of types of impacts from oil shale development is quite detailed,
particularly in light of the nascent stage of the industry. In fact,
given the largely procedural character of the rule and the speculative
character of the environmental impacts from a future regulated
industry, one could argue that the proposed action of promulgating the
rule is subject to at least one of the Department of the Interior
categorical exclusion. As discussed in Response to Comment EA-1, the
scope and nature of the proposed action and alternatives is the
establishment of a regulatory framework for an oil shale program. The
analysis looks at the various components, requirements, and processes
outlined in the rule's provisions. These regulations are process-
oriented and do not commit any resources or authorize any BLM action
that would have a direct, indirect, or cumulative impact on the
physical, biological, or socioeconomic environment. As there are no
environmental impacts caused by the proposed action or alternatives, it
follows that there are no cumulative impacts either. The analysis in
the EA is appropriate, for the scope of the proposed action.
Comment EA-6: Does the draft EA look at the elasticity of
production under different policy scenarios--to justify this set of
policy-driven rules and regulations as the optimum combination of
options.
The draft EA did not speculate as to how future production might be
different under different regulatory schemes. We have no reason to
believe that such differences would affect production levels, which
depend more on technological advances, demand, the prices of competing
fuels, land use allocation decisions and subsequent site-specific
decisions informed by site-specific environmental analysis.
Comment EA-7: The draft EA is so devoid of substance that it cannot
be used to meaningfully support any subsequent leasing decision.
As discussed in Response to Comment EA-1, the nature and scope of
the proposed action is the establishment of a regulatory framework for
an oil shale program and does not commit the BLM to hold a lease sale.
That is, this EA is not intended to support any subsequent leasing
decision. As explained in the PEIS, the BLM intends to prepare separate
NEPA analysis to support any decision to lease, which will be a
proposed action entirely separate and apart from that under
consideration here, or in the PEIS.
Comment EA-8: The draft EA incorrectly concludes that no
significant impacts can result from its current decision, yet the draft
rule identifies significant impacts from commercial development, and,
all the factors which are used to define ``significantly'' based on
intensity have been met; including setting a precedent, controversial
proposed action. The decisions made in these regulations (i.e., royalty
rates) will have a significant impact on the scope and pace of
commercial oil shale development, and therefore will have direct,
indirect, and cumulative effects on the physical biological and
socioeconomic environment.
No significant impacts result from promulgating the regulations
because the Secretary could lease Federal oil shale without the
regulations, and similarly could decide not to offer leases after
regulations are promulgated; the regulations are not causing any tract
to be leased or to be developed. The BLM considered the context and
intensity of the consequences of promulgating the regulations, and
whether the establishment of the regulations, in of themselves, could
significantly affect the environment.
When the factors associated with the intensity or severity of
impact are evaluated against the provisions of the regulations, they do
not meet the criteria as to the degree to which the rule affects the
various resources or historic properties, and the rule does not
contribute incrementally to the cumulative effect of other past,
present, or reasonably foreseeable Federal or non-Federal actions.
The BLM evaluated the severity of effects associated with the rule.
To determine significance, the severity of the effects must be examined
in terms of the type, quality, and sensitivity of the resource
involved; the location of the proposed project; the duration of the
effect (short- or long-term) and other considerations of context.
Significance of the effect will vary with the setting of the proposed
action and the surrounding area. The rule is primarily procedural and
does not commit any resources, authorize any BLM action in a specific
location, or result in short- or long-term impact, and therefore the
factors and criteria related to intensity are not applicable.
The commenter notes that an EIS is required if the action is
considered controversial. The criteria for determining whether
controversy makes an action significant is 40 CFR 1508.27(b)(4), which
states ``The degree to which the effects on the quality of the human
environment are likely to be highly controversial.'' CEQ guidelines
require that an EIS be prepared where there is a substantial dispute as
to the size, nature, or effect of the ``major'' Federal action. There
are no such disputes as to the regulations, which have no effects on
the environment, and thus the ``controversial'' criterion does not
apply.
A commenter notes that an EIS is required if the action may
establish a precedent for future actions with significant effects or
represents a decision in principal about a future consideration. The
rule is not a decision on any project and therefore does not set a
precedent for such decisions in the future, nor establish a custom or
practice. The rule contains standards, procedures, or requirements that
govern the general manner in which industry and the BLM will operate.
It is a set of rules that govern conduct and guide actions but do not
commit, on the part of the BLM, to approve or authorize an action or
require a specific decision.
The royalty rate may affect the interest in leasing and
development, but the rule does not commit the BLM to engage in leasing
or approve development. The royalty rate may be one of the factors used
in the development of a Reasonably Foreseeable Development Scenario to
help focus the NEPA analysis for a future leasing decision. The pace
and scope of that oil shale development are issues outside the scope of
the rule and its supporting EA. The Secretary retains
[[Page 69455]]
discretion to decide whether, when, and where to offer tracts for
lease.
Comment EA-9: The NEPA analysis in support of the rule is flawed
because the promulgation of the oil shale regulations is a ``major
federal action'' and that the draft rule states that significant
impacts from commercial development can occur and therefore, the BLM is
required to prepare a detailed EIS.
The EA properly concludes that the promulgation of regulations is
not a major Federal action significantly affecting the human
environment. Whether or not a detailed EIS is required turns on the
significance of the effects of the decision before the Secretary, not
all of the impacts of commercial oil shale development. The Secretary
has long had statutory authority to lease Federal oil shale without any
regulations. The promulgation of this largely procedural rule itself
will not cause any impacts to the quality of the human environment,
much less ``significant'' ones.
Comment EA-10: The BLM inappropriately tiered the draft EA to the
PEIS, and therefore the BLM's reliance on the PEIS as the source of
information about environmental consequences of the rule is not
grounded in law and nor provides a thorough or defensible analysis of
specific technologies and associated impacts. The BLM cannot tier its
EA to the PEIS.
The comment is accurate that it was inappropriate to describe the
EA as tiered to the PEIS. The EA was modified to clarify that it was
the BLM's intent to incorporate by reference the impact analysis, and
not tier to the PEIS. Tiering is distinct from incorporation by
reference. Incorporation by reference allows information presented in
one source to be referred to in another source, without the necessity
of simply copying out that information. As explained in the draft EA,
the EA incorporates by reference information on the environmental
consequences of the development of oil shale resource that is presented
in the Chapter 4 of the PEIS. This was done to inform the decision-
makers as to the possible environmental consequences of developing
these resources.
Comment EA-11: The BLM did not publish the draft EA or provide
copies of the document to the states of Colorado, Wyoming, and Utah
until requested.
There is no legal requirement to publish a draft EA for public
comment. Nonetheless, the BLM did notify the public of the availability
of the draft EA. The BLM placed the EA on file in the BLM
Administrative Record at the address specified in the ADDRESSES section
of the Federal Register Notice for the proposed rule. The BLM invited
the public to review these documents and suggested that anyone wishing
to submit comments in response to the EA do so in accordance with the
Public Comment Procedures section. Although the BLM is under no
obligation to provide copies of the document to the States of Colorado,
Wyoming, and Utah, of course BLM did provide copies to the state
agencies, as it would any other member of the public, upon request.
Comment EA-12: The draft EA failed to analyze the impacts of
climate change and take actions to reduce it.
The rule does not authorize or cause any surface disturbing
activity and therefore will not cause either the emissions of
greenhouse gases (GHG), or any impacts to the climate. The EA
incorporates by reference the description of the affected environment
from the PEIS which reflects the current condition of resources in the
area where oil shale is found, which reflects any effects to date of
the climate change phenomenon. It also incorporates the generic impact
analysis from Chapter 4 of the PEIS, including a discussion of the
possible impacts from development of oil shale resources on air
quality, as well as any GHG emissions that may result from this
development. The discussion also presents potential mitigation measures
that may be considered for use, if warranted, on the basis of project-
specific NEPA analysis to be conducted at appropriate decision points.
The EA was modified to make it clear that information concerning
climate change was incorporated by reference.
Comment EA-13: Commenter references information or analysis
contained in the PEIS and alleges that the BLM has not adequately
addressed the impacts of oil shale activities on various resources like
climate change, wildlife, fish, and water usage, etc.
The commenter did not specify any information that was not analyzed
nor any impacts attributable to the contemplated rulemaking. It is even
unclear whether the commenter is referring to the analysis contained or
incorporated in the EA. The analysis in and incorporated in the EA is
adequate for the purpose of informing the choices in the rulemaking.
Comment EA-14: The BLM incorrectly determined to prepare an EA
versus an EIS. Based on the draft EA, it is clear that oil shale
development on the public lands will have a significant impact on the
environment. Further environmental review is needed, otherwise the
finalization of the rule is arbitrary and capricious.
The regulations do not cause any change to the environment, but
establish processes for review of proposals to lease and develop oil
shale. The Secretary's authority to lease is long-standing and is not
dependent upon promulgation of the regulations. Likewise, oil shale
development on the public lands is separate from, and was not prior to
EP Act dependent upon, the regulations. There is nothing arbitrary or
capricious about the regulations or the EA.
The BLM prepared the EA in accordance with CEQ regulations
implementing NEPA, and relevant Departmental guidance, in order to
determine whether the proposed action of establishing a procedural
framework governing a leasing program for the development of oil shale
resources may result in significant effects on the quality of the human
environment, and to inform the decision maker. As explained in the EA,
the establishment of the rule is largely a procedural enterprise, with
no environmental effects. It does not represent a decision to authorize
such development and therefore such development is not an indirect
effect of the action. Accordingly, the significance of impacts of that
development does not affect the finding that the rule does not have
significant impacts. Even if an EIS were required, the BLM has analyzed
the environmental consequences of the commercial development of oil
shale on Federal lands at a programmatic level in the PEIS.
Comment EA-15: The BLM failed to consult with the FWS concerning
the proposed development impacts on endangered and threatened species
in the region and therefore violates the ESA.
The rule does not issue any permit or lease or approve the issuance
of any plan of oil shale development. There is no proposed oil shale
development associated with the rule. The BLM determined that this rule
would have no effect on listed or proposed species, or on designated or
proposed critical habitat, under the ESA, and therefore consultation
under Section 7 of the ESA is not be required. Moreover, nothing in the
rule changes existing processes and procedures that ensure the
protection of listed or proposed species or designated or proposed
critical habitat. Further compliance with the ESA will occur if and
when applications are filed with the BLM.
Comment EA-16: The lack of knowledge of oil shale operations makes
it impossible for the BLM to adequately
[[Page 69456]]
explain how this industry will not have a significant affect on the
environment.
The commenter is confusing the nature and scope of the proposed
action for the EA with oil shale industrial development. The EA does
not conclude that the development of oil shale will have no significant
impact on the environment. The EA, analyzes the environmental
consequences of a regulatory framework, which will govern any leasing
of oil shale or authorization of operations on Federal lands. However,
the EA incorporates by reference Chapter 4 of the PEIS, which presents
an analysis of oil shale technologies and their potential environmental
and socio-economic impacts, to the extent they can be predicted, as
well as potential mitigation measures that may be considered, if
warranted, prior to the issuance of a lease. This informs the
rulemaking decision on the nature of the effects of possible future
development of these resources, if there was future commercial leasing
of oil shale resources (see Response to Comments EA-1 and EA-2). The
analyses need only consider available information and not await all the
information needed to support the approval of operations. The impacts
of oil shale operations will be analyzed in future NEPA documents as
decisions become ripe and the necessary information becomes available.
NEPA does not require that the BLM forestall promulgation of
regulations until all impacts of commercial oil shale development are
known with certainty.
Comment EA-17: Comments on the DPEIS were incorporated by reference
to show how oil shale development could not move forward in an
``environmentally sound manner.''
As explained in Response to Comment EA-2, the proposed actions
analyzed in the EA and the PEIS are different, and therefore, these
analyses are different in scope. The commenter has not explained why
these comments need to be addressed in the context of the decision to
adopt this rule.
The comments on the PEIS were appropriately addressed in the Final
PEIS and are located on pages 4785 to 4846, index number 52766. The EA
incorporates by reference the generic analysis that is contained in the
Chapter 4 of the FPEIS, as modified based on the comments received.
Regulatory Flexibility Act
Congress enacted the Regulatory Flexibility Act of 1980 (RFA), as
amended, 5 U.S.C. 601-612, to ensure that Government regulations do not
unnecessarily or disproportionately burden small entities. The RFA
requires a regulatory flexibility analysis if a rule would have a
significant economic impact, either detrimental or beneficial, on a
substantial number of small entities. The RFA establishes an analytical
process for determining how public policy goals can best be achieved
without erecting barriers to competition, stifling innovation, or
imposing undue burdens on small entities. Executive Order 13272
reinforces executive intent that agencies give serious attention to
impacts on small entities and develop regulatory alternatives to reduce
the regulatory burden on small entities. To meet these requirements,
the agency must either conduct a regulatory flexibility analysis or
certify that the final rule will not have ``a significant economic
impact on a substantial number of small entities.''
Section 369 of the EP Act requires the Department to establish
regulations for a commercial oil shale leasing program. Although this
rule would only directly affect entities that choose to explore and
develop oil shale resources from land administered by the BLM, there is
no way to know which firms would hold exploration licenses or leases or
operate on Federal lands in the future. The extent to which the rule
will have an actual impact on any firm depends on whether the firm
would hold exploration licenses or leases or would operate on Federal
lands.
Currently, active oil shale research and development on Federal
lands is limited to a few firms. Chevron, EGL Resources, Oil Shale
Exploration Company, and Shell Oil Company hold R, D and D leases and
are the only companies currently conducting operations on Federal oil
shale leases. Of the four companies holding R, D and D leases, two are
major oil companies and two are small research and development firms.
With implementation of these regulations, technological advances,
and favorable market conditions that would support oil shale
development, the BLM anticipates an increase in the number of firms
involved in oil shale development. However, the number of firms, large
or small, involved in oil shale development on Federal lands would
likely remain quite limited. Given the likely size of the industry that
may eventually be involved in the leasing and development of Federal
oil shale resources, it is reasonable to conclude that this rule would
not significantly impact a ``substantial number of small entities.''
This rule provides for the leasing and management of oil shale
resources on Federal lands. Provisions covered in this rule include
exploration license and competitive leasing procedures, requirements
and terms, and POD and operational requirements.
To explore on Federal lands, the operator would have to have an
exploration license or an oil shale lease. The process to obtain an
exploration license is relatively straightforward and does not entail
significant fees, e.g., $295 nonrefundable filing fee. Commercial oil
shale leases will primarily rely on a process of leasing parcels
nominated by industry. The BLM may also choose to offer certain lands
for lease. With the exception of R, D and D lease conversions, all
leases will be offered competitively. The BLM will not collect an
application or nomination fee; however, the successful high bidder will
be required to pay certain costs associated with the BLM offering the
tract for lease, in addition to the bonus bid. At the time of lease
sale, the high bidder will be required to submit a payment of one fifth
of the amount of the bonus bid. Leases are also subject to a $2.00 per
acre rental.
The terms and conditions for operating under an exploration license
or commercial lease are those needed to protect the environment and
resource values of the area and to ensure reclamation of the lands
disturbed by the activities. Exploration and development plans must be
submitted to the BLM for approval. All operations, whether under an
exploration license or a commercial oil shale lease, are required to
provide the BLM with a license or lease bond. In addition, operators
are required to provide the government with a bond to cover the cost of
site reclamation and closure.
Production from commercial oil shale leases will be subject to a
Federal royalty. A royalty on the amount or value of production removed
or sold from the lease applies to commercial production from these
leases.
The ability to obtain an exploration license and/or to compete for
a commercial oil shale lease is not affected by the size of the
company. Exploration licenses require a nominal filing fee ($295 per
filing) and have no minimum acreage. Leases have no minimum tract
acreage; lease processing costs are paid by the successful bidder; and
bonus bids may be deferred over a 5 year period. These aspects of the
licensing and leasing procedures allow small entities to better compete
for Federal oil shale licenses and leases with larger, well-capitalized
companies. As required by the EP Act, all royalties, rentals, bonus
bids, and other payments in this rule are to encourage development of
the oil shale resources while ensuring a fair return to the
[[Page 69457]]
government. The regulatory provisions, including filing fees, rentals,
and production royalties, will not have a significant economic impact
on lessees or operators, regardless of the firm's size.
Therefore, the BLM has determined that under the RFA this rule does
not have a significant economic impact on a substantial number of small
entities.
Several commenters suggested that there will be significant hurdles
for small entities hoping to participate in the leasing and development
of Federal oil shale resources. The commenter suggested that the
proposed rule creates high hurdles to entry into the industry. The
specific example provided is the combined effect of the minimum bid and
the minimum tract size. The $1,000 per acre minimum bid coupled with
the 160 acre minimum lease size results in a very onerous sum, in the
form of a minimum bonus bid, for small operators. Commenters argued the
minimum lease size needs to be no more than 1-2 acres. Other provisions
identified as unnecessarily creating large up-front costs included
competitive bidding, front-end lease rentals, and lease bonding. A
commenter suggested we created the impression that there are no costs
to the applicant until the small entity becomes the successful bidder.
We agree with the commenters' suggestion that the combined effect
of the minimum bid and minimum lease acreage could be a deterrent to
small entities participating in the leasing and development of oil
shale resources on Federal lands. Based on the comments received, we
have decided to drop the minimum lease acreage requirement from the
final rule. Decisions on tract size will be made as part of the tract
delineation process. We do not agree with the assertion that the other
identified provisions, including the bonus, rental, and bonding
requirements, are significant deterrents to small entities. Clearly
these are costs in obtaining and holding a Federal oil shale lease;
however, they are not burdens created by the regulations, but rather by
statute. As for the suggestion that we implied there are no costs
except for the successful bidder; that was not our intent. It is
important to understand that this is likely to be a high cost industry,
including some of the regulatory and statutory requirements. We have
attempted to reduce the front-loading impact of those costs.
Commenters also argued that the proposed rule allows large entities
to tie up too much of the resource at little cost. They suggest that
the penalties for missing diligence milestones are so insignificant
that a large operator will be able to tie up significant resources for
20 or more years at a maximum cost of $250 per acre per year. Deferred
development for at least ten years and payments in lieu of production
were given as other examples of provisions that allow large, well-
capitalized entities to hold large tracts of oil shale lands.
Given the technological and economic unknowns associated with oil
shale development and the potential for long development timeframes, we
intentionally kept the lease-hold costs down to provide an element of
stability and certainty for entities, large or small, attempting to
develop this vital resource. Large entities may be in a better position
to take advantage of these provisions, but we do not view these
provisions as a deterrent to small entities.
Unfunded Mandates Reform Act
In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501
et seq.) the rule does not impose an unfunded mandate on state, local,
or tribal governments or the private sector, in the aggregate, of $100
million or more per year; nor does this rule have a significant or
unique effect on state, local, or tribal governments. The rule imposes
no requirements on any of those entities. Therefore, the BLM is not
required to prepare a statement containing the information required by
the Unfunded Mandates Reform Act.
Executive Order 12630, Governmental Actions and Interference With
Constitutionally Protected Property Rights (Takings)
This rule is a not a government action capable of interfering with
constitutionally protected property rights. A takings implication
assessment is not required. The rule does not authorize any specific
activities that would result in any effects on private property.
Therefore, the Department has determined that the rule will not cause a
taking of private property or require further discussion of takings
implications under this Executive Order.
Executive Order 13132, Federalism
The rule will not have a substantial direct effect on the states,
on the relationship between the national government and the states, or
on the distribution of power and responsibilities among the levels of
government. It will not apply to states or local governments or state
or local governmental entities. The management of Federal oil shale
leases is the responsibility of the Secretary and the BLM. This rule
does not alter any lease management or revenue sharing provisions with
the states, nor does it impose any costs on the states. Therefore, in
accordance with Executive Order 13132, the BLM has determined that this
rule does not have sufficient Federalism implications to warrant
preparation of a Federalism Assessment.
Executive Order 12988, Civil Justice Reform
Under Executive Order 12988, the BLM determined that this rule
would not unduly burden the judicial system and that it meets the
requirements of sections 3(a) and 3(b)(2) of the Order.
Executive Order 13175, Consultation and Coordination With Indian Tribal
Governments
In accordance with Executive Order 13175, we have found that this
rule may include policies that have Tribal implications. The rule
implements the Federal oil shale leasing and management program, which
does not apply on Indian Tribal lands. At present, there are no oil
shale leases or agreements on Tribal or allotted Indian lands. If
tribes or allottees should ever enter into any leases or agreements
with the approval of the Bureau of Indian Affairs, the BLM would then
likely be responsible for the approval of any proposed operations on
Indian oil shale leases and agreements. In light of this possibility,
and because Tribal interests could be implicated in oil shale leasing
on Federal lands, the BLM began consultation with potentially affected
Tribes on the proposed oil shale regulations, and continued to consult
with Tribes during the comment period on the proposed rule.
On July 21, 2008, the BLM sent consultation letters to all Indian
Tribal Governments potentially affected by the proposed regulations. In
the letter, the BLM offered to meet with any of the Tribal Leaders or
their representatives, and offered them the opportunity to comment on
the proposed rule during the public comment period. As of October 8,
2008, we received one response to our request in the form of a comment
letter. The commenter concluded that the proposed regulations would not
affect their Tribal traditional cultural properties or historic
properties.
Information Quality Act
In developing this rule, we did not conduct or use a study,
experiment or survey requiring peer review under the
[[Page 69458]]
Information Quality Act (Section 515 of Pub. L. 106-554).
Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
In accordance with Executive Order 13211, the BLM has determined
that this rule is not likely to have a substantial direct effect on the
supply, distribution, or use of energy. Executive Order 13211 requires
an agency to prepare a Statement of Energy Effects for a rule that is a
significant regulatory action under Executive Order 12866 or any
successor order and is likely to have a significant adverse effect on
the supply, distribution, or use of energy.
As discussed earlier in this preamble, the BLM believes that the
rule will likely increase energy production and will not have an
adverse effect on the supply, distribution, or use of energy, and
therefore has determined that the preparation of a Statement of Energy
Effects is not required.
Executive Order 13352, Facilitation of Cooperative Conservation
In accordance with Executive Order 13352, the BLM has determined
that this rule will not impede facilitating cooperative conservation;
takes appropriate account of and considers the interests of persons
with ownership or other legally recognized interests in the land or
other natural resources; properly accommodates local participation in
the Federal decision making process; and provides that the programs,
projects, and activities are consistent with protecting public health
and safety. The BLM, in coordination with the MMS, held three
``listening sessions'' with representatives of the governors of the
states of Colorado, Utah, and Wyoming. The purpose of the ``listening
sessions'' was to provide the governor's 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 that not later than 180 days after the publication
of the final regulations, the Secretary (as delegated to the BLM), is
to consult with the governors of the states with significant oil shale
and tar sands resources on public lands, representatives of local
governments in such states, interested Indian tribes, and other
interested persons to determine the level of support and interest in
the states in the development of oil shale resources. In addition, the
regulations contain a section providing for comments from state
governors, local governments, and interested Indian tribes prior to
offering lands for lease for oil shale. The comment period will occur
prior to the BLM's publication of a call for nominations.
Paperwork Reduction Act of 1995 (PRA)
This final rule contains new information collection requirements.
As required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)),
OMB has reviewed and approved the information collection requirements
and assigned OMB control number 1004-0201, which expires November 30,
2011.
The title of the new information collection request (ICR) is
``Parts 3900-3930--Oil Shale Management--General.'' This final rule
establishes regulations for a commercial leasing oil shale leasing
program. The BLM will collect information from individuals,
corporations, and associations in order to:
(1) Learn the extent and qualities of the public oil shale
resource;
(2) Evaluate the environmental impacts of oil shale leasing and
development;
(3) Determine the qualifications of prospective lessees to acquire
and hold Federal oil shale leases;
(4) Administer statutes applicable to oil shale mining, production,
resource recovery and protection, operations under oil shale leases,
and exploration under leases and licenses;
(5) Ensure lessee compliance with applicable statutes, regulations,
and lease terms and conditions; and
(6) Ensure that accurate records are kept of all Federal oil shale
produced.
Prospectively estimating the annual burden hours for the commercial
oil shale program is difficult because the oil shale industry is at the
research and development stage where there is a lack of available
information and the future technology to be used is uncertain. The
burden hour estimates in the following charts were modeled on a
previous ICR completed for the Federal coal program, as the information
collection associated with that program is somewhat similar to the
planned oil shale leasing program. The coal burden hour estimates were
adjusted to reflect the differences in the two processes. It is also
difficult to make a prospective estimate of the number of annual
responses; therefore, the BLM has used one response for each activity
as a starting point, except for the number of applications received. We
anticipate that we could receive several applications after these
regulations go into effect. The BLM estimates that this ICR for the oil
shale management program will result in 23 responses totaling 1,794
burden hours (Table 1). The BLM also estimates that there will be
processing/cost recovery fees in the amount of $526,652 (Table 2).
We received one public comment that addressed the information
collection aspects of the proposed rule. It mainly stated that the PRA
requires the BLM to develop a final rule that maximizes the utility and
the public benefit of the information collected in lease applications,
and went on to say that this requirement dovetails with the
requirements in the EP Act that the regulations encourage initial
development and sustain diligent development throughout the life of the
lease, because initiating and sustaining predictable development are
prerequisites for minimizing uncertainty in state and local impact
projections. The comment urged that these interconnected principles
require that the BLM establish a royalty rate sufficiently low to
ensure that development will be initiated and diligently pursued,
citing foreign examples where royalties on tar sands were entirely
forgiven and successfully encouraged development, and where a 1.8
percent royalty led to a commercially viable oil shale project. We
address the royalty rate and the rationale for selecting it the
preamble discussion of section 3903.52.
The comment also stated that the information collection clearance
package that the BLM submitted to OMB at the time the proposed rule was
published contained a premature, and thus invalid, certification that
we had complied with the requirements of section 3506(c)(3) of the PRA.
The comment stated that we could not make this certification until we
had considered public comments submitted on the information collection,
and concluded that we need to describe in the supporting material how
the BLM would use the two principles discussed in the preceding
paragraph that govern royalty determination to ensure that the agency
will maximize the utility and public benefit of the information
collected.
The certification is made by the Department as part of the routine
submission of the information collection to OMB, but the certification
is not effective and was never intended to be effective until it is
finally approved by OMB. The certification was not premature--the
proposed rule could not be submitted to OMB without the certification.
The comment concluded by urging that the OMB Terms of Clearance for
the Information Collection Request should
[[Page 69459]]
require that the record demonstrating the BLM's compliance with the
royalty principles of encouraging and sustaining diligent development
be included in the preamble of the final rule. As stated earlier, this
information appears elsewhere in this preamble.
See the following tables for burden hours and processing/cost
recovery fees by CFR citation:
Burden Breakdown
Table 1
----------------------------------------------------------------------------------------------------------------
Average number
Parts 3900-3930 burden activity Information collected Hour burden of annual Average annual
responses burden hours
----------------------------------------------------------------------------------------------------------------
Subpart 3904--Bonds and Trust Funds
----------------------------------------------------------------------------------------------------------------
A prospective lessee or licensee Section 3904.12--File one 1 1 1
must furnish a bond before a lease copy of the bond form with
or exploration license may be original signatures in the
issued or transferred or a POD proper BLM state office.
approved. Bonds must be filed on an
approved BLM form. The
obligor of a personal bond
must sign the form. Surety
bonds must have the
lessee's and the
acceptable surety's
signature.
The BLM will review the bond and, Section 3904.14(c)(1)-- 1 1 1
if adequate as to amount and Prior to the approval of a
execution, will accept it in order POD, in those instances
to indemnify the United States where a state bond will be
against default on payments due or used to cover all of the
other performance obligations. The BLM's reclamation
BLM may also adjust the bond requirements, evidence
amount to reflect changed verifying that the
conditions. The BLM will cancel existing state bond will
the bond when all requirements are satisfy all the BLM
satisfied. reclamation bonding
requirements must be filed
in the proper BLM office.
The BLM will use no
specific form to collect
this information.
----------------------------------------------------------------------------------------------------------------
Part 3910--Oil Shale Exploration Licenses
----------------------------------------------------------------------------------------------------------------
For those lands where no Section 3910.31--The BLM 24 1 24
exploration data is available, the will use no specific form
lease applicant may apply for an to collect the
exploration license to conduct information. The applicant
exploration on unleased public will be required to submit
lands to determine the extent and the following information:
specific characteristics of the (1) Name and address of
Federal oil shale resource. applicant(s);.
(2) A nonrefundable filing
fee of $295;.
(3) A general description
of the area to be drilled
described by legal land
description; and.
(4) 3 copies of an
exploration plan that
includes the exact
location of the affected
lands, the name, address,
and telephone number of
the party conducting the
exploration activities, a
description of the
proposed methods and
extent of exploration, and
reclamation.
The BLM will use the information in
the application to:
(1) Locate the proposed
exploration site;
(2) Determine if the lands are
subject to entry for
exploration;
(3) Prepare a notice of
invitation to other parties to
participate in the
exploration; and
(4) Ensure the exploration plan
is adequate to safeguard
resource values, and public
and worker health and safety.
The BLM will use this information Section 3910.44--Upon the 8 1 8
from a licensee to determine if it BLM's request, the
will offer the land area for lease. licensee must provide
copies of all data
obtained under the
exploration license in the
format requested by the
BLM. The BLM will consider
the data confidential and
proprietary until the BLM
determines that public
access to the data will
not damage the competitive
position of the licensee
or the lands involved have
been leased, whichever
comes first. Submit all
data obtained under the
exploration license to the
proper BLM office.
----------------------------------------------------------------------------------------------------------------
[[Page 69460]]
Subpart 3921--Pre-Sale Activities
----------------------------------------------------------------------------------------------------------------
Corporations, associations, and Section 3921.30--The BLM 4 1 4
individuals may submit expressions will request this
of leasing interest for specific information through the
areas to assist the applicable BLM publication of a notice in
State Director in determining the Federal Register and
whether or not to lease oil shale. will use no specific form
The information provided will be to collect the
used in the consultation with the information. The
governor of the affected state and expression of leasing
in setting a geographic area for interest will contain
which a call for applications will specific information
be requested. consisting of name and
address and area of
interest described by
legal land description.
----------------------------------------------------------------------------------------------------------------
Subpart 3922--Application Processing
----------------------------------------------------------------------------------------------------------------
Entities interested in leasing the Section 3922.20 and 308 3 924
Federal oil shale resource must 3922.30--Lease
file an application in a applications must be filed
geographic area for which the BLM in the proper BLM state
has issued a ``Call for office. No specific form
Applications.'' The information of application is
provided by the applicant will be required, but the
used to evaluate the impacts of application must include
issuing a proposed lease on the information necessary to
human environment. Failure to evaluate the impacts of
provide the requested additional issuing the proposed lease
information may result in on the human environment,
suspension or termination of including, but not limited
processing of the application or to, the following:
in a decision to deny the (1) Name, address,
application. telephone number of
applicant, and a
qualification statement,
as required by subpart
3902;.
(2) A delineation of the
proposed lease area or
areas, the surface
ownership (if other than
the United States) of
those areas, a description
of the quality, thickness,
and depth of the oil shale
and of any other resources
the applicant proposes to
extract, and environmental
data necessary to assess
impacts from the proposed
development;.
(3) A description of the
proposed extraction
method, including
personnel requirements,
production levels, and
transportation methods
including:
(a) A description of the
mining, retorting, or in
situ mining or processing
technology that the
operator would use and
whether the proposed
development technology is
substantially identical to
a technology or method
currently in use to
produce marketable
commodities from oil shale
deposits;
(b) An estimate of the
maximum surface area of
the lease area that will
be disturbed or undergoing
reclamation at any one
time;
(c) A description of the
source and quantities of
water to be used and of
the water treatment and
disposal methods necessary
to meet applicable water
quality standards;
(d) A description of the
regulated air emissions;
(e) A description of the
anticipated noise levels
from the proposed
development;
(f) A description of how
the proposed lease
development would comply
with all applicable
statutes and regulations
governing management of
chemicals and disposal of
solid waste. If the
proposed lease development
would include disposal of
wastes on the lease site,
include a description of
measures to be used to
prevent the contamination
of soil and of surface and
ground water;
[[Page 69461]]
(g) A description of how
the proposed lease
development would avoid,
or, to the extent
practicable, mitigate
impacts to species or
habitats protected by
applicable state or
Federal law or
regulations, and impacts
to wildlife habitat
management;
(h) A description of
reasonably foreseeable
social, economic, and
infrastructure impacts to
the surrounding
communities, and to state
and local governments from
the proposed development;
(i) A description of the
known historical,
cultural, or archeological
resources within the lease
area;
(j) A description of
infrastructure that would
likely be required for the
proposed development and
alternative locations of
those facilities, if
applicable;
(k) A discussion of
proposed measures or plans
to mitigate any adverse
socioeconomic or
environmental impacts to
local communities,
services and
infrastructure;
(l) A brief description of
the reclamation methods
that will be used;
(m) Any other information
that shows that the
application meets the
requirements of this
subpart or that the
applicant believes would
assist the BLM in
analyzing the impacts of
the proposed development;
and
(n) A map, or maps,
showing:
(i) The topography,
physical features, and
natural drainage patterns;
(ii) Existing roads,
vehicular trails, and
utility systems;
(iii) The location of any
proposed exploration
operations, including
seismic lines and drill
holes;
(iv) To the extent known,
the location of any
proposed mining operations
and facilities, trenches,
access roads, or trails,
and supporting facilities
including the approximate
location and extent of the
areas to be used for pits,
overburden, and tailings;
and
(v) The location of water
sources or other resources
that may be used in the
proposed operations and
facilities.
At any time during
processing of the
application, or the
environmental or similar
assessments of the
application, the BLM may
request additional
information from the
applicant.
----------------------------------------------------------------------------------------------------------------
Subpart 3924--Lease Sale Procedures
----------------------------------------------------------------------------------------------------------------
Prospective lessees will be Section 3924.10--The BLM 8 1 8
required to submit a bid at a will request the following
competitive sale in order to be bid information via the
issued a lease. notice of oil shale lease
sale:
(1) A certified check,
cashier's check, bank
draft, money order,
personal check, or cash
for one-fifth of the
amount of the bonus; and.
(2) A qualifications
statement signed by the
bidder as described in
subpart 3902.
----------------------------------------------------------------------------------------------------------------
[[Page 69462]]
Subpart 3926--Conversion of Preference Right for Research, Demonstration, and Development (R, D and D) Leases
----------------------------------------------------------------------------------------------------------------
The lessee of an R, D and D lease Section 3926.10(c)--A 308 1 308
may apply for conversion of the R, lessee of an R, D and D
D and D lease to a commercial lease identified in
lease. subpart 3926 must apply
for the conversion of the
R, D and D lease to a
commercial lease no later
than 90 days after the
commencement of production
in commercial quantities.
No specific form of
application is required.
The application for
conversion must be filed
in the BLM state office
that issued the R, D and D
lease. The conversion
application must include:
(1) Documentation that
there has been commercial
quantities of oil shale
produced from the lease,
including the narrative
required by section 23 of
R, D and D leases; and
(2) Documentation that the
lessee consulted with
state and local officials
to develop a plan for
mitigating the
socioeconomic impacts of
commercial development on
communities and
infrastructure.
(3) A bonus payment equal
to the FMV of the lease;
and
(4) Bonding to cover all
costs associated with
reclamation.
----------------------------------------------------------------------------------------------------------------
Subpart 3930--Management of Oil Shale Exploration and Leases
----------------------------------------------------------------------------------------------------------------
The records, logs, and samples Section 3930.11(b)--The 19 1 19
provide information necessary to operator/lessee must
determine the nature and extent of retain for one year all
oil shale resources on Federal drill and geophysical
lands and to monitor and adjust logs. The operator must
the extent of the oil shale also make such logs
reserve. available for inspection
or analysis by the BLM.
The BLM may require the
operator/lessee to retain
representative samples of
drill cores for 1 year.
The BLM uses no specific
form to collect the
information.
Section 3930.20 (b)--The 19 1 19
operator must record any
new geologic information
obtained during mining or
in situ development
operations regarding any
mineral deposits on the
lease. The operator must
report this new
information in a BLM-
approved format to the
proper BLM office within
90 days of obtaining the
information.
----------------------------------------------------------------------------------------------------------------
Subpart 3931--Plans of Development and Exploration Plans
----------------------------------------------------------------------------------------------------------------
The plan of development (POD) must Section 3931.11--The POD 308 1 308
provide for reasonable protection must contain, at a
and reclamation of the environment minimum, the following:
and the protection and diligent (a) Names, addresses, and
development of the oil shale telephone numbers of those
resources in the lease. responsible for operations
to be conducted under the
approved plan and to whom
notices and orders are to
be delivered, names and
addresses of Federal oil
shale lessees and
corresponding Federal
lease serial numbers, and
names and addresses of
surface and mineral owners
of record, if other than
the United States;.
(b) A general description
of geologic conditions and
mineral resources within
the area where mining is
to be conducted, including
appropriate maps;
[[Page 69463]]
(c) A copy of a suitable
map or aerial photograph
showing the topography,
the area covered by each
lease, the name and
location of major
topographic and cultural
features;
(d) A statement of proposed
methods of operation and
development, including the
following items as
appropriate:
(1) A description detailing
the extraction technology
to be used;
(2) The equipment to be
used in development and
extraction;
(3) The proposed access
roads;
(4) The size, location, and
schematics of all
structures, facilities,
and lined or unlined pits
to be built;
(5) The stripping ratios,
development sequence, and
schedule;
(6) The number of acres in
the Federal lease(s) or
license(s) to be affected;
(7) Comprehensive well
design and procedure for
drilling, casing,
cementing, testing,
stimulation, clean-up,
completion, and
production, for all
drilled well types,
including those used for
heating, freezing, and
disposal;
(8) A description of the
methods and means of
protecting and monitoring
all aquifers;
(9) Surveyed well location
plats or project-wide well
location plats;
(10) A description of the
measurement and handling
of produced fluids,
including the anticipated
production rates and
estimated recovery
factors; and
(11) A description/
discussion of the controls
that the operator will use
to protect the public,
including identification
of:
(i) Essential operations,
personnel, and health and
safety precautions;
(ii) Programs and plans for
noxious gas control
(hydrogen sulfide,
ammonia, etc.);
(iii) Well control
procedures;
(iv) Temporary abandonment
procedures; and
(v) Plans to address
spills, leaks, venting,
and flaring;
(e) An estimate of the
quantity and quality of
the oil shale resources;
(f) An explanation of how
MER of the resource will
be achieved for each
Federal lease; and
(g) Appropriate maps and
cross sections showing:
(1) Federal lease
boundaries and serial
numbers;
(2) Surface ownership and
boundaries;
(3) Locations of any
existing and abandoned
mines and existing oil and
gas well (including well
bore trajectories) and
water well locations,
including well bore
trajectories;
(4) Typical geological
structure cross sections;
(5) Location of shafts or
mining entries, strip
pits, waste dumps, retort
facilities, and surface
facilities;
(6) Typical mining or in
situ development sequence,
with appropriate time-
frames;
[[Page 69464]]
(h) A narrative addressing
the environmental aspects
of the proposed mine or in
situ operation, including
at a minimum, the
following:
(1) An estimate of the
quantity of water to be
used and pollutants that
may enter any receiving
waters;
(2) A design for the
necessary impoundment,
treatment, control, or
injection of all produced
water, runoff water, and
drainage from workings;
and
(3) A description of
measures to be taken to
prevent or control fire,
soil erosion, subsidence,
pollution of surface and
ground water, pollution of
air, damage to fish or
wildlife or other natural
resources, and hazards to
public health and safety;
(i) A reclamation plan and
schedule for all Federal
lease(s) or exploration
license(s) that details
all reclamation activities
necessary to fulfill the
requirements of Sec.
3931.20;
(j) The method of
abandonment of operations
on Federal lease(s) and
exploration license(s)
proposed to protect the
unmined recoverable
reserves and other
resources, including:
(1) The method proposed to
fill in, fence, or close
all surface openings that
are hazardous to people or
animals; and
(2) For in situ operations,
a description of the
method and materials to be
used to plug all abandoned
development or production
wells; and
(k) Any additional
information that the BLM
determines is necessary
for analysis or approval
of the POD.
The BLM may, in the interest of Section 3931.30--An 24 1 24
conservation order or agree to a application by a lessee
suspension of operations and for suspension of
production. operations and production
must be filed in duplicate
in the proper BLM office
and must set forth why it
is in the interest of
conservation to suspend
operations and production.
The BLM will use no
specific form to collect
this information.
Except for casual use, before Section 3931.41--The BLM 24 1 24
conducting any exploration will use no specific form
operations on federally-leased or to collect this
federally-licensed lands, the information. Exploration
lessee must submit an exploration plans must contain the
plan to the BLM for approval. following information:
(1) The name, address, and
telephone number of the
applicant, and, if
applicable, that of the
operator or lessee of
record;.
(2) The name, address, and
telephone number of the
representative of the
applicant who will be
present during, and
responsible for,
conducting exploration;
(3) A description of the
proposed exploration area,
cross-referenced to the
map required under section
3931.41, including:
(a) Applicable Federal
lease and exploration
license serial numbers;
(b) Surface topography;
(c) Geologic, surface
water, and other physical
features;
(d) Vegetative cover;
(e) Endangered or
threatened species listed
under the Endangered
Species Act of 1973 (16
U.S.C. 1531 et seq.) that
may be affected by
exploration operations;
[[Page 69465]]
(f) Districts, sites,
buildings, structures, or
objects listed on, or
eligible for listing on,
the National Register of
Historic Places that may
be present in the lease
area; and
(g) Known cultural or
archeological resources
located within the
proposed exploration area;
(4) A description of the
methods to be used to
conduct oil shale
exploration, reclamation,
and abandonment of
operations, including, but
not limited to:
(a) The types, sizes,
numbers, capacity, and
uses of equipment for
drilling and blasting and
road or other access route
construction;
(b) Excavated earth-
disposal or debris-
disposal activities;
(c) The proposed method for
plugging drill holes; and
(d) The estimated size and
depth of drill holes,
trenches, and test pits;
(5) An estimated timetable
for conducting and
completing each phase of
the exploration, drilling,
and reclamation;
(6) The estimated amounts
of oil shale or oil shale
products to be removed
during exploration, a
description of the method
to be used to determine
those amounts, and the
proposed use of the oil
shale removed;
(7) A description of the
measures to be used during
exploration for Federal
oil shale to comply with
the performance standards
for exploration (43 CFR
3930.10) and applicable
requirements of an
approved state program;
(8) A map at a scale of
1:24,000 or larger showing
the areas of land to be
affected by the proposed
exploration and
reclamation. The map must
show:
(a) Existing roads,
occupied dwellings, and
pipelines;
(b) The proposed location
of trenches, roads, and
other access routes and
structures to be
constructed;
(c) Applicable Federal
lease and exploration
license boundaries;
(d) The location of land
excavations to be
conducted;
(e) Oil shale exploratory
holes to be drilled or
altered;
(f) Earth-disposal or
debris-disposal areas;
(g) Existing bodies of
surface water; and
(h) Topographic and
drainage features; and
(9) The name and address of
the owner of record of the
surface land, if other
than the United States. If
the surface is owned by a
person other than the
applicant or if the
Federal oil shale is
leased to a person other
than the applicant, a
description of the basis
upon which the applicant
claims the right to enter
that land for the purpose
of conducting exploration
and reclamation.
[[Page 69466]]
Approved exploration, mining and in Section 3931.50--The BLM 24 1 24
situ development plans may be will use no specific form
modified by the operator or lessee to collect this
to adjust to changed conditions, information. The operator
new information, improved methods, or lessee may apply in
and new or improved technology, or writing to the BLM for
to correct an oversight. modification of the
approved exploration plan
or POD to adjust to
changed conditions, new
information, improved
methods, and new or
improved technology, or to
correct an oversight. To
obtain approval of an
exploration plan or POD
modification, the operator
or lessee must submit to
the proper BLM office a
written statement of the
proposed modification and
the justification for such
modification.
Production of all oil shale Section 3931.70--(1) Report 16 1 16
products or byproducts must be production of all oil
reported to the BLM on a monthly shale products or by-
basis. products to the BLM on a
monthly basis.
(2) Report all production
and royalty information to
the MMS under 30 CFR parts
210 and 216.
(3) Submit production maps
to the proper BLM office
at the end of each royalty
reporting period or on a
schedule determined by the
BLM. Show all excavations
in each separate bed or
deposit on the maps so
that the production of
minerals for any period
can be accurately
ascertained. Production
maps must also show
surface boundaries, lease
boundaries, topography,
and subsidence resulting
from mining activities.
(4) For in situ development
operations, the lessee or
operator must submit a map
showing all surface
installations including
pipelines, meter
locations, or other points
of measurement necessary
for production
verification as part of
the POD. All maps must be
modified as necessary to
adequately represent
existing operations.
(5) Within 30 days after
well completion, the
lessee or operator must
submit to the proper BLM
office 2 copies of a
completed Form 3160-4,
Well Completion or
Recompletion Report and
Log, limited to
information that is
applicable to oil shale
operations. Well logs may
be submitted
electronically using a BLM
approved electronic
format. Describe surface
and bottom-hole locations
in latitude and longitude.
[[Page 69467]]
Within 30 days after drilling Section 3931.80--Within 30 16 1 16
completion the operator or lessee days after drilling
must submit to the BLM a signed completion, the operator
copy of records of all core or or lessee must submit to
test holes made on the lands the proper BLM office a
covered by the lease or signed copy of records of
exploration license. all core or test holes
made on the lands covered
by the lease or
exploration license. The
records must show the
position and direction of
the holes on a map. The
records must include a log
of all strata penetrated
and conditions
encountered, such as
water, gas, or unusual
conditions, and copies of
analysis of all samples.
Provide this information
to the proper BLM office
in either paper copy or in
a BLM-approved electronic
format. Within 30 days
after creation, the
operator or lessee must
also submit to the proper
BLM office a detailed
lithologic log of each
test hole and all other in-
hole surveys or other logs
produced. Upon the BLM's
request, the operator or
lessee must provide to the
BLM splits of core samples
and drill cuttings.
----------------------------------------------------------------------------------------------------------------
Subpart 3932--Lease Modifications and Readjustments
----------------------------------------------------------------------------------------------------------------
A lessee may apply for a Section 3932.10(b) and
modification of a lease to include Section 3932.30(c)--The
additional Federal lands adjoining BLM will use no specific
those in the lease. form to collect this
information. An
application for
modification of the lease
size must:.
(1) Be filed with the 12 1 12
proper BLM office;
(2) Contain a legal
description of the
additional lands involved;
(3) Contain a justification
for the modification;
(4) Explain why the
modification would be in
the best interest of the
United States;
(5) Include a nonrefundable
processing fee that the
BLM will determine under
43 CFR 3000.11; and
(6) Include a signed
qualifications statement
consistent with subpart
3902. Before the BLM will
approve a lease
modification, the lessee
must file a written
acceptance of the
conditions in the modified
lease and a written
consent of the surety
under the bond covering
the original lease as
modified. The lessee must
also submit evidence that
the bond has been amended
to cover the modified
lease.
----------------------------------------------------------------------------------------------------------------
Subpart 3933--Assignments and Subleases
----------------------------------------------------------------------------------------------------------------
Any lease may be assigned or Section 3933.31--(1) The 10 2 20
subleased, and any exploration BLM will use no specific
license may be assigned, in whole form to collect this
or in part to any person, information. File in
association, or corporation that triplicate at the proper
meets the qualification BLM office a separate
requirements at subpart 3902. instrument of assignment
for each assignment. File
the assignment application
within 90 days of the date
of final execution of the
assignment instrument and
with it include:
(a) Name and current
address of assignee;
(b) Interest held by
assignor and interest to
be assigned;
(c) The serial number of
the affected lease or
license and a description
of the lands to be
assigned as described in
the lease or license;
(d) Percentage of
overriding royalties
retained; and
(e) Date and signature of
assignor.
[[Page 69468]]
(2) The assignee must
provide a single copy of
the request for approval
of assignment which must
contain a:
(a) Statement of
qualifications and
holdings as required by
subpart 3902;
(b) Date and signature of
assignee; and
(c) Nonrefundable filing
fee of $60.
----------------------------------------------------------------------------------------------------------------
Subpart 3934--Relinquishments, Cancellations, and Terminations
----------------------------------------------------------------------------------------------------------------
A lease or exploration license may Section 3934.10--The BLM 18 1 18
be surrendered in whole or in part. will use no specific form
to collect this
information. The record
title holder must file a
written relinquishment, in
triplicate, in the BLM
state office having
jurisdiction over the
lands covered by the
relinquishment.
----------------------------------------------------------------------------------------------------------------
Subpart 3935--Production and Sale Records
----------------------------------------------------------------------------------------------------------------
Operators or lessees must maintain Section 3935.10--Operators
production and sale records which or lessees must maintain
must be available for the BLM's accurate records:
examination during regular (1) Oil shale mined;.......
business hours. (2) Oil shale put through
the processing plant and
retort;.
(3) Mineral products
produced and sold;
(4) Shale oil products, 16 1 16
shale gas, and shale oil
by-products sold;
(5) Relevant quality
analyses of oil shale
mined or processed and of
synthetic petroleum, shale
oil or shale oil by-
products sold; and
(6) Shale oil products and
by-products that are
consumed on lease for the
beneficial use of the
lease.
-----------------------------------------------
Totals......................... ........................... .............. 23 1,794
----------------------------------------------------------------------------------------------------------------
Based on an average number of actions, we estimate the processing
and cost recovery fees as follows:
Table 2
----------------------------------------------------------------------------------------------------------------
Total
Estimated collections from Estimated Processing fee per Estimated case-by- estimated
processing and cost recovery case- number of action case cost recovery annual
by-case fees actions fee per action collection
----------------------------------------------------------------------------------------------------------------
Part 3910--Oil Shale Exploration 1 $295................. Not Applicable...... $295
Licenses.
Subpart 3922--Application 3 Not Applicable....... $172,323............ 516,969
Processing.
The case-by-case processing fee
does not include any required
studies or analyses that are
completed by third party
contractors and funded by the
applicant. The regulations at 43
CFR 3000.11 provide the
regulatory framework for
determining the cost recovery
value.
Subpart 3925--Award of Lease...... 1 $60.................. Not Applicable...... 60
The successful bidder must submit
the necessary lease bond (see
subpart 3904), the first year's
rental, and the bidder's
proportionate share of the cost
of publication of the sale
notice.
Subpart 3932--Lease Size 1 Not Applicable....... $9,208.............. 9,208
Modification.
Subpart 3933--Assignments and 2 $60.................. Not Applicable...... 120
Subleases.
-----------------------------------------------------------------------------
Totals........................ 8 ..................... .................... 526,652
----------------------------------------------------------------------------------------------------------------
If you have any questions or comments on any aspect of this
information collection, please contact Mitchell Leverette, Chief,
Division of Solid Minerals (320), Bureau of Land Management, 1620 L
Street, NW., Suite 501, Department of the Interior, Washington DC
20236.
[[Page 69469]]
Authors
The principal authors of this rule are Charlie Beecham, II, and
Mary Linda Ponticelli, Division of Solid Minerals (Washington Office);
assisted by Mavis Love, BLM Wyoming State Office; James Kohler, Sr.,
BLM Utah State Office; Hank Szymanski, BLM Colorado State Office; Paul
McNutt, Division of Solid Minerals (Washington Office); Kelly Odom,
Division of Regulatory Affairs (Washington Office); and Richard McNeer,
Department of the Interior, Office of the Solicitor.
List of Subjects
43 CFR Part 3900
Administrative practice and procedure, Environmental protection,
Intergovernmental relations, Mineral royalties, Oil shale reserves,
Public lands-mineral resources, Reporting and recordkeeping
requirements, Surety bonds.
43 CFR Part 3910
Environmental protection, Exploration licenses, Intergovernmental
relations, Oil shale reserves, Public lands--mineral resources,
Reporting and recordkeeping requirements.
43 CFR Part 3920
Administrative practice and procedure, Environmental protection,
Intergovernmental relations, Oil shale reserves, public lands--mineral
resources, Reporting and recordkeeping requirements.
43 CFR Part 3930
Administrative practice and procedure, Environmental protection,
Mineral royalties, Oil shale reserves, Public lands--mineral resources,
Reporting and recordkeeping requirements, Surety bonds.
0
Accordingly, for the reasons stated in the preamble and under the
authorities stated below, the BLM amends 43 CFR subtitle B Chapter II
as follows:
Dated: October 31, 2008.
C. Stephen Allred,
Assistant Secretary, Land and Minerals Management.
0
1. Add part 3900 to subchapter C to read as follows:
PART 3900--OIL SHALE MANAGEMENT--GENERAL
Subpart 3900--Oil Shale Management--Introduction
Sec.
3900.2 Definitions.
3900.5 Information collection.
3900.10 Lands subject to leasing.
3900.20 Appealing the BLM's decision.
3900.30 Filing documents.
3900.40 Multiple use development of leased or licensed lands.
3900.50 Land use plans and environmental considerations.
3900.61 Federal minerals where the surface is owned or administered
by other Federal agencies, by state agencies or charitable
organizations, or by private entities.
3900.62 Special requirements to protect the lands and resources.
Subpart 3901--Land Descriptions and Acreage
3901.10 Land descriptions.
3901.20 Acreage limitations.
3901.30 Computing acreage holdings.
Subpart 3902--Qualification Requirements
3902.10 Who may hold leases.
3902.21 Filing of qualification evidence.
3902.22 Where to file.
3902.23 Individuals.
3902.24 Associations, including partnerships.
3902.25 Corporations.
3902.26 Guardians or trustees.
3902.27 Heirs and devisees.
3902.28 Attorneys-in-fact.
3902.29 Other parties in interest.
Subpart 3903--Fees, Rentals, and Royalties
3903.20 Forms of payment.
3903.30 Where to submit payments.
3903.40 Rentals.
3903.51 Minimum production and payments in lieu of production.
3903.52 Production royalties.
3903.53 Overriding royalties.
3903.54 Waiver, suspension, or reduction of rental or payments in
lieu of production, or reduction of royalty, or waiver of royalty in
the first 5 years of the lease.
3903.60 Late payment or underpayment charges.
Subpart 3904--Bonds and Trust Funds
3904.10 Bonding requirements.
3904.11 When to file bonds.
3904.12 Where to file bonds.
3904.13 Acceptable forms of bonds.
3904.14 Individual lease, exploration license, and reclamation
bonds.
3904.15 Amount of bond.
3904.20 Default.
3904.21 Termination of the period of liability and release of bonds.
3904.40 Long-term water treatment trust funds.
Subpart 3905--Lease Exchanges
3905.10 Oil shale lease exchanges.
Authority: 30 U.S.C. 189, 359, and 241(a), 42 U.S.C. 15927, 43
U.S.C. 1732(b) and 1740.
Subpart 3900--Oil Shale Management--Introduction
Sec. 3900.2 Definitions.
As used in this part and parts 3910 through 3930 of this chapter,
the term:
Acquired lands means lands which the United States obtained through
purchase, gift, or condemnation, including mineral estates associated
with lands previously disposed of under the public land laws, including
the mining laws.
Act means the Mineral Leasing Act of 1920, as amended and
supplemented (30 U.S.C. 181 et seq.).
BLM means the Bureau of Land Management and includes the individual
employed by the Bureau of Land Management authorized to perform the
duties set forth in this part and parts 3910 through 3930.
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 research, development, and demonstration (R, D and D)
lease, based on, and at the conclusion of which, there is a reasonable
expectation 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.
Department means the Department of the Interior.
Diligent development means achieving or completing the prescribed
milestones listed in Sec. 3930.30 of this chapter.
Entity means a person, association, or corporation, or any
subsidiary, affiliate, corporation, or association controlled by or
under common control with such person, association, or corporation.
Exploration means drilling, excavating, and geological, geophysical
or geochemical surveying operations designed to obtain detailed data on
the physical and chemical characteristics of Federal oil shale and its
environment including:
(1) The strata below the Federal oil shale;
(2) The overburden;
(3) The strata immediately above the Federal oil shale; and
(4) The hydrologic conditions associated with the Federal oil
shale.
Exploration license means a license issued by the BLM that allows
the licensee to explore unleased oil shale deposits to obtain geologic,
environmental, and other pertinent data concerning the deposits. An
exploration license confers no preference to a lease to develop oil
shale.
Exploration plan means a plan prepared in sufficient detail to show
the:
(1) Location and type of exploration to be conducted;
(2) Environmental protection procedures to be taken;
(3) Present and proposed roads, if any; and
[[Page 69470]]
(4) Reclamation and abandonment procedures to be followed upon
completion of operations.
Fair market value (FMV) means the monetary amount for which the oil
shale deposit would be leased by a knowledgeable owner willing, but not
obligated, to lease to a knowledgeable purchaser who desires, but is
not obligated, to lease the oil shale deposit.
Federal lands means any lands or interests in lands, including oil
shale interests underlying non-Federal surface, owned by the United
States, without reference to how the lands were acquired or what
Federal agency administers the lands.
Infrastructure means all support structures necessary for the
production or development of shale oil, including, but not limited to:
(1) Offices;
(2) Shops;
(3) Maintenance facilities;
(4) Pipelines;
(5) Roads;
(6) Electrical transmission lines;
(7) Well bores;
(8) Storage tanks;
(9) Ponds;
(10) Monitoring stations;
(11) Processing facilities--retorts; and
(12) Production facilities.
In situ operation means the processing of oil shale in place.
Interest in a lease, application, or bid means any:
(1) Record title interest;
(2) Overriding royalty interest;
(3) Working interest;
(4) Operating rights or option or any agreement covering such an
interest; or
(5) Participation or any defined or undefined share in any
increments, issues, or profits that may be derived from or that may
accrue in any manner from a lease based on or under any agreement or
understanding existing when an application was filed or entered into
while the lease application or bid is pending.
Kerogen means the solid, organic substance in sedimentary rock that
yields oil when it undergoes destructive distillation.
Lease means a Federal lease issued under the mineral leasing laws,
which grants the exclusive right to explore for and extract a
designated mineral.
Lease bond means the bond or equivalent security given to the
Department to assure performance of all obligations associated with all
lease terms and conditions.
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.
Mining waste means all tailings, dumps, deleterious materials, or
substances produced by mining, retorting, or in-situ operations.
MMS means the Minerals Management Service.
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.
Permit means any of the required approvals that are issued by
Federal, state, or local agencies.
Plan of development (POD) means the plan created for oil shale
operations that complies with the requirements of the Act and that
details the plans, equipment, methods, and schedules to be used in oil
shale development.
Production means:
(1) The extraction of shale oil, shale gas, or shale oil by-
products through surface retorting or in situ recovery methods; or
(2) The severing of oil shale rock through surface or underground
mining methods.
Proper BLM office means the Bureau of Land Management office having
jurisdiction over the lands under application or covered by a lease or
exploration license and subject to the regulations in this part and in
parts 3910 through 3930 of this chapter (see subpart 1821 of part 1820
of this chapter for a list of BLM state offices).
Public lands means lands, i.e., surface estate, mineral estate, or
both, which:
(1) Never left the ownership of the United States, including
minerals reserved when the lands were patented;
(2) Were obtained by the United States in exchange for public
lands;
(3) Have reverted to the ownership of the United States; or
(4) Were specifically identified by Congress as part of the public
domain.
Reclamation means the measures undertaken to bring about the
necessary reconditioning of lands or waters affected by exploration,
mining, in situ operations, onsite processing operations or waste
disposal in a manner which will meet the requirements imposed by the
BLM under applicable law.
Reclamation bond means the bond or equivalent security given to the
BLM to assure performance of all obligations relating to reclamation of
disturbed areas under an exploration license or lease.
Secretary means the Secretary of the Interior.
Shale gas means the gaseous hydrocarbon-bearing products of surface
retorting of oil shale or of in situ extraction that is not liquefied
into shale oil. In addition to hydrocarbons, shale gas might include
other gases such as carbon dioxide, nitrogen, helium, sulfur, other
residual or specialty gases, and entrained hydrocarbon liquids.
Shale oil means synthetic petroleum derived from the destructive
distillation of oil shale.
Sole party in interest means a party who alone is or will be vested
with all legal and equitable rights and responsibilities under a lease,
bid, or application for a lease.
Surface management agency means the Federal agency with
jurisdiction over the surface of federally-owned lands containing oil
shale deposits.
State Director means an employee of the Bureau of Land Management
designated as the chief administrative officer of one of the BLM's 12
administrative areas administered by a state office.
Surface retort means the above-ground facility used for the
extraction of kerogen by heating mined shale.
Surface retort operation means the extraction of kerogen by heating
mined shale in an above-ground facility.
Synthetic petroleum means synthetic crude oil manufactured from
shale oil and suitable for use as a refinery feedstock or for
petrochemical production.
Sec. 3900.5 Information collection.
(a) OMB has approved the information collection requirements in
parts 3900 through 3930 of this chapter under 44 U.S.C. 3501 et seq.
The table in paragraph (d) of this section lists the subpart in the
rule requiring the information and its title, provides the OMB control
number, and summarizes the reasons for collecting the information and
how the BLM uses the information.
(b) Respondents are oil shale lessees and operators. The
requirement to respond to the information collections in these parts
are mandated under the Energy Policy Act of 2005 (EP Act) (42 U.S.C.
15927), the Mineral Leasing Act for Acquired Lands of 1947 (30 U.S.C.
351-359), and the Federal Land Policy and Management Act (FLPMA) of
1976 (43 U.S.C. 1701 et seq., including 43 U.S.C. 1732).
(c) The Paperwork Reduction Act of 1995 requires us to inform the
public
[[Page 69471]]
that an agency may not conduct or sponsor, and you are not required to
respond to, a collection of information unless it displays a currently
valid OMB control number.
(d) The BLM is collecting this information for the reasons given in
the following table:
------------------------------------------------------------------------
43 CFR Parts 3900-3930, General (1004- Reasons for collecting
0201) information and how used
------------------------------------------------------------------------
Section 3904.12........................ Prospective lessee or licensee
Section 3904.14(c)(1).................. must furnish a bond before a
lease or exploration license
may be issued or transferred
or a plan of development is
approved. The BLM will review
the bond and, if adequate as
to amount and execution, will
accept it in order to
indemnify the United States
against default on payments
due or other performance
obligations. The BLM may also
adjust the bond amount to
reflect changed conditions.
The BLM will cancel the bond
when all requirements are
satisfied.
Section 3910.31........................ For those lands where no
Section 3910.44........................ exploration data is available,
the lease applicant may apply
for an exploration license to
conduct exploration on
unleased public lands to
determine the extent and
specific characteristics of
the Federal oil shale
resource. The BLM will use the
information in the application
to:
(1) Locate the proposed
exploration site;
(2) Determine if the lands
are subject to entry for
exploration;
(3) Prepare a notice of
invitation to other parties
to participate in the
exploration; and
(4) Ensure the exploration
plan is adequate to
safeguard resource values,
and public and worker
health and safety.
The BLM will use this
information from a licensee to
determine if it will offer the
land area for lease.
Section 3921.30........................ Corporations, associations, and
individuals may submit
expressions of leasing
interest for specific areas to
assist the applicable BLM
State Director in determining
whether or not to lease oil
shale. The information
provided will be used in the
consultation with the governor
of the affected state and in
setting a geographic area for
which a call for applications
will be requested.
Sections 3922.20 and 3922.30........... Entities interested in leasing
the Federal oil shale resource
must file an application in a
geographic area for which the
BLM has issued a ``Call for
Applications.'' The
information provided by the
applicant will be used to
evaluate the impacts of
issuing a proposed lease on
the human environment. Failure
to provide the requested
additional information may
result in suspension or
termination of processing of
the application or in a
decision to deny the
application.
Section 3924.10........................ Prospective lessees will be
required to submit a bid at a
competitive sale in order to
be issued a lease.
Section 3926.10(c)..................... The lessee of an R, D and D
lease may apply for conversion
of the R, D and D lease to a
commercial lease.
Section 3930.11(b)..................... The records, logs, and samples
Section 3930.20(b)..................... provide information necessary
to determine the nature and
extent of oil shale resources
on Federal lands and to
monitor and adjust the extent
of the oil shale reserve.
Section 3931.11........................ The POD must provide for
reasonable protection and
reclamation of the environment
and the protection and
diligent development of the
oil shale resources in the
lease.
Section 3931.30........................ The BLM may, in the interest of
Conservation, order or agree
to a suspension of operations
and production.
Section 3931.41........................ Except for casual use, before
conducting any exploration
operations on federally-leased
or federally-licensed lands,
the lessee must submit an
exploration plan to the BLM
for approval.
Section 3931.50........................ Approved exploration, mining
and in situ development plans
may be modified by the
operator or lessee to adjust
to changed conditions, new
information, improved methods,
and new or improved
technology, or to correct an
oversight.
Section 3931.70........................ Production of all oil shale
products or byproducts must be
reported to the BLM on a
monthly basis.
Section 3931.80........................ Within 30 days after drilling
completion the operator or
lessee must submit to the BLM
a signed copy of records of
all core or test holes made on
the lands covered by the lease
or exploration license.
Sections 3932.10(b) and 3932.30(c)..... A lessee may apply for a
modification of a lease to
include additional Federal
lands adjoining those in the
lease.
Section 3933.31........................ Any lease may be assigned or
subleased, and any exploration
license may be assigned, in
whole or in part, to any
person, association, or
corporation that meets the
qualification requirements at
subpart 3902.
Section 3934.10........................ A lease or exploration license
may be surrendered in whole or
in part.
Section 3935.10........................ Operators or lessees must
maintain production and sale
records which must be
available for the BLM's
examination during regular
business hours.
------------------------------------------------------------------------
Sec. 3900.10 Lands subject to leasing.
The BLM may issue oil shale leases under this part on all Federal
lands except:
(a) Those lands specifically excluded from leasing by the Act;
(b) Lands within the boundaries of any unit of the National Park
System, except as expressly authorized by law (Glen Canyon National
Recreation Area, Lake Mead National Recreation Area, and the
Whiskeytown Unit of the Whiskeytown-Shasta-Trinity National Recreation
Area);
(c) Lands within incorporated cities, towns and villages; and
(d) Any other lands withdrawn from leasing.
Sec. 3900.20 Appealing the BLM's decision.
Any party adversely affected by a BLM decision made under this part
or parts 3910 through 3930 of this chapter may appeal the decision
under part 4 of
[[Page 69472]]
this title. All decisions and orders by the BLM under these parts
remain effective pending appeal unless the BLM decides otherwise. A
petition for the stay of a decision may be filed with the Interior
Board of Land Appeals (IBLA).
Sec. 3900.30 Filing documents.
(a) All necessary documents must be filed in the proper BLM office.
A document is considered filed when the proper BLM office receives it
with any required fee.
(b) All information submitted to the BLM under the regulations in
this part or parts 3910 through 3930 will be available to the public
unless exempt from disclosure under the Freedom of Information Act (5
U.S.C. 552), under part 2 of this title, or unless otherwise provided
for by law.
Sec. 3900.40 Multiple use development of leased or licensed lands.
(a) The granting of an exploration license or lease for the
exploration, development, or production of deposits of oil shale does
not preclude the BLM from issuing other exploration licenses or leases
for the same lands for deposits of other minerals. Each exploration
license or lease reserves the right to allow any other uses or to allow
disposal of the leased lands if it does not unreasonably interfere with
the exploration and mining operations of the lessee. The lessee or the
licensee must make all reasonable efforts to avoid interference with
other such authorized uses.
(b) Subsequent lessee or licensee will be required to conduct
operations in a manner that will not interfere with the established
rights of existing lessees or licensees.
(c) When the BLM issues an oil shale lease, it will cancel all oil
shale exploration licenses for the leased lands.
Sec. 3900.50 Land use plans and environmental considerations.
(a) Any lease or exploration license issued under this part or
parts 3910 through 3930 of this chapter will be issued in conformance
with the decisions, terms, and conditions of a comprehensive land use
plan developed under part 1600 of this chapter.
(b) Before a lease or exploration license is issued, the BLM, or
the appropriate surface management agency, must comply with the
requirements of the National Environmental Policy Act of 1969 (NEPA).
(c) Before the BLM approves a POD, the BLM must comply with NEPA,
in cooperation with the surface management agency when possible, if the
surface is managed by another Federal agency.
Sec. 3900.61 Federal minerals where the surface is owned or
administered by other Federal agencies, by state agencies or charitable
organizations, or by private entities.
(a) Public lands. Unless consent is required by law, the BLM will
issue a lease or exploration license only after the BLM has consulted
with the surface management agency on public lands where the surface is
administered by an agency other than the BLM. The BLM will not issue a
lease or an exploration license on lands to which the surface managing
agency withholds consent required by statute.
(b) Acquired lands. The BLM will issue a lease on acquired lands
only after receiving written consent from an appropriate official of
the surface management agency.
(c) Lands covered by lease or license. If a Federal surface
management agency outside of the Department has required special
stipulations in the lease or license or has refused consent to issue
the lease or license, an applicant may pursue the administrative
remedies to challenge that decision offered by that particular surface
management agency, if any. If the applicant notifies the BLM within 30
calendar days after receiving the BLM's decision that the applicant has
requested the surface management agency to review or reconsider its
decision, the time for filing an appeal to the IBLA under part 4 of
this title is suspended until a decision is reached by such agency.
(d) The BLM will not issue a lease or exploration license on
National Forest System Lands without the consent of the Forest Service.
(e) Ownership of surface overlying Federal minerals by states,
charitable organizations, or private entities. Where the United States
has conveyed title to the surface of lands to any state or political
subdivision, agency, or instrumentality thereof, including a college or
any other educational corporation or association, to a charitable or
religious corporation or association, or to a private entity, the BLM
will send such surface owners written notification by certified mail of
the application for exploration license or lease. In the written
notification, the BLM will give the surface owners a reasonable time,
not to exceed 90 calendar days, within which to suggest any lease
stipulations necessary for the protection of existing surface
improvements or uses and to set forth the facts supporting the
necessity of the stipulations, or to file any objections it may have to
the issuance of the lease or license. The BLM makes the final decision
as to whether to issue the lease or license and on what terms based on
a determination as to whether the interests of the United States would
best be served by issuing the lease or license with the particular
stipulations. This is true even in cases where the party controlling
the surface opposes the issuance of a lease or license or wishes to
place restrictive stipulations on the lease.
Sec. 3900.62 Special requirements to protect the lands and resources.
The BLM will specify stipulations in a lease or exploration license
to protect the lands and their resources. This may include stipulations
required by the surface management agency or recommended by the surface
management agency or non-Federal surface owner and accepted by the BLM.
Subpart 3901--Land Descriptions and Acreage
Sec. 3901.10 Land descriptions.
(a) All lands in an oil shale lease must be described by the legal
subdivisions of the public land survey system or if the lands are
unsurveyed, the legal description by metes and bounds.
(b) Unsurveyed lands will be surveyed, at the cost of the lease
applicant, by a surveyor approved or employed by the BLM.
Sec. 3901.20 Acreage limitations.
No entity may hold more than 50,000 acres of Federal oil shale
leases on public lands and 50,000 acres on acquired lands in any one
state. Oil shale lease acreage does not count toward acreage
limitations associated with leases for other minerals.
Sec. 3901.30 Computing acreage holdings.
In computing the maximum acreage an entity may hold under a Federal
lease, on either public lands or acquired lands, in any one state,
acquired lands and public lands are counted separately. An entity may
hold up to the maximum acreage of each at the same time.
Subpart 3902--Qualification Requirements
Sec. 3902.10 Who may hold leases.
(a) The following entities may hold leases or interests therein:
(1) Citizens of the United States;
(2) Associations (including partnerships and trusts) of such
citizens; and
[[Page 69473]]
(3) Corporations organized under the laws of the United States or
of any state or territory thereof.
(b) Citizens of a foreign country may only hold interest in leases
through stock ownership, stock holding, or stock control in such
domestic corporations. Foreign citizens may hold stock in United States
corporations that hold leases if the Secretary has not determined that
laws, customs, or regulations of their country deny similar privileges
to citizens or corporations of the United States.
(c) A minor may not hold a lease. A legal guardian or trustee of a
minor may hold a lease.
(d) An entity must be in compliance with Section 2(a)(2)(A) of the
Act in order to hold a lease. If the BLM erroneously issues a lease to
an entity that is in violation of Section 2(a)(2)(A) of the Act, the
BLM will void the lease.
Sec. 3902.21 Filing of qualification evidence.
Applicants must file with the BLM a statement and evidence that the
qualification requirements in this subpart are met. These may be filed
separately from the lease application, but must be filed in the same
office as the application. After the BLM accepts the applicant's
qualifications, any additional information may be provided to the same
BLM office by referring to the serial number of the record in which the
evidence is filed. All changes to the qualifications statement must be
in writing. The evidence provided must be current, accurate, and
complete.
Sec. 3902.22 Where to file.
The lease application and qualification evidence must be filed in
the proper BLM office (see subpart 1821 of part 1820 of this chapter).
Sec. 3902.23 Individuals.
Individuals who are applicants must provide to the BLM a signed
statement showing:
(a) U.S. citizenship; and
(b) That acreage holdings do not exceed the limits in Sec. 3901.20
of this chapter. This includes holdings through a corporation,
association, or partnership in which the individual is the beneficial
owner of more than 10 percent of the stock or other instruments of
control.
Sec. 3902.24 Associations, including partnerships.
Associations that are applicants must provide to the BLM:
(a) A signed statement that:
(1) Lists the names, addresses, and citizenship of all members of
the association who own or control 10 percent or more of the
association or partnership, and certifies that the statement is true;
(2) Lists the names of the members authorized to act on behalf of
the association; and
(3) Certifies that the association or partnership's acreage
holdings and those of any member under paragraph (a)(1) of this section
do not exceed the acreage limits in Sec. 3901.20 of this chapter; and
(b) A copy of the articles of association or the partnership
agreement.
Sec. 3902.25 Corporations.
Corporate officers or authorized attorneys-in-fact who represent
applicants must provide to the BLM a signed statement that:
(a) Names the state or territory of incorporation;
(b) Lists the name and citizenship of, and percentage of stock
owned, held, or controlled by, any stockholder owning, holding, or
controlling more than 10 percent of the stock of the corporation, and
certifies that the statement is true;
(c) Lists the names of the officers authorized to act on behalf of
the corporation; and
(d) Certifies that the corporation's acreage holdings, and those of
any stockholder identified under paragraph (b) of this section, do not
exceed the acreage limits in Sec. 3901.20 of this chapter.
Sec. 3902.26 Guardians or trustees.
Guardians or trustees for a trust, holding on behalf of a
beneficiary, who are applicants must provide to the BLM:
(a) A signed statement that:
(1) Provides the beneficiary's citizenship;
(2) Provides the guardian's or trustee's citizenship;
(3) Provides the grantor's citizenship, if the trust is revocable;
and
(4) Certifies the acreage holdings of the beneficiary, the
guardian, trustee, or grantor, if the trust is revocable, do not exceed
the aggregate acreage limitations in Sec. 3901.20 of this chapter; and
(b) A copy of the court order or other document authorizing or
creating the trust or guardianship.
Sec. 3902.27 Heirs and devisees.
If an applicant or successful bidder for a lease dies before the
lease is issued:
(a) The BLM will issue the lease to the heirs or devisees, or their
guardian, if probate of the estate has been completed or is not
required. Before the BLM will recognize the heirs or devisees or their
guardian as the record title holders of the lease, they must provide to
the proper BLM office:
(1) A certified copy of the will or decree of distribution, or if
no will or decree exists, a statement signed by the heirs that they are
the only heirs and citing the provisions of the law of the deceased's
last domicile showing that no probate is required; and
(2) A statement signed by each of the heirs or devisees with
reference to citizenship and holdings as required by Sec. 3902.23 of
this chapter. If the heir or devisee is a minor, the guardian or
trustee must sign the statement; and
(b) The BLM will issue the lease to the executor or administrator
of the estate if probate is required, but is not completed. In this
case, the BLM considers the executor or administrator to be the record
title holder of the lease. Before the BLM will issue the lease to the
executor or administrator, the executor or administrator must provide
to the proper BLM office:
(1) Evidence that the person who, as executor or administrator,
submits lease and bond forms has authority to act in that capacity and
to sign those forms;
(2) A certified list of the heirs or devisees of the deceased; and
(3) A statement signed by each heir or devisee concerning
citizenship and holdings, as required by Sec. 3902.23 of this chapter.
Sec. 3902.28 Attorneys-in-fact.
Attorneys-in-fact must provide to the proper BLM office evidence of
the authority to act on behalf of the applicant and a statement of the
applicant's qualifications and acreage holdings if it is also empowered
to make this statement. Otherwise, the applicant must provide the BLM
this information separately.
Sec. 3902.29 Other parties in interest.
If there is more than one party in interest in an application for a
lease, include with the application the names of all other parties who
hold or will hold any interest in the application or in the lease. All
interested parties who wish to hold an interest in a lease must provide
to the BLM the information required by this subpart to qualify to hold
a lease interest.
Subpart 3903--Fees, Rentals, and Royalties
Sec. 3903.20 Forms of payment.
All payments must be by U.S. postal money order or negotiable
instrument payable in U.S. currency. In the case of payments made to
the MMS, such payments must be made by electronic funds transfer (see
30 CFR part 218 for the MMS's payment procedures).
[[Page 69474]]
Sec. 3903.30 Where to submit payments.
(a) All filing and processing fees, all first-year rentals, and all
bonuses for leases issued under this part or parts 3910 through 3930 of
this chapter must be paid to the BLM state office that manages the
lands covered by the application, lease, or exploration license, unless
the BLM designates a different state office. The first one-fifth bonus
installment is paid to the appropriate BLM state office. All remaining
bonus installment payments are paid to the MMS.
(b) All second-year and subsequent rentals and all other payments
for leases are paid to the MMS.
(c) All royalties on producing leases and all payments under leases
in their minimum production period are paid to the MMS.
Sec. 3903.40 Rentals.
(a) The rental rate for oil shale leases is $2.00 per acre, or
fraction thereof, payable annually on or before the anniversary date of
the lease. Rentals paid for any 1 year are credited against any
production royalties accruing for that year.
(b) The BLM will send a notice demanding payment of late rentals.
Failure to provide payment within 30 calendar days after notification
will result in the BLM taking action to cancel the lease (see Sec.
3934.30 of this chapter).
Sec. 3903.51 Minimum production and payments in lieu of production.
(a) Each lease must meet its minimum annual production amount of
shale oil or make a payment in lieu of production for any particular
lease year, beginning with the 10th lease year.
(b) The minimum payment in lieu of annual production is established
in the lease and will not be less than $4 per acre or fraction thereof
per year, payable in advance. Production royalty payments will be
credited to payments in lieu of annual production for that year only.
Sec. 3903.52 Production royalties.
(a) The lessee must pay royalties on all products of oil shale that
are sold from or transported off of the lease.
(b) The royalty rate for the products of oil shale is 5 percent of
the amount or value of production for the first 5 years of commercial
production. The royalty rate will increase by 1% each year starting the
sixth year of commercial production to a maximum royalty rate of 12\1/
2\% in the thirteenth year of commercial production.
Sec. 3903.53 Overriding royalties.
The lessee must file documentation of all overriding royalties
(payments out of production to an entity other than the United States)
associated with the lease in the proper BLM office within 90 calendar
days after execution of the assignment of the overriding royalties.
Sec. 3903.54 Waiver, suspension, or reduction of rental or payments
in lieu of production, or reduction of royalty, or waiver of royalty in
the first 5 years of the lease.
(a) In order to encourage the maximum economic recovery (MER) of
the leased mineral(s), and in the interest of conservation, whenever
the BLM determines it is necessary to promote development or finds that
leases cannot be successfully operated under the lease terms, the BLM
may waive, suspend, or reduce the rental or payment in lieu of
production, reduce the rate of royalty, or in the first 5 years of the
lease, waive the royalty.
(b) Applications for waivers, suspension or reduction of rentals or
payment in lieu of production, reduction in royalty, or waiver of
royalty for the first 5 years of the lease must contain the serial
number of the lease, the name of the record title holder, the operator
or sub-lessee, a description of the lands by legal subdivision, and the
following information:
(1) The location of each oil shale mine or operation, and include:
(i) A map showing the extent of the mining or development
operations;
(ii) A tabulated statement of the minerals mined and subject to
royalty for each month covering a period of not less than 12 months
immediately preceding the date of filing of the application; and
(iii) The average production per day mined for each month, and
complete information as to why the minimum production was not attained;
(2) Each application must contain:
(i) A detailed statement of expenses and costs of operating the
entire lease;
(ii) The income from the sale of any leased products;
(iii) All facts showing whether the mines can be successfully
operated under the royalty or rental fixed in the lease; and
(iv) Where the application is for a reduction in royalty,
information as to whether royalties or payments out of production are
paid to anyone other than the United States, the amounts so paid, and
efforts made to reduce those payments;
(3) Any overriding royalties cannot be greater in aggregate than
one-half the royalties paid to the United States.
(c) Contact the proper BLM office for detailed information on
submitting copies of these applications electronically.
Sec. 3903.60 Late payment or underpayment charges.
Late payment or underpayment charges will be assessed under MMS
regulations at 30 CFR 218.202.
Subpart 3904--Bonds and Trust Funds
Sec. 3904.10 Bonding requirements.
(a) Prior to issuing a lease or exploration license, the BLM
requires exploration license or lease bonds for each lease or
exploration license that covers all liabilities, other than
reclamation, that may arise under the lease or license. The bond must
be executed by the lessee and cover all record title owners, operating
rights owners, operators, and any person who conducts operations or is
responsible for payments under a lease or license.
(b) Before the BLM will approve a POD, the lessee must provide to
the proper BLM office a reclamation bond to cover all costs the BLM
estimates will be necessary to cover reclamation.
Sec. 3904.11 When to file bonds.
File the lease bond before the BLM will issue the lease, file the
reclamation bond before the BLM will approve the POD, and file the
exploration bond before the BLM will issue the exploration license.
Sec. 3904.12 Where to file bonds.
File one copy of the bond form with original signatures in the
proper BLM state office. Bonds must be filed on an approved BLM form.
The obligor of a personal bond must sign the form. Surety bonds must
have the lessee's and the acceptable surety's signatures.
Sec. 3904.13 Acceptable forms of bonds.
(a) The BLM will accept either a personal bond or a surety bond.
Personal bonds are pledges of any of the following:
(1) Cash;
(2) Cashier's check;
(3) Certified check; or
(4) Negotiable U.S. Treasury bonds equal in value to the bond
amount. Treasury bonds must give the Secretary authority to sell the
securities in the case of failure to comply with the conditions and
obligations of the exploration license or lease.
(b) Surety bonds must be issued by qualified surety companies
approved by the Department of the Treasury. A list of qualified
sureties is available at any BLM state office.
[[Page 69475]]
Sec. 3904.14 Individual lease, exploration license, and reclamation
bonds.
(a) The BLM will determine individual lease bond amounts on a case-
by-case basis. The minimum lease bond amount is $25,000.
(b) The BLM will determine reclamation bond and exploration license
bond amounts on a case-by-case basis when it approves a POD or
exploration plan. The reclamation or exploration license bond must be
sufficient to cover the estimated cost of site reclamation.
(c) The BLM may enter into agreements with states to accept a state
reclamation bond to cover the BLM's reclamation bonding requirements if
it is adequate to cover both the Federal liabilities and all others for
which it stands as security. The BLM may request additional information
from the lessee or operator to determine whether the state bond will
cover all of the BLM's reclamation requirements.
(1) If a state bond is to be used to satisfy the BLM bonding
requirements, evidence verifying that the existing state bond will
satisfy all the BLM reclamation bonding requirements must be filed in
the proper BLM office.
(2) The BLM will require an additional bond if the BLM determines
that the state bond is inadequate to cover all of the potential
liabilities for your BLM leases.
Sec. 3904.15 Amount of bond.
(a) The BLM may increase or decrease the required bond amount if it
determines that a change in amount is appropriate to cover the costs
and obligations of complying with the requirements of the lease or
license and these regulations. The BLM will not decrease the bond
amount below the minimum (see Sec. 3904.14(a)).
(b) The lessee or operator must submit to the BLM every three years
after reclamation bond approval a revised estimate of the reclamation
costs. The BLM will verify the revised estimate of the reclamation
costs submitted by the lessee or operator. If the current bond does not
cover the revised estimate of reclamation costs, the lessee or operator
must increase the reclamation bond amount to meet or exceed the revised
cost estimate.
Sec. 3904.20 Default.
(a) The BLM will demand payment from the lease bond to cover
nonpayment of any rental or royalty owed or the reclamation or
exploration license bond for any reclamation obligations that are not
met. The BLM will reduce the bond amount by the amount of the payment
made to cover the default.
(b) After any default, the BLM will provide notification of the
amount required to restore the bond to the required level. A new bond
or an increase in the existing bond to its pre-default level must be
provided to the proper BLM office within 6 months of the BLM's written
notification that the bond is below its required level. The BLM may
accept separate or substitute bonds for each exploration license or
lease. The BLM may take action to cancel the lease or exploration
license covered by the bond if sufficient additional bond is not
provided within the six month time period.
Sec. 3904.21 Termination of the period of liability and release of
bonds.
(a) The BLM will not consent to termination of the period of
liability under a bond unless an acceptable replacement bond has been
filed.
(b) Terminating the period of liability of a bond ends the period
during which obligations continue to accrue, but does not relieve the
surety of the responsibility for obligations that accrued during the
period of liability.
(c) A lease bond will be released when BLM determines that all
lease obligations accruing during the period of liability have been
fulfilled.
(d) A reclamation bond or license bond will be released when the
BLM determines that the reclamation obligations arising within the
period of liability have been met and that the reclamation has
succeeded to the BLM's satisfaction.
(e) The BLM will release a bond when it accepts a replacement bond
in which the surety expressly assumes liability for all obligations
that accrued within the period of liability of the original bond.
Sec. 3904.40 Long-term water treatment trust funds.
(a) The BLM may require the operator or lessee to establish a trust
fund or other funding mechanism to ensure the continuation of long-term
treatment to achieve water quality standards and for other long-term,
post-mining maintenance requirements. The funding must be adequate to
provide for the construction, long-term operation, maintenance, or
replacement of any treatment facilities and infrastructure, for as long
as the treatment and facilities are needed after mine closure. The BLM
may identify the need for a trust fund or other funding mechanism
during plan review or later.
(b) In determining whether a trust fund will be required, the BLM
will consider the following factors:
(1) The anticipated post-mining obligations (PMO) that are
identified in the environmental document or approved POD;
(2) Whether there is a reasonable degree of certainty that the
treatment will be required based on accepted scientific evidence or
models;
(3) The determination that the financial responsibility for those
obligations rests with the operator; and
(4) Whether it is feasible, practical, or desirable to require
separate or expanded reclamation bonds for those anticipated long-term
PMOs.
Subpart 3905--Lease Exchanges
Sec. 3905.10 Oil shale lease exchanges.
To facilitate the recovery of oil shale, the BLM may consider land
exchanges where appropriate and feasible to consolidate land ownership
and mineral interest into manageable areas. Exchanges are covered under
part 2200 of this chapter.
0
2. Add part 3910 to subchapter C to read as follows:
PART 3910--OIL SHALE EXPLORATION LICENSES
Subpart 3910--Exploration Licenses
Sec.
3910.21 Lands subject to exploration.
3910.22 Lands managed by agencies other than the BLM.
3910.23 Requirements for conducting exploration activities.
3910.31 Filing of an application for an exploration license.
3910.32 Environmental analysis.
3910.40 Exploration license requirements.
3910.41 Issuance, modification, relinquishment, and cancellation.
3910.42 Limitations on exploration licenses.
3910.44 Collection and submission of data.
3910.50 Surface use.
Authority: 25 U.S.C. 396(d) and 2107, 30 U.S.C. 241(a), 42
U.S.C. 15927, 43 U.S.C. 1732(b) and 1740.
Subpart 3910--Exploration Licenses
Sec. 3910.21 Lands subject to exploration.
The BLM may issue oil shale exploration licenses for all Federal
lands subject to leasing under Sec. 3900.10 of this chapter, except
lands that are in an existing oil shale lease or in preference right
leasing areas under the R, D and D program. The BLM may issue
exploration licenses for lands in preference right lease areas only to
the R, D and D lessee.
Sec. 3910.22 Lands managed by agencies other than the BLM.
(a) The consent and consultation procedures required by Sec.
3900.61 of this
[[Page 69476]]
chapter also apply to exploration license applications.
(b) If exploration activities could affect the adjacent lands under
the surface management of a Federal agency other than the BLM, the BLM
will consult with that agency before issuing an exploration license.
Sec. 3910.23 Requirements for conducting exploration activities.
Exploration activities on Federal lands require an exploration
license or oil shale lease. Activities on a license or lease without an
approved plan of operation must be conducted pursuant to an approved
exploration plan under Sec. 3931.40 of this chapter. The licensee may
not remove any oil shale for sale, but may remove a reasonable amount
of oil shale for analysis and study.
Sec. 3910.31 Filing of an application for an exploration license.
(a) Applications for exploration licenses must be submitted to the
proper BLM office.
(b) No specific form is required. Applications must include:
(1) The name and address of the applicant(s);
(2) A nonrefundable filing fee of $295;
(3) A description of the lands covered by the application according
to section, township and range in accordance with the public lands
survey system or, if the lands are unsurveyed lands, the legal
description by metes and bounds; and
(4) An acceptable electronic format or 3 paper copies of an
exploration plan that complies with the requirements of Sec. 3931.41
of this chapter. Contact the proper BLM office for detailed information
on submitting copies electronically.
(c) An exploration license application may cover no more than
25,000 acres in a reasonably compact area and entirely within one
state. An application for an exploration license covering more than
25,000 acres must include justification for an exception to the normal
acreage limitation.
(d) Applicants for exploration licenses are required to invite
other parties to participate in exploration under the license on a pro
rata cost share basis.
(e) Using information supplied by the applicant, the BLM will
prepare a notice of invitation and post the notice in the proper BLM
office for 30 calendar days. The applicant will publish the BLM-
approved notice once a week for 2 consecutive weeks in at least 1
newspaper of general circulation in the area where the lands covered by
the exploration license application are situated. The notification must
invite the public to participate in the exploration under the license
and contain the name and location of the BLM office in which the
application is available for inspection.
(f) If any person wants to participate in the exploration program,
the applicant and the BLM must receive written notice from that person
within 30 calendar days after the end of the 30-day posting period. A
person who wants to participate in the exploration program must:
(1) State in their notification that they are willing to share in
the cost of the exploration on a pro-rata share basis; and
(2) Describe any modifications to the exploration program that the
BLM should consider.
(g) To avoid duplication of exploration activities in an area, the
BLM may:
(1) Require modification of the original exploration plan to
accommodate the exploration needs of those seeking to participate; or
(2) Notify those seeking to participate that they should file a
separate application for an exploration license.
Sec. 3910.32 Environmental analysis.
(a) Before the BLM will issue an exploration license, the BLM, in
consultation with any affected surface management agency, will perform
the appropriate NEPA analysis of the actions contemplated in the
application.
(b) For each exploration license, the BLM will include terms and
conditions needed to protect the environment and resource values of the
area and to ensure reclamation of the lands disturbed by the
exploration activities.
Sec. 3910.40 Exploration license requirements.
The licensee must comply with all applicable Federal, state, and
local laws and regulations, the terms and conditions of the license,
and the approved exploration plan. The operator or licensee must notify
the BLM of any change of address or operator or licensee name.
Sec. 3910.41 Issuance, modification, relinquishment, and
cancellation.
(a) The BLM may:
(1) Issue an exploration license; or
(2) Reject an application for an exploration license based on, but
not limited to:
(i) The need for resource information;
(ii) The environmental analysis;
(iii) The completeness of the application; or
(iv) Any combination of these factors.
(b) An exploration license is effective on the date the BLM
specifies, which is also the date when exploration activities may
begin. An exploration license is valid for a period of up to 2 years
after the effective date of the license or as specified in the license.
(c) The BLM-approved exploration plan will be attached and made a
part of each exploration license (see subpart 3931 of part 3930 of this
chapter).
(d) After consultation with the surface management agency, the BLM
may approve modification of the exploration license proposed by the
licensee in writing if geologic or other conditions warrant. The BLM
will not add lands to the license once it has been issued.
(e) Subject to the continued obligation of the licensee and the
surety to comply with the terms and conditions of the exploration
license, the exploration plan, and these regulations, a licensee may
relinquish an exploration license for any or all of the lands covered
by it. A relinquishment must be filed in the BLM state office in which
the original application was filed.
(f) The BLM may terminate an exploration license for noncompliance
with its terms and conditions and part 3900, this part, and parts 3920
and 3930 of this chapter.
Sec. 3910.42 Limitations on exploration licenses.
(a) The issuance of an exploration license for an area will not
preclude the BLM's approval of an exploration license or issuance of a
Federal oil shale lease for the same lands.
(b) If an oil shale lease is issued for an area covered by an
exploration license, the BLM will terminate the exploration license on
the effective date of the lease for those lands that are common to
both.
Sec. 3910.44 Collection and submission of data.
Upon the BLM's request, the licensee must provide copies of all
data obtained under the exploration license in the format requested by
the BLM. To the extent authorized by the Freedom of Information Act,
the BLM will consider the data confidential and proprietary until the
BLM determines that public access to the data will not damage the
competitive position of the licensee or the lands involved have been
leased, whichever comes first. The licensee must submit to the proper
BLM office all data obtained under the exploration license.
Sec. 3910.50 Surface use.
Operations conducted under an exploration license must:
(a) Not unreasonably interfere with or endanger any other lawful
activity on the same lands;
[[Page 69477]]
(b) Not damage any improvements on the lands; and
(c) Comply with all applicable Federal, state, and local laws and
regulations.
0
3. Add part 3920 to subchapter C to read as follows:
PART 3920--OIL SHALE LEASING
Subpart 3921--Pre-Sale Activities
Sec.
3921.10 Special requirements related to land use planning.
3921.20 Compliance with the National Environmental Policy Act.
3921.30 Call for expression of leasing interest.
3921.40 Comments from governors, local governments, and interested
Indian tribes.
3921.50 Determining the geographic area for receiving applications
to lease.
3921.60 Call for applications.
Subpart 3922--Application Processing
3922.10 Application processing fee.
3922.20 Application contents.
3922.30 Application--Additional information.
3922.40 Tract delineation.
Subpart 3923--Minimum Bid
3923.10 Minimum bid.
Subpart 3924--Lease Sale Procedures
3924.5 Notice of sale.
3924.10 Lease sale procedures and receipt of bids.
Subpart 3925--Award of Lease
3925.10 Award of lease.
Subpart 3926--Conversion of Preference Right for Research, Development,
and Demonstration (R, D and D) Leases
3926.10 Conversion of an R, D and D lease to a commercial lease.
Subpart 3927--Lease Terms
3927.10 Lease form.
3927.20 Lease size.
3927.30 Lease duration and notification requirement.
3927.40 Effective date of leases.
3927.50 Diligent development.
Authority: 30 U.S.C. 241(a), 42 U.S.C. 15927, 43 U.S.C. 1732(b)
and 1740.
Subpart 3921--Pre-Sale Activities
Sec. 3921.10 Special requirements related to land use planning.
The State Director may call for expressions of leasing interest as
described in Sec. 3921.30 after areas available for leasing have been
identified in a land use plan completed under part 1600 of this
chapter.
Sec. 3921.20 Compliance with the National Environmental Policy Act.
Before the BLM will offer a tract for competitive lease sale under
subpart 3924, the BLM must prepare a NEPA analysis of the proposed
lease area under 40 CFR parts 1500 through 1508 either separately or in
conjunction with a land use planning action.
Sec. 3921.30 Call for expression of leasing interest.
The State Director may implement the provisions of Sec. Sec.
3921.40 through 3921.60 after review of any responses received as a
result of a call for expression of leasing interest. The BLM notice
calling for expressions of leasing interest will:
(a) Be published in the Federal Register and in at least 1
newspaper of general circulation in each affected state for 2
consecutive weeks;
(b) Allow no less than 30 calendar days to submit expressions of
interest;
(c) Request specific information including the name and address of
the respondent and the legal land description of the area of interest;
(d) State that all information submitted under this subpart must be
available for public inspection; and
(e) Include a statement indicating that data which is considered
proprietary must not be submitted as part of an expression of leasing
interest.
Sec. 3921.40 Comments from governors, local governments, and
interested Indian tribes.
After the BLM receives responses to the call for expression of
leasing interest, the BLM will notify the appropriate state governor's
office, local governments, and interested Indian tribes and allow them
an opportunity to provide comments regarding the responses and other
issues related to oil shale leasing. The BLM will only consider those
comments it receives within 60 calendar days after the notification
requesting comments.
Sec. 3921.50 Determining the geographic area for receiving
applications to lease.
After analyzing expressions of leasing interest received under
Sec. 3921.30 and complying with the procedures at Sec. 3921.40 of
this chapter, the State Director may determine a geographic area for
receiving applications to lease. The BLM may also include additional
geographic areas available for lease in addition to lands identified in
expressions of interest to lease.
Sec. 3921.60 Call for applications.
If, as a result of the analysis of the expression of leasing
interest, the State Director determines that there is interest in
having a competitive sale, the State Director may publish a notice in
the Federal Register requesting applications to lease. The notice will:
(a) Describe the geographic area the BLM determined is available
for application under Sec. 3921.50;
(b) Allow no less than 90 calendar days for interested parties to
submit applications to the proper BLM office; and
(c) Provide that applications submitted to the BLM must meet the
requirements at subpart 3922.
Subpart 3922--Application Processing
Sec. 3922.10 Application processing fee.
(a) An applicant nominating or applying for a tract for competitive
leasing must pay a cost recovery or processing fee that the BLM will
determine on a case-by-case basis as described in Sec. 3000.11 of this
chapter and as modified by the following provisions.
(b) The cost recovery process for a competitive oil shale lease is
as follows:
(1) The applicant nominating the tract for competitive leasing must
pay the fee before the BLM will process the application and publish a
notice of competitive lease sale;
(2) The BLM will publish a sale notice no later than 30 days before
the proposed sale. The BLM will include in the sale notice a statement
of the total cost recovery fee paid to the BLM by the applicant, up to
30 calendar days before the sale;
(3) Before the lease is issued:
(i) The successful bidder, if someone other than the applicant,
must pay to the BLM the cost recovery amount specified in the sale
notice, including the cost of the NEPA analysis; and
(ii) The successful bidder must pay all processing costs the BLM
incurs after the date of the sale notice;
(4) If the successful bidder is someone other than the applicant,
the BLM will refund to the applicant the amount paid under paragraph
(b)(1) of this section;
(5) If there is no successful bidder, the applicant is responsible
for all processing fees; and
(6) If the successful bidder is someone other than the applicant,
within 30 calendar days after the lease sale, the successful bidder
must file an application in accordance with Sec. 3922.20.
Sec. 3922.20 Application contents.
A lease application must be filed by any party seeking to obtain a
lease. Lease applications must be filed in the proper BLM State Office.
No specific form of application is required, but the application must
include information necessary to evaluate the impacts on the human
environment of issuing the proposed lease or leases. Except as
[[Page 69478]]
otherwise requested by the BLM, the application must include, but not
be limited to, the following:
(a) Name, address, and telephone number of applicant, and a
qualification statement, as required by subpart 3902 of this chapter;
(b) A delineation of the proposed lease area or areas, the surface
ownership (if other than the United States) of those areas, a
description of the quality, thickness, and depth of the oil shale and
of any other resources the applicant proposes to extract, and
environmental data necessary to assess impacts from the proposed
development; and
(c) A description of the proposed extraction method, including
personnel requirements, production levels, and transportation methods,
including:
(1) A description of the mining, retorting, or in situ mining or
processing technology that the operator would use and whether the
proposed development technology is substantially identical to a
technology or method currently in use to produce marketable commodities
from oil shale deposits;
(2) An estimate of the maximum surface area of the lease area that
will be disturbed or be undergoing reclamation at any one time;
(3) A description of the source and quantities of water to be used
and of the water treatment and disposal methods necessary to meet
applicable water quality standards;
(4) A description of the regulated air emissions;
(5) A description of the anticipated noise levels from the proposed
development;
(6) A description of how the proposed lease development would
comply with all applicable statutes and regulations governing
management of chemicals and disposal of solid waste. If the proposed
lease development would include disposal of wastes on the lease site,
include a description of measures to be used to prevent the
contamination of soil and of surface and ground water;
(7) A description of how the proposed lease development would
avoid, or, to the extent practicable, mitigate impacts on species or
habitats protected by applicable state or Federal law or regulations,
and impacts on wildlife habitat management;
(8) A description of reasonably foreseeable social, economic, and
infrastructure impacts on the surrounding communities, and on state and
local governments from the proposed development;
(9) A description of the known historical, cultural, or
archaeological resources within the lease area;
(10) A description of infrastructure that would likely be required
for the proposed development and alternative locations of those
facilities, if applicable;
(11) A discussion of proposed measures or plans to mitigate any
adverse socioeconomic or environmental impacts to local communities,
services and infrastructure;
(12) A brief description of the reclamation methods that will be
used;
(13) Any other information that shows that the application meets
the requirements of this subpart or that the applicant believes would
assist the BLM in analyzing the impacts of the proposed development;
and
(14) A map, or maps, showing:
(i) The topography, physical features, and natural drainage
patterns;
(ii) Existing roads, vehicular trails, and utility systems;
(iii) The location of any proposed exploration operations,
including seismic lines and drill holes;
(iv) To the extent known, the location of any proposed mining
operations and facilities, trenches, access roads, or trails, and
supporting facilities including the approximate location and extent of
the areas to be used for pits, overburden, and tailings; and
(v) The location of water sources or other resources that may be
used in the proposed operations and facilities.
Sec. 3922.30 Application--Additional information.
At any time during processing of the application, or the
environmental or similar assessments of the application, the BLM may
request additional information from the applicant. Failure to provide
the best available and most accurate information may result in
suspension or termination of processing of the application, or in a
decision to deny the application.
Sec. 3922.40 Tract delineation.
(a) The BLM will delineate tracts for competitive sale to provide
for the orderly development of the oil shale resource.
(b) The BLM may delineate more or less lands than were covered by
an application for any reason the BLM determines to be in the public
interest.
(c) The BLM may delineate tracts in any area acceptable for further
consideration for leasing, whether or not expressions of leasing
interest or applications have been received for those areas.
(d) Where the BLM receives more than 1 application covering the
same lands, the BLM may delineate the lands that overlap as a separate
tract.
Subpart 3923--Minimum Bid
Sec. 3923.10 Minimum bid.
The BLM will not accept any bid that is less than the FMV as
determined under Sec. 3924.10(d). In no case may the minimum bid be
less than $1,000 per acre.
Subpart 3924--Lease Sale Procedures
Sec. 3924.5 Notice of sale.
(a) After the BLM complies with subparts 3921and 3922, the BLM may
publish a notice of the lease sale in the Federal Register containing
all information required by paragraph (b) of this section. The BLM will
also publish a similar notice of lease sale that complies with this
section once a week for 3 consecutive weeks, or such other time deemed
appropriate by the BLM, in 1 or more newspapers of general circulation
in the county or counties in which the oil shale lands are situated.
The notice of the sale will be posted in the appropriate State Office
at least 30 days prior to the lease sale.
(b) The notice of sale will:
(1) List the time and place of sale, the bidding method, and the
legal land descriptions of the tracts being offered;
(2) Specify where a detailed statement of lease terms, conditions,
and stipulations may be obtained;
(3) Specify the royalty rate and the amount of the annual rental;
(4) Specify that, prior to lease issuance, the successful bidder
for a particular lease must pay the identified cost recovery amount,
including the bidder's proportionate share of the total cost of the
NEPA analysis and of publication of the notice; and
(5) Contain such other information as the BLM deems appropriate.
(c) The detailed statement of lease terms, conditions, and
stipulations will, at a minimum, contain:
(1) A complete copy of each lease and all lease stipulations to the
lease; and
(2) Resource information relevant to the tracts being offered for
lease and the minimum production requirement.
Sec. 3924.10 Lease sale procedures and receipt of bids.
(a) The BLM will accept sealed bids only as specified in the notice
of sale and will return to the bidder any sealed bid submitted after
the time and date specified in the sale notice. Each sealed bid must
include:
(1) A certified check, cashier's check, bank draft, money order,
personal check, or cash for one-fifth of the amount of the bonus; and
(2) A qualifications statement signed by the bidder as described in
subpart 3902 of this chapter.
[[Page 69479]]
(b) At the time specified in the sale notice, the BLM will open and
read all bids and announce the highest bid. The BLM will make a record
of all bids.
(c) No decision to accept or reject the high bid will be made at
the time of sale.
(d) After the sale, the BLM will convene a sales panel to
determine:
(1) If the high bid was submitted in compliance with the terms of
the notice of sale and these regulations;
(2) If the high bid reflects the FMV of the tract; and
(3) Whether the high bidder is qualified to hold the lease.
(e) The BLM may reject any or all bids regardless of the amount
offered, and will not accept any bid that is less than the FMV. The BLM
will notify the high bidder whose bid has been rejected in writing and
include a statement of reasons for the rejection.
(f) The BLM may offer the lease to the next highest qualified
bidder if the successful bidder fails to execute the lease or for any
reason is disqualified from receiving the lease.
(g) The balance of the bonus bid is due and payable to the MMS in 4
equal annual installments on each of the first 4 anniversary dates of
the lease, unless otherwise specified in the lease.
Subpart 3925--Award of Lease
Sec. 3925.10 Award of lease.
(a) The lease will be awarded to the highest qualified bidder whose
bid meets or exceeds the BLM's estimate of FMV, except as provided in
Sec. 3924.10. The BLM will provide the successful bidder 3 copies of
the oil shale lease form for execution.
(b) Within 60 calendar days after receipt of the lease forms, the
successful bidder must sign all copies and return them to the proper
BLM office. The successful bidder must also submit the necessary lease
bond (see subpart 3904 of this chapter), the first year's rental, any
unpaid cost recovery fees, including costs associated with the NEPA
analysis, and the bidder's proportionate share of the cost of
publication of the sale notice. The BLM may, upon written request,
grant an extension of time to submit the items under this paragraph.
(c) If the successful bidder does not comply with this section, the
BLM will not issue the lease and the bidder forfeits the one-fifth
bonus payment submitted with the bid.
(d) If the lease cannot be awarded for reasons determined by the
BLM to be beyond the control of the successful bidder, the BLM will
refund the deposit submitted with the bid.
(e) If the successful bidder was not an applicant under Sec.
3922.20, the successful bidder must submit an application and the BLM
may require additional NEPA analysis of the successful bidder's
proposed operations.
Subpart 3926--Conversion of Preference Right for Research,
Development, and Demonstration (R, D and D) Leases
Sec. 3926.10 Conversion of an R, D and D lease to a commercial lease.
(a) Applications to convert R, D and D leases, including preference
right areas, into commercial leases, are subject to the regulations at
parts 3900 and 3910, this part, and part 3930, except for lease sale
procedures at subparts 3921 and 3924 and Sec. 3922.40.
(b) A lessee of an R, D and D lease must apply for the conversion
of the R, D and D lease to a commercial lease no later than 90 calendar
days after the commencement of production in commercial quantities. No
specific form of application is required. The application for
conversion must be filed in the BLM state office that issued the R, D
and D lease. The conversion application must include:
(1) Documentation that there have been commercial quantities of oil
shale produced from the lease, including the narrative required by the
R, D and D leases;
(2) Documentation that the lessee consulted with state and local
officials to develop a plan for mitigating the socioeconomic impacts of
commercial development on communities and infrastructure;
(3) A bid payment no less than specified in Sec. 3923.10 and equal
to the FMV of the lease; and
(4) Bonding as required by Sec. 3904.14 of this chapter.
(c) The lessee of an R, D and D lease has the exclusive right to
acquire any and all portions of the preference right area designated in
the R, D and D lease up to a total of 5,120 acres in the lease. The BLM
will approve the conversion application, in whole or in part, if it
determines that:
(1) There have been commercial quantities of shale oil produced
from the lease;
(2) The bid payment for the lease met FMV;
(3) The lessee consulted with state and local officials to develop
a plan for mitigating the socioeconomic impacts of commercial
development on communities and infrastructure;
(4) The bond is consistent with Sec. 3904.14 of this chapter; and
(5) Commercial scale operations can be conducted, subject to
mitigation measures to be specified in stipulations or regulations, in
a manner that complies with applicable law and regulation.
(d) The commercial lease must contain terms consistent with the
regulations in parts 3900 and 3910 of this chapter, this part, and part
3930 of this chapter, and stipulations developed through appropriate
NEPA analysis.
Subpart 3927--Lease Terms
Sec. 3927.10 Lease form.
Leases are issued on a BLM approved standard form. The BLM may
modify those provisions of the standard form that are not required by
statute or regulations and may add such additional stipulations and
conditions, as appropriate, with notice to bidders in the notice of
sale.
Sec. 3927.20 Lease size.
The maximum size of an oil shale lease is 5,760 acres.
Sec. 3927.30 Lease duration and notification requirement.
Leases issue for a period of 20 years and continue as long as there
is annual minimum production or as long as there are payments in lieu
of production (see Sec. 3903.51 of this chapter). The BLM may initiate
procedures to cancel a lease under subpart 3934 of this chapter for not
maintaining annual minimum production, for not making the payment in
lieu of production, or for not complying with the lease terms,
including the diligent development milestones (see Sec. 3930.30 of
this chapter). The operator or lessee must notify the BLM of any change
of address or operator or lessee name.
Sec. 3927.40 Effective date of leases.
Leases are dated and effective the first day of the month following
the date the BLM signs it. However, upon receiving a prior written
request, the BLM may make the effective date of the lease the first day
of the month in which the BLM signs it.
Sec. 3927.50 Diligent development.
Oil shale lessees must meet:
(a) Diligent development milestones;
(b) Annual minimum production requirements or payments in lieu of
production starting the 10th lease year, except when the BLM determines
that operations under the lease are interrupted by strikes, the
elements, or causes not attributable to the lessee. Market conditions
are not considered a valid reason to waive or suspend the requirements
for annual minimum production. The BLM will determine the annual
production requirements based on the extraction technology to be
[[Page 69480]]
used and on the BLM's estimate of the recoverable resources on the
lease, expected life of the operation, and other factors.
0
4. Add part 3930 to subchapter C to read as follows:
PART 3930--MANAGEMENT OF OIL SHALE EXPLORATION AND LEASES
Subpart 3930--Management of Oil Shale Exploration Licenses and Leases
Sec.
3930.10 General performance standards.
3930.11 Performance standards for exploration and in situ
operations.
3930.12 Performance standards for underground mining.
3930.13 Performance standards for surface mines.
3930.20 Operations.
3930.30 Diligent development milestones.
3930.40 Assessments for missing diligence milestones.
Subpart 3931--Plans of Development and Exploration Plans
3931.10 Exploration plans and plans of development for mining and in
situ operations.
3931.11 Content of plan of development.
3931.20 Reclamation.
3931.30 Suspension of operations and production.
3931.40 Exploration.
3931.41 Content of exploration plan.
3931.50 Exploration plan and plan of development modifications.
3931.60 Maps of underground and surface mine workings and in situ
surface operations.
3931.70 Production maps and production reports.
3931.80 Core or test hole samples and cuttings.
3931.100 Boundary pillars and buffer zones.
Subpart 3932--Lease Modifications and Readjustments
3932.10 Lease size modification.
3932.20 Lease modification land availability criteria.
3932.30 Terms and conditions of a modified lease.
3932.40 Readjustment of lease terms.
Subpart 3933--Assignments and Subleases
3933.10 Leases or licenses subject to assignment or sublease.
3933.20 Filing fees.
3933.31 Record title assignments.
3933.32 Overriding royalty interests.
3933.40 Account status.
3933.51 Bond coverage.
3933.52 Continuing responsibility under assignment and sublease.
3933.60 Effective date.
3933.70 Extensions.
Subpart 3934--Relinquishment, Cancellations, and Terminations
3934.10 Relinquishments.
3934.21 Written notice of default.
3934.22 Causes and procedures for lease cancellation.
3934.30 License terminations.
3934.40 Payments due.
3934.50 Bona fide purchasers.
Subpart 3935--Production and Sale Records
3935.10 Accounting records.
Subpart 3936--Inspection and Enforcement
3936.10 Inspection of underground and surface operations and
facilities.
3936.20 Issuance of notices of noncompliance and orders.
3936.30 Enforcement of notices of noncompliance and orders.
3936.40 Appeals.
Authority: 25 U.S.C. 396d and 2107, 30 U.S.C. 241(a), 42 U.S.C.
15927, 43 U.S.C. 1732(b), 1733, and 1740.
Subpart 3930--Management of Oil Shale Exploration Licenses and
Leases
Sec. 3930.10 General performance standards.
The operator/lessee must comply with the following performance
standards concerning exploration, development, and production:
(a) All operations must be conducted to achieve MER;
(b) Operations must be conducted under an approved POD or
exploration plan;
(c) The operator/lessee must diligently develop the lease and must
comply with the diligent development milestones and production
requirements at Sec. 3930.30;
(d) The operator/lessee must notify the BLM promptly if operations
encounter unexpected wells or drill holes that could adversely affect
the recovery of shale oil or other minerals producible under an oil
shale lease during mining operations, and must not take any action that
would disturb such wells or drill holes without the BLM's prior
approval;
(e) The operator/lessee must conduct operations to:
(1) Prevent waste and conserve the recoverable oil shale reserves
and other resources;
(2) Prevent damage to or degradation of oil shale formations;
(3) Ensure that other resources are protected upon abandonment of
operations; and
(f) The operator must save topsoil for use in final reclamation
after the reshaping of disturbed areas has been completed.
Sec. 3930.11 Performance standards for exploration and in situ
operations.
The operator/lessee must adhere to the following standards for all
exploration and in situ drilling operations:
(a) At the end of exploration operations, all drill holes must be
capped with at least 5 feet of cement and plugged with a permanent
plugging material that is unaffected by water and hydrocarbon gases and
will prevent the migration of gases and water in the drill hole under
normal hole pressures. For holes drilled deeper than stripping limits,
the operator/lessee, using cement or other suitable plugging material
the BLM approves in advance, must plug the hole through the thickness
of the oil shale bed(s) or mineral deposit(s) and through aquifers for
a distance of at least 50 feet above and below the oil shale bed(s) or
mineral deposit(s) and aquifers, or to the bottom of the drill hole.
The BLM may approve a lesser cap or plug. Capping and plugging must be
managed to prevent water pollution and the mixing of ground and surface
waters and to ensure the safety of people, livestock, and wildlife;
(b) The operator/lessee must retain for 1 year all drill and
geophysical logs. The operator must also make such logs available for
inspection or analysis by the BLM. The BLM may require the operator/
lessee to retain representative samples of drill cores for 1 year;
(c) The operator/lessee may, after the BLM's written approval, use
drill holes as surveillance wells for the purpose of monitoring the
effects of subsequent operations on the quantity, quality, or pressure
of ground water or mine gases; and
(d) The operator/lessee may, after written approval from the BLM
and the surface owner, convert drill holes to water wells. When
granting such approvals, the BLM will include a transfer to the surface
owner of responsibility for any liability, including eventual plugging,
reclamation, and abandonment.
Sec. 3930.12 Performance standards for underground mining.
(a) Underground mining operations must be conducted in a manner to
prevent the waste of oil shale, to conserve recoverable oil shale
reserves, and to protect other resources. The BLM must approve in
writing permanent abandonment and operations that render oil shale
inaccessible.
(b) The operator/lessee must adopt mining methods that ensure the
proper recovery of recoverable oil shale reserves.
(c) Operators/lessees must adopt measures consistent with known
technology to prevent or, where the mining method used requires
subsidence, control subsidence, maximize mine stability, and maintain
the value and use of surface lands. If the POD indicates that pillars
will not be removed and controlled subsidence is
[[Page 69481]]
not part of the POD, the POD must show that pillars of adequate
dimensions will be left for surface stability, considering the
thickness and strength of the oil shale beds and the strata above and
immediately below the mined interval.
(d) The lessee/operator must have the BLM's approval to temporarily
abandon a mine or portions thereof.
(e) The operator/lessee must have the BLM's prior approval to mine
any recoverable oil shale reserves or drive any underground workings
within 50 feet of any of the outer boundary lines of the federally-
leased or federally-licensed land. The BLM may approve operations
closer to the boundary after taking into consideration state and
Federal environmental laws and regulations.
(f) The lessee/operator must have the BLM's prior approval before
drilling any lateral holes within 50 feet of any outside boundary.
(g) Either the operator/lessee or the BLM may initiate the proposal
to mine oil shale in a barrier pillar if the oil shale in adjoining
lands has been mined out. The lessee/operator of the Federal oil shale
must enter into an agreement with the owner of the oil shale in those
adjacent lands prior to mining the oil shale remaining in the Federal
barrier pillars (which otherwise may be lost).
(h) The BLM must approve final abandonment of a mining area.
Sec. 3930.13 Performance standards for surface mines.
(a) Pit widths for each oil shale seam must be engineered and
designed to eliminate or minimize the amount of oil shale fender to be
left as a permanent pillar on the spoil side of the pit.
(b) Considering mine economics and oil shale quality, the amount of
oil shale wasted in each pit must be minimal.
(c) The BLM must approve the final abandonment of a mining area.
(d) The BLM must approve the conditions under which surface mines,
or portions thereof, will be temporarily abandoned, under the
regulations in this part.
(e) The operator/lessee may, in the interest of conservation, mine
oil shale up to the Federal lease or license boundary line, provided
that the mining:
(1) Complies with existing state and Federal mining, environmental,
reclamation, and safety laws and rules; and
(2) Does not conflict with the rights of adjacent surface owners.
(f) The operator must save topsoil for final application after the
reshaping of disturbed areas has been completed.
Sec. 3930.20 Operations.
(a) Maximum Economic Recovery (MER). All mining and in situ
development and production operations must be conducted in a manner to
yield the MER of the oil shale deposits, consistent with the protection
and use of other natural resources, the protection and preservation of
the environment, including, land, water, and air, and with due regard
for the safety of miners and the public. All shafts, main exits, and
passageways, and overlying beds or mineral deposits that at a future
date may be of economic importance must be protected by adequate
pillars in the deposit being worked or by such other means as the BLM
approves.
(b) New geologic information. The operator must record any new
geologic information obtained during mining or in situ development
operations regarding any mineral deposits on the lease. The operator
must report this new information in a BLM-approved format to the proper
BLM office within 90 calendar days after obtaining the information.
(c) Statutory compliance. Operators must comply with applicable
Federal and state law, including, but not limited to the following:
(1) Clean Air Act (42 U.S.C. 1857 et seq.);
(2) Federal Water Pollution Control Act, as amended (30 U.S.C. 1151
et seq.);
(3) Solid Waste Disposal Act as amended by the Resource
Conservation and Recovery Act (42 U.S.C. 6901 et seq.);
(4) National Historic Preservation Act, as amended (16 U.S.C. 470
et seq.);
(5) Archaeological and Historical Preservation Act, as amended (16
U.S.C. 469 et seq.);
(6) Archaeological Resources Protection Act, as amended (16 U.S.C.
470aa et seq.); and
(7) Native American Graves Protection and Repatriation Act, as
amended (25 U.S.C. 3001 et seq.).
(d) Resource protection. The following additional resource
protection provisions apply to oil shale operations:
(1) Operators must comply with applicable Federal and state
standards for the disposal and treatment of solid wastes. All garbage,
refuse, or waste must either be removed from the affected lands' or
disposed of or treated to minimize, so far as is practicable, their
impact on the lands, water, air, and biological resources;
(2) Operators must conduct operations in a manner to prevent
adverse impacts to threatened or endangered species and any of their
habitat that may be affected by operations.
(3) If the operator encounters any scientifically important
paleontological remains or any historical or archaeological site,
structure, building, or object on Federal lands, it must immediately
notify the BLM. Operators must not, without prior BLM approval,
knowingly disturb, alter, damage, or destroy any scientifically
important paleontological remains or any historical or archaeological
site, structure, building, or object on Federal lands.
Sec. 3930.30 Diligent development milestones.
(a) Operators must diligently develop the oil shale resources
consistent with the terms and conditions of the lease, POD, and these
regulations. If the operator does not maintain or comply with diligent
development milestones, the BLM may initiate lease cancellation. In
order to be considered diligently developing the lease, the lessee/
operator must comply with the following diligence milestones:
(1) Milestone 1. Within 2 years of the lease issuance date, submit
to the proper BLM office an initial POD that meets the requirements of
subpart 3931. The operator must revise the POD following subpart 3931,
if the BLM determines that the initial POD is unacceptable;
(2) Milestone 2. Within 3 years of the lease issuance date, submit
a final POD. The BLM may, based on circumstances beyond the control of
the lessee or operator, or on the complexity of the POD, grant a 1 year
extension to the lessee or operator to submit a complete POD;
(3) Milestone 3. Within 2 years after the BLM approves the final
POD, apply for all required Federal and state permits and licenses;
(4) Milestone 4. Before the end of the 7th year after lease
issuance, begin permitted infrastructure installation, as required by
the BLM approved POD; and
(5) Milestone 5. Before the end of the 10th year after lease
issuance, begin oil shale production.
(b) Operators may apply for additional time to complete a
milestone. The BLM may grant additional time for completing a milestone
if the operator provides documentation that shows to the BLM's
satisfaction that achieving the milestone by the deadline is not
possible for reasons that are beyond the control of the operator.
Allowable time extensions to meet milestone 4 will extend the
requirement to begin production in the 10th lease year by an amount of
time equal to the extension
[[Page 69482]]
granted for milestone 4. This extension also extends the requirements
for payments in lieu of production and minimum production under
paragraphs (c), (d), and (e) of this section.
(c) Operators must maintain minimum annual production every year
after the 10th lease year or pay in lieu of production according to the
lease terms.
(d) Each lease will provide for minimum production. The minimum
production requirement stated in the lease must be met by the end of
the 10th lease year and will be based on the BLM's estimate of the
extraction technology to be used, the recoverable resources on the
lease, expected life of the operation, and other factors the BLM
considers.
(e) Each lease will provide for payment in lieu of the minimum
production for any particular year starting in the 10th lease year.
Payments in lieu of production in year 10 of the lease satisfies
Milestone 5 in paragraph (a)(5) of this section.
Sec. 3930.40 Assessments for missing diligence milestones.
The BLM will assess $50 for each acre in the lease for each missed
diligence milestone each year, prorated on a daily basis, until the
operator or lessee complies with Sec. 3930.30(a). For example: If the
operator does not submit the required POD within the required 2 years
after lease issuance (the first milestone), the BLM will assess the
operator $50 per acre per year until the milestone is met. If the
operator does not meet the second milestone, the BLM will assess the
operator an additional $50 per acre per year, resulting in a total
assessment of $100 per acre per year. If the operator does not begin
production by the end of the initial lease term, or make payments in
lieu thereof, the BLM may initiate lease cancellation procedures (see
Sec. Sec. 3934.21 and 3934.22).
Subpart 3931--Plans of Development and Exploration Plans
Sec. 3931.10 Exploration plans and plans of development for mining
and in situ operations.
(a) The POD must provide for reasonable protection and reclamation
of the environment and the protection and diligent development of the
oil shale resources in the lease.
(b) The operator must submit to the proper BLM office an
exploration plan or POD describing in detail the proposed exploration,
testing, development, or mining operations to be conducted. Exploration
plans or PODs must be consistent with the requirements of the lease or
exploration license and protect nonmineral resources and provide for
the reclamation of the lands affected by the operations on Federal
lease(s) or exploration license(s). All PODs and exploration plans must
be submitted to the proper BLM office.
(c) The lessee or operator must submit 3 copies of the POD to the
proper BLM office or submit it in an acceptable electronic format.
Contact the proper BLM office for detailed information on submitting
copies electronically (see Sec. 3931.40 for submission of exploration
plans).
(d) The BLM will consult with any other Federal, state, or local
agencies involved and review the plan. The BLM may require additional
information or changes in the plan before approving it. If the BLM
denies the plan, it will set forth why it was denied.
(e) All development and exploration activities must comply with the
BLM-approved POD or exploration plan.
(f) Activities under Sec. Sec. 3931.11 and 3931.40, other than
casual use, may not begin until appropriate NEPA analysis is completed
and the BLM approves an exploration plan or POD.
Sec. 3931.11 Content of plan of development.
The POD must contain, at a minimum, the following:
(a) Names, addresses, and telephone numbers of those responsible
for operations to be conducted under the approved plan and to whom
notices and orders are to be delivered, names and addresses of Federal
oil shale lessees and corresponding Federal lease serial numbers, and
names and addresses of surface and mineral owners of record, if other
than the United States;
(b) A general description of geologic conditions and mineral
resources within the area where mining is to be conducted, including
appropriate maps;
(c) A copy of a suitable map or aerial photograph showing the
topography, the area covered by each lease, the name and location of
major topographic and cultural features;
(d) A statement of proposed methods of operation and development,
including the following items as appropriate:
(1) A description detailing the extraction technology to be used;
(2) The equipment to be used in development and extraction;
(3) The proposed access roads;
(4) The size, location, and schematics of all structures,
facilities, and lined or unlined pits to be built;
(5) The stripping ratios, development sequence, and schedule;
(6) The number of acres in the Federal lease(s) or license(s) to be
affected;
(7) Comprehensive well design and procedure for drilling, casing,
cementing, testing, stimulation, clean-up, completion, and production,
for all drilled well types, including those used for heating, freezing,
and disposal;
(8) A description of the methods and means to protect and monitor
all aquifers;
(9) Surveyed well location plats or project-wide well location
plats;
(10) A description of the measurement and handling of produced
fluids, including the anticipated production rates and estimated
recovery factors;
(11) A description of the methods used to dispose of and control
mining waste; and
(12) A description/discussion of the controls that the operator
will use to protect the public, including identification of:
(i) Essential operations, personnel, and health and safety
precautions;
(ii) Programs and plans for noxious gas control (hydrogen sulfide,
ammonia, etc.);
(iii) Well control procedures;
(iv) Temporary abandonment procedures; and
(v) Plans to address spills, leaks, venting, and flaring;
(e) An estimate of the quantity and quality of the oil shale
resources;
(f) An explanation of how MER of the resource will be achieved for
each Federal lease;
(g) Appropriate maps and cross sections showing:
(1) Federal lease boundaries and serial numbers;
(2) Surface ownership and boundaries;
(3) Locations of any existing and abandoned mines and existing oil
and gas well (including well bore trajectories) and water well
locations, including well bore trajectories;
(4) Typical geological structure cross sections;
(5) Location of shafts or mining entries, strip pits, waste dumps,
retort facilities, and surface facilities;
(6) Typical mining or in situ development sequence, with
appropriate time-frames;
(h) A narrative addressing the environmental aspects of the
proposed mine or in situ operation, including at a minimum, the
following:
(1) An estimate of the quantity of water to be used and pollutants
that may enter any receiving waters;
(2) A design for the necessary impoundment, treatment, control, or
injection of all produced water, runoff water, and drainage from
workings; and
(3) A description of measures to be taken to prevent or control
fire, soil
[[Page 69483]]
erosion, subsidence, pollution of surface and ground water, pollution
of air, damage to fish or wildlife or other natural resources, and
hazards to public health and safety;
(i) A reclamation plan and schedule for all Federal lease(s) or
exploration license(s) that details all reclamation activities
necessary to fulfill the requirements of Sec. 3931.20;
(j) The method of abandonment of operations on Federal lease(s) and
exploration license(s) proposed to protect the unmined recoverable
reserves and other resources, including:
(1) The method proposed to fill in, fence, or close all surface
openings that are hazardous to people or animals; and
(2) For in situ operations, a description of the method and
materials to be used to plug all abandoned development or production
wells; and
(k) Any additional information that the BLM determines is necessary
for analysis or approval of the POD.
Sec. 3931.20 Reclamation.
(a) The operator or lessee must restore the disturbed lands to
their pre-mining or pre-exploration use or to a higher use agreed to by
the BLM and the lessee.
(b) The operator must reclaim the area disturbed by taking
reasonable measures to prevent or control onsite and offsite damage to
lands and resources.
(c) Reclamation includes, but is not limited to:
(1) Measures to control erosion, landslides, and water runoff;
(2) Measures to isolate, remove, or control toxic materials;
(3) Reshaping the area disturbed, application of the topsoil, and
re-vegetation of disturbed areas, where reasonably practicable; and
(4) Rehabilitation of fisheries and wildlife habitat.
(d) The operator or lessee must substantially fill in, fence,
protect, or close all surface openings, subsidence holes, surface
excavations, or workings which are a hazard to people or animals. These
protected areas must be maintained in a secure condition during the
term of the lease or exploration license. During reclamation, but
before abandonment of operations, all openings, including water
discharge points, must be closed to the BLM's satisfaction. For in situ
operations, all drilled holes must be plugged and abandoned, as
required by the approved plan.
(e) The operator or lessee must reclaim or protect surface areas no
longer needed for operations as contemporaneously as possible as
required by the approved plan.
Sec. 3931.30 Suspension of operations and production.
(a) The BLM may, in the interest of conservation, agree to a
suspension of lease operations and production. Applications by lessees
for suspensions of operations and production must be filed in duplicate
in the proper BLM office and must explain why it is in the interest of
conservation to suspend operations and production.
(b) The BLM may order a suspension of operations and production if
the suspension is necessary to protect the resource or the environment:
(1) While the BLM performs necessary environmental studies or
analysis;
(2) To ensure that necessary environmental remediation or cleanup
is being performed as a result of activity or inactivity on the part of
the operator; or
(3) While necessary environmental remediation or cleanup is being
performed as a result of unwarranted or unexpected actions.
(c) The term of any lease will be extended by adding thereto any
period of suspension of operations and production during such term.
(d) A suspension will take effect on the date the BLM specifies.
Rental, upcoming diligent development milestones, and minimum annual
production will be suspended:
(1) During any period of suspension of operations and production
beginning with the first day of the lease month on which the suspension
of operations and production is effective; or
(2) If the suspension of operations and production is effective on
any date other than the first day of a lease month, beginning with the
first day of the lease month following such effective date.
(e) The suspension of rental and minimum annual production will end
on the first day of the lease month in which the suspension ends.
(f) The minimum annual production requirements of a lease will be
proportionately reduced for that portion of a lease year for which a
suspension of operations and production is directed or granted by the
BLM, as would any payments in lieu of production.
Sec. 3931.40 Exploration.
To conduct exploration operations under an exploration license or
on a lease after lease issuance, but prior to approval of the POD, the
following rules apply:
(a) Except for casual use, before conducting any exploration
operations on federally-leased or federally-licensed lands, the
operator or lessee must submit to the proper BLM office for approval 3
copies of the exploration plan or a copy of the plan in an acceptable
electronic format. Contact the proper BLM office for detailed
information on submitting copies electronically. As used in this
paragraph, casual use means activities that do not cause appreciable
surface disturbance or damage to lands or other resources and
improvements. Casual use does not include use of heavy equipment,
explosives, or vehicular movement off established roads and trails.
(b) The exploration activities must be consistent with the
requirements of the underlying Federal lease or exploration license,
and address protection of recoverable oil shale reserves and other
resources and reclamation of the surface of the lands affected by the
exploration operations. The exploration plan must meet the requirements
of Sec. 3931.20 and must show how reclamation will be an integral part
of the proposed operations and that reclamation will progress as
contemporaneously as practicable with operations.
Sec. 3931.41 Content of exploration plan.
Exploration plans must contain the following:
(a) The name, address, and telephone number of the applicant, and,
if applicable, that of the operator or lessee of record;
(b) The name, address, and telephone number of the representative
of the applicant who will be present during, and responsible for,
conducting exploration;
(c) A description of the proposed exploration area, cross-
referenced to the map required under paragraph (h) of this section,
including:
(1) Applicable Federal lease and exploration license serial
numbers;
(2) Surface topography;
(3) Geologic, surface water, and other physical features;
(4) Vegetative cover;
(5) Endangered or threatened species listed under the Endangered
Species Act of 1973 (16 U.S.C. 1531 et seq.) that may be affected by
exploration operations;
(6) Districts, sites, buildings, structures, or objects listed on,
or eligible for listing on, the National Register of Historic Places
that may be present in the lease area; and
(7) Known cultural or archaeological resources located within the
proposed exploration area;
(d) A description of the methods to be used to conduct oil shale
exploration, reclamation, and abandonment of operations including, but
not limited to:
(1) The types, sizes, numbers, capacity, and uses of equipment for
drilling and blasting, and road or other access route construction;
[[Page 69484]]
(2) Excavated earth-disposal or debris-disposal activities;
(3) The proposed method for plugging drill holes; and
(4) The estimated size and depth of drill holes, trenches, and test
pits;
(e) An estimated timetable for conducting and completing each phase
of the exploration, drilling, and reclamation;
(f) The estimated amounts of oil shale or oil shale products to be
removed during exploration, a description of the method to be used to
determine those amounts, and the proposed use of the oil shale or oil
shale products removed;
(g) A description of the measures to be used during exploration for
Federal oil shale to comply with the performance standards for
exploration (Sec. Sec. 3930.10 and 3930.11);
(h) A map at a scale of 1:24,000 or larger showing the areas of
land to be affected by the proposed exploration and reclamation. The
map must show:
(1) Existing roads, occupied dwellings, and pipelines;
(2) The proposed location of trenches, roads, and other access
routes and structures to be constructed;
(3) Applicable Federal lease and exploration license boundaries;
(4) The location of land excavations to be conducted;
(5) Oil shale exploratory holes to be drilled or altered;
(6) Earth-disposal or debris-disposal areas;
(7) Existing bodies of surface water; and
(8) Topographic and drainage features; and
(i) The name and address of the owner of record of the surface
land, if other than the United States. If the surface is owned by a
person other than the applicant or if the Federal oil shale is leased
to a person other than the applicant, include evidence of authority to
enter that land for the purpose of conducting exploration and
reclamation.
Sec. 3931.50 Exploration plan and plan of development modifications.
(a) The operator or lessee may apply in writing to the BLM for
modification of the approved exploration plan or POD to adjust to
changed conditions, new information, improved methods, and new or
improved technology or to correct an oversight. To obtain approval of
an exploration plan or POD modification, the operator or lessee must
submit to the proper BLM office a written statement of the proposed
modification and the justification for such modification.
(b) The BLM may require a modification of the approved exploration
plan or POD.
(c) The BLM may approve a partial exploration plan or POD, if
circumstances warrant, or if development of an exploration or POD for
the entire operation is dependent upon unknown factors that cannot or
will not be determined until operations progress. The operator or
lessee must not, however, perform any operation not covered in a BLM-
approved plan.
Sec. 3931.60 Maps of underground and surface mine workings and in
situ surface operations.
Maps of underground workings and surface operations must be to a
scale of 1:24,000 or larger if the BLM requests it. All maps must be
appropriately marked with reference to government land marks or lines
and elevations with reference to sea level. When required by the BLM,
include vertical projections and cross sections in plan views. Maps
must be based on accurate surveys and certified by a professional
engineer, professional land surveyor, or other professionally qualified
person. Accurate copies of such maps must be furnished by the operator
to the BLM when and as required. All maps submitted must be in a format
acceptable to the BLM. Contact the proper BLM office for information on
what is the acceptable format to submit maps.
Sec. 3931.70 Production maps and production reports.
(a) Report production of all oil shale products or by-products to
the BLM on a quarterly basis no later than 30 calendar days after the
end of the reporting period.
(b) Report all production and royalty information to the MMS under
30 CFR parts 210 and 216.
(c) Submit production maps to the proper BLM office no later than
30 calendar days after the end of each royalty reporting period or on a
schedule determined by the BLM. Show all excavations in each separate
bed or deposit on the maps so that the production of minerals for any
period can be accurately ascertained. Production maps must also show
surface boundaries, lease boundaries, topography, and subsidence
resulting from mining activities.
(d) If the lessee or operator does not provide the BLM the maps
required by this section, the BLM will employ a licensed mine surveyor
to make a survey and maps of the mine, and the cost will be charged to
the operator or lessee.
(e) If the BLM believes any map submitted by an operator or lessee
is incorrect, the BLM may have a survey performed, and if the survey
shows the map submitted by the operator or lessee to be substantially
incorrect in whole or in part, the cost of performing the survey and
preparing the map will be charged to the operator or lessee.
(f) For in situ development operations, the lessee or operator must
submit a map showing all surface installations, including pipelines,
meter locations, or other points of measurement necessary for
production verification as part of the POD. All maps must be modified
as necessary for adequate representation of existing operations.
(g) Within 30 calendar days after well completion, the lessee or
operator must submit to the proper BLM office 2 copies of a completed
Form 3160-4, Well Completion or Recompletion Report and Log, limited to
information that is applicable to oil shale operations. Well logs may
be submitted electronically using a BLM-approved electronic format.
Describe surface and bottom-hole locations in latitude and longitude.
Sec. 3931.80 Core or test hole samples and cuttings.
(a) Within 90 calendar days after drilling completion, the operator
or lessee must submit to the proper BLM office a signed copy of records
of all core or test holes made on the lands covered by the lease or
exploration license. The records must show the position and direction
of the holes on a map. The records must include a log of all strata
penetrated and conditions encountered, such as water, gas, or unusual
conditions, and copies of analysis of all samples. Provide this
information to the proper BLM office in either paper copy or in a BLM-
approved electronic format. Contact the proper BLM office for
information on submitting copies electronically. Within 30 calendar
days after its creation, the operator or lessee must also submit to the
proper the BLM office a detailed lithologic log of each test hole and
all other in-hole surveys or other logs produced. Upon the BLM's
request, the operator or lessee must provide to the BLM splits of core
samples and drill cuttings.
(b) The lessee or operator must abandon surface exploration drill
holes for development or holes for exploration to the BLM's
satisfaction by cementing or casing or by other methods approved in
advance by the BLM. Abandonment must be conducted in a manner to
protect the surface and not endanger
[[Page 69485]]
any present or future underground or surface operation or any deposit
of oil, gas, other mineral substances, or ground water.
(c) Operators may convert drill holes to surveillance wells for the
purpose of determining the effect of subsequent operations upon the
quantity, quality, or pressure of ground water or mine gases. The BLM
may require such conversion or the operator may request that the BLM
approve such conversion. Prior to lease or exploration license
termination, all surveillance wells must be plugged and abandoned and
reclaimed, unless the surface owner assumes responsibility for
reclamation of such surveillance wells. The transfer of liability for
reclamation will not be considered complete until the BLM approves it
in writing.
(d) Drilling equipment must be equipped with blowout control
devices suitable for the pressures encountered and acceptable to the
BLM.
Sec. 3931.100 Boundary pillars and buffer zones.
(a) For underground mining operations, all boundary pillars must be
at least 50 feet thick, unless otherwise specified in writing by the
BLM. Boundary and other main pillars may be mined only with the BLM's
prior written consent or on the BLM's order. For in-situ operations, a
50-foot buffer zone from the Federal lease line is required.
(b) If the oil shale on adjacent Federal lands has been worked out
beyond any boundary pillar and no hazards exist, the operator or lessee
must, on the BLM's written order, mine out and remove all available oil
shale in such boundary pillar, both in the lands covered by the lease
and in the adjacent Federal lands, when the BLM determines that such
oil shale can be mined safely without undue hardship to the operator or
lessee.
(c) If the mining rights in adjacent lands are privately owned or
controlled, the lessee must have an agreement with the owners of such
interests for the extraction of the oil shale in the boundary pillars.
Subpart 3932--Lease Modifications and Readjustments
Sec. 3932.10 Lease size modification.
(a) A lessee may apply for a modification of a lease to include
Federal lands adjacent to those in the lease. The total area of the
lease, including the acreage in the modification application and any
previously authorized modification, must not exceed the maximum lease
size (see Sec. 3927.20).
(b) An application for modification of the lease size must:
(1) Be filed with the proper BLM office;
(2) Contain a legal land description of the additional lands
involved;
(3) Contain an explanation of how the modification would meet the
criteria in Sec. 3932.20(a) that qualify the lease for modification;
(4) Explain why the modification would be in the best interest of
the United States;
(5) Include a nonrefundable processing fee that the BLM will
determine under Sec. 3000.11 of this chapter; and
(6) Include a signed qualifications statement consistent with
subpart 3902 of this chapter.
Sec. 3932.20 Lease modification land availability criteria.
(a) The BLM may grant a lease modification if:
(1) There is no competitive interest in the lands covered by the
modification application;
(2) The lands covered by the modification application cannot be
reasonably developed as part of another independent federally-approved
operation;
(3) The modification would be in the public interest; and
(4) The modification does not cause a violation of lease size
limitations under Sec. 3927.20 of this chapter or acreage limitations
under Sec. 3901.20 of this chapter.
(b) The BLM may approve adding lands covered by the modification
application to the existing lease without competitive bidding, but
before the BLM will approve adding lands to the lease, the applicant
must pay in advance the FMV for the interests to be conveyed.
(c) Before modifying a lease, the BLM will prepare any necessary
NEPA analysis covering the proposed lease area under 40 CFR parts 1500
through 1508 and recover the cost of such analysis from the applicant.
Sec. 3932.30 Terms and conditions of a modified lease.
(a) The terms and conditions of a lease modified under this subpart
will be made consistent with the laws, regulations, and land use plans
applicable at the time the lands are added by the modification.
(b) The royalty rate for the lands in the modification is the same
as for the lease.
(c) Before the BLM will approve a lease modification, the lessee
must file a written acceptance of the conditions in the modified lease
and a written consent of the surety under the bond covering the
original lease as modified. The lessee must also submit evidence that
the bond has been amended to cover the modified lease and pay BLM
processing costs.
Sec. 3932.40 Readjustment of lease terms.
(a) Except as provided in paragraph (b) of this section, all leases
are subject to readjustment of lease terms, conditions, and
stipulations at the end of the first 20-year period (the primary term
of the lease) and at the end of each 10-year period thereafter.
(b) Royalty rates will be subject to readjustment at the end of the
primary term and every 20 years thereafter.
(c) At least 30 days prior to the expiration of the readjustment
period, the BLM will notify the lessee by written decision if any
readjustment is to be made and of the proposed readjusted lease terms,
including any revised royalty rate.
(d) Readjustments may be appealed. In the case of an appeal, unless
the readjustment is stayed by the IBLA or the courts, the lessee must
comply with the revised lease terms, including any revised royalty
rate, pending the outcome of the appeal.
Subpart 3933--Assignments and Subleases
Sec. 3933.10 Leases or licenses subject to assignment or sublease.
Any lease may be assigned or subleased and any exploration license
may be assigned in whole or in part to any person, association, or
corporation that meets the qualification requirements in subpart 3902
of this chapter. The BLM may approve or disapprove assignments and
subleases. A licensee proposing to transfer or assign a license must
first offer, in writing, to all other participating parties in the
license, the opportunity to acquire the license (the right of first
refusal).
Sec. 3933.20 Filing fees.
Each application for assignment or sublease of record title or
overriding royalty must include a nonrefundable filing fee of $60. The
BLM will not accept any assignment that does not include the filing
fee.
Sec. 3933.31 Record title assignments.
(a) File in triplicate at the proper BLM office a separate
instrument of assignment for each assignment. File the assignment
application within 90 calendar days after the date of final execution
of the assignment instrument and with it include the:
[[Page 69486]]
(1) Name and current address of assignee;
(2) Interest held by assignor and interest to be assigned;
(3) Serial number of the affected lease or license and a
description of the lands to be assigned as described in the lease or
license;
(4) Percentage of overriding royalties retained; and
(5) Dated signature of assignor.
(b) The assignee must provide a single copy of the request for
approval of assignment which must contain a:
(1) Statement of qualifications and holdings as required by subpart
3902 of this chapter;
(2) Date and the signature of the assignee; and
(3) Nonrefundable filing fee of $60.
(c) The approval of an assignment of all interests in a specific
portion of the lands in a lease or license will create a separate lease
or license, which will be given a new serial number.
Sec. 3933.32 Overriding royalty interests.
File at the proper BLM office, for record purposes only, all
overriding royalty interest assignments within 90 calendar days after
the date of execution of the assignment.
Sec. 3933.40 Account status.
The BLM will not approve an assignment unless the lease or license
account is in good standing.
Sec. 3933.51 Bond coverage.
Before the BLM will approve an assignment, the assignee must submit
to the proper BLM office a new bond in an amount to be determined by
the BLM, or, in lieu thereof, documentation of consent of the surety on
the present bond to the substitution of the assignee as principal (see
subpart 3904 of this chapter).
Sec. 3933.52 Continuing responsibility under assignment and sublease.
(a) The assignor and its surety are responsible for the performance
of any obligation under the lease or license that accrues prior to the
effective date of the BLM's approval of the assignment. After the
effective date of the BLM's approval of the assignment, the assignee
and its surety are responsible for the performance of all lease or
license obligations that accrue after the effective date of the BLM's
approval of the assignment, notwithstanding any terms in the assignment
to the contrary. If the BLM does not approve the assignment, the
purported assignor's obligation to the United States continues as
though no assignment had been filed.
(b) After the effective date of approval of a sublease, the
sublessor and sublessee are jointly and severally liable for the
performance of all lease obligations, notwithstanding any terms in the
sublease to the contrary.
Sec. 3933.60 Effective date.
An assignment or sublease takes effect, so far as the United States
is concerned, on the first day of the month following the BLM's final
approval, or if the assignee requests it in advance, the first day of
the month of the approval.
Sec. 3933.70 Extensions.
The BLM's approval of an assignment or sublease does not extend the
term or the readjustment period of the lease (see Sec. 3932.40) or the
term of the exploration license.
Subpart 3934--Relinquishments, Cancellations, and Terminations
Sec. 3934.10 Relinquishments.
(a) A lease or exploration license or any legal subdivision thereof
may be surrendered by the record title holder by filing a written
relinquishment, in triplicate, in the BLM State Office having
jurisdiction over the lands covered by the relinquishment.
(b) To be relinquished, the lease account must be in good standing
and the relinquishment must be considered to be in the public interest.
(c) A relinquishment will take effect on the date the BLM approves
it, subject to the:
(1) Continued obligation of the lessee or licensee and surety to
make payments of all accrued rentals and royalties;
(2) The proper rehabilitation of the lands to be relinquished to a
condition acceptable to the BLM under these regulations;
(3) Terms of the lease or license; and
(4) Approved exploration plan or development plan.
(d) Prior to relinquishment of an exploration license, the licensee
must give any other parties participating in activities under the
exploration license the opportunity to take over operations under the
exploration license. The licensee must provide to the BLM written
evidence that the offer was made to all other parties participating in
the exploration license.
Sec. 3934.21 Written notice of default.
The BLM will provide the lessee or licensee written notice of any
default, breach, or cause of forfeiture, and provide a time period of
30 calendar days to correct the default, to request an extension of
time in which to correct the default, or to submit evidence showing why
the BLM is in error and why the lease should not be canceled or
exploration license terminated.
Sec. 3934.22 Causes and procedures for lease cancellation.
(a) The BLM will take appropriate steps in a United States District
Court of competent jurisdiction to institute proceedings for the
cancellation of the lease if the lessee:
(1) Does not comply with the provisions of the Act as amended and
other relevant statutes;
(2) Does not comply with any applicable regulations; or
(3) Defaults in the performance of any of the terms, covenants, and
stipulations of the lease, and the BLM does not formally waive the
default, breach, or cause of forfeiture.
(b) A waiver of any particular default, breach, or cause of
forfeiture will not prevent the cancellation and forfeiture of the
lease for any other default, breach, or cause of forfeiture, or for the
same cause occurring at any other time.
Sec. 3934.30 License terminations.
The BLM may terminate an exploration license if:
(a) The BLM issued it in violation of any law or regulation, or if
there are substantive factual errors, such as a lack of title;
(b) The licensee does not comply with the terms and conditions of
the exploration license; or
(c) The licensee does not comply with the approved exploration
plan.
Sec. 3934.40 Payments due.
If a lease is canceled or relinquished for any reason, all bonus,
rentals, royalties, and minimum royalties paid will be forfeited, and
any amounts not paid will be immediately payable to the United States.
Sec. 3934.50 Bona fide purchasers.
The BLM will not cancel a lease or an interest in a lease of a
purchaser if at the time of purchase the purchaser was not aware and
could not have reasonably determined from the BLM records the existence
of a violation of any of the following:
(a) Federal regulatory requirements;
(b) The Act, as amended; or
(c) Lease terms and conditions.
Subpart 3935--Production and Sale Records
Sec. 3935.10 Accounting records.
(a) Operators or lessees must maintain records that provide an
accurate account of, or include all:
(1) Oil shale mined;
(2) Oil shale put through the processing plant and retort;
(3) Mineral products produced and sold;
(4) Shale oil products, shale gas, and shale oil by-products sold;
and
[[Page 69487]]
(5) Shale oil products and by-products that are consumed on-lease
for the beneficial use of the lease.
(b) The records must include relevant quality analyses of oil shale
mined or processed and of all products including synthetic petroleum,
shale oil, shale gas, and shale oil by-products sold.
(c) Production and sale records must be made available for the
BLM's examination during regular business hours.
Subpart 3936--Inspection and Enforcement
Sec. 3936.10 Inspection of underground and surface operations and
facilities.
Operators, licensees, or lessees must allow the BLM, at any time,
either day or night, to inspect or investigate underground and surface
mining, in situ, or exploration operations to determine compliance with
lease or license terms and conditions, compliance with the approved
exploration or development plans, and to verify production.
Sec. 3936.20 Issuance of notices of noncompliance and orders.
(a) If the BLM determines that an operator, licensee, or lessee has
not complied with established requirements, the BLM will issue to the
operator, licensee, or lessee a notice of noncompliance.
(b) If operations threaten immediate, serious, or irreparable
damage to the environment, the mine or deposit being mined, or other
valuable mineral deposits or other resources, the BLM will order the
cessation of operations and will require the operator, licensee, or
lessee to revise the POD or exploration plan.
(c) The operator, licensee, or lessee will be considered to have
received all orders or notices of noncompliance and orders that the
operator, licensee, or lessee receives by personal delivery or
certified mail. The BLM will consider service of any notice of
noncompliance or order to have occurred 7 business days after the date
the notice or order is mailed. Verbal orders and notices may be given
to officials at the mine or exploration site, but the BLM will confirm
them in writing within 10 business days.
Sec. 3936.30 Enforcement of notices of noncompliance and orders.
(a) If the operator, licensee, or lessee does not take action in
accordance with the notice of noncompliance, the BLM may issue an order
to suspend or cease operations or initiate legal proceedings to cancel
the lease or terminate the license under subpart 3934 .
(1) A notice of noncompliance will state how the operator,
licensee, or lessee has not complied with established requirements, and
will specify the action which must be taken to correct the
noncompliance and the time limits within which such action must be
taken. The operator, licensee, or lessee must notify the BLM when
noncompliance items have been corrected.
(2) If the operator, licensee, or lessee does not comply with the
notice of noncompliance or order within the specified time frame, the
operator, licensee, or lessee may be ordered to pay an assessment of
$500 per day for each incident of noncompliance that is not corrected
until the noncompliance is corrected to the BLM's satisfaction.
(3) Noncompliance with the approved exploration or development plan
that results in wasted resource may result in the lessee or licensee
being assessed royalty at the market value, in addition to the
noncompliance assessment.
(b) If the BLM determines that the failure to comply with the
exploration or development plan threatens health or human safety or
immediate, serious, or irreparable damage to the environment, the mine
or the deposit being mined or explored, or other valuable mineral
deposits or other resources, the BLM may, either in writing or verbally
followed with written confirmation within 5 business days, order the
cessation of operations or exploration without prior notice.
Sec. 3936.40 Appeals.
Notices of noncompliance and orders or decisions issued under the
regulations in this part may be appealed as provided in part 4 of this
title. All decisions and orders by the BLM under this part remain
effective pending appeal unless the BLM decides otherwise. A petition
for the stay of a decision may be filed with the IBLA.
[FR Doc. E8-27025 Filed 11-17-08; 8:45 am]
BILLING CODE 4310-$$-P