# Oil Shale Management-General

> Briefs, arguments, decisions, and more.

URL: https://www.frixlaw.com/law-library/documents/fr%3AE8-16275

## Record

- **Collection:** Federal Register
- **Document type:** Proposed Rule
- **Published:** July 23, 2008
- **Citation:** 73 FR 42926

## Text

DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3900, 3910, 3920, and 3930
[WO-320-1310-OSHL]
RIN 1004-AD90
Oil Shale Management—General

AGENCY:

Bureau of Land Management, Interior.

ACTION:

Proposed rule.

SUMMARY:

The Bureau of Land Management (BLM) is proposing regulations to set out the policies and procedures for the implementation of a commercial leasing program for the management of federally-owned oil shale and any associated minerals located on Federal lands. The Energy Policy Act of 2005 (EP Act) directs the Secretary of the Interior to: Make public lands available for conducting oil shale research and development activities; complete a Programmatic Environmental Impact Statement (PEIS) for a commercial leasing program for both oil shale and tar sands resources on the BLM administered lands in Colorado, Utah, and Wyoming; and issue regulations establishing a commercial oil shale leasing program.

These proposed regulations would incorporate specific provisions of the Mineral Leasing Act of 1920 (MLA) and the EP Act relating to: Maximum oil shale lease size; maximum acreage limitations; rental; and lease diligence.

These proposed regulations would also address the diligent development requirements of the EP Act by establishing work requirements and milestones to ensure diligent development of leases. The proposed rule would also provide for other standard components of a BLM mineral leasing program, including lease administration and operations.

DATES:

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

ADDRESSES:

Mail
: U.S. Department of the Interior, Director (630), Bureau of Land Management, Mail Stop 401 LS, 1849 C St., NW.,
Attention:
1004-AD90, Washington, DC 20240.

Personal or messenger delivery: 1620 L Street, NW., Room 401, Washington, DC 20036.

Federal eRulemaking Portal: http://www.regulations.gov
. Follow the instructions at this Web site.

You may also send comments on the information collection aspects of this proposed rule directly to: Interior Desk Officer (1004-AD90), Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), (202) 395-6566 (facsimile);
e-mail: oira_docket@omb.eop.gov
. Please also send a copy to the BLM.

FOR FURTHER INFORMATION CONTACT:

Mitchell Leverette, Chief, Division of Solid Minerals at (202) 452-5088 for issues related to the BLM's commercial oil shale leasing program or Kelly Odom at (202) 452-5028 for regulatory process issues. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339, 24 hours a day, 7 days a week, to leave a message or question with the above individuals. You will receive a reply during normal business hours.

SUPPLEMENTARY INFORMATION:

I. Public Comment Procedures

II. Background

III. Discussion of the Proposed Rule

IV. Procedural Matters

I. Public Comment Procedures

A. How do I comment on the proposed rule?

If you wish to comment, you may submit your comments by any one of several methods:

• You may mail comments to U.S. Department of the Interior, Director (630), Bureau of Land Management, Mail Stop 401 LS, 1849 C St., NW.,
Attention
: 1004-AD90, Washington, DC 20240.

• You may deliver comments to Room 401, 1620 L Street, NW., Washington, DC 20036.

• You may access and comment on the proposed rules at the Federal eRulemaking Portal by following the instructions at that site (see
ADDRESSES
).

Please make your comments on the proposed rule as specific as possible, confine them to issues pertinent to the proposed rule, and explain the reason for any changes you recommend. Where possible, your comments should reference the specific section or paragraph of the proposal that you are addressing.

The BLM may not necessarily consider or include in the Administrative Record for the final rule comments that we receive after the close of the comment period (see
DATES
) or comments delivered to an address other than those listed above (see
ADDRESSES
).

B. May I review comments submitted by others?

Comments, including names and street addresses of respondents, will be available for public review at the address listed under
ADDRESSES
: Personal or messenger delivery during regular hours (7:45 a.m. to 4:15 p.m.), Monday through Friday, except holidays. The comments are also available for public review on
http://www.regulations.gov
.

Before including your address, telephone number, e-mail address, or other personal identifying information in your comment, be advised that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold from public review your personal identifying information, we cannot guarantee that we will be able to do so.

II. Background

The BLM is proposing these regulations to implement the EP Act (42 U.S.C. 15927), which became law on August 8, 2005. Section 369 of the EP Act addresses oil shale development and authorizes the Secretary of the Interior to establish regulations for a commercial leasing program. The MLA of 1920 (30 U.S.C. 241(a)) provides the authority for the BLM to allow for the exploration, development, and utilization of oil shale resources on the BLM-managed public lands. Additional statutory authorities for these proposed regulations are:

(1) The Mineral Leasing Act for Acquired Lands of 1947 (30 U.S.C. 351-359); and

(2) The Federal Land Policy and Management Act (FLPMA) of 1976 (43 U.S.C. 1701
et seq.
, including 43 U.S.C. 1732).

Oil shale is a fine-grained sedimentary rock containing organic matter from which shale oil may be produced. Oil shale is a marlstone and contains no oil; rather, it contains un-decayed algae called kerogen (not oil). In fact, the word kerogen is a Greek word interpreted to mean “to produce wax”—“kero” (wax), “gen” to produce. The waxy substance produced from oil shale rock is not the same as conventional crude oil. The kerogen only has a market value as an energy source after it has been refined and converted to synthetic crude oil.

Oil shale is a solid rock and must be mined or treated in place to release the kerogen oil from the rock. Energy companies and petroleum researchers have, over the past 60 years, developed

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

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

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

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

The American Association of Petroleum Geologists estimates that the total world oil shale resources contain the equivalent of 2.6 trillion barrels of oil. According to estimates by the U.S. Geological Survey, the United States holds more than 50 percent of the world's oil shale resources.

The largest known deposits of oil shale in the world are located in a 16,000 square mile area in the Green River formation in Colorado, Utah, and Wyoming (underlying the Piceance, Uinta, Green River, and Washakie Basins), which is estimated to contain the equivalent of between 1.5 and 1.8 trillion barrels of oil. Federal lands comprise 72 percent of the total surface of oil shale acreage and 82 percent of the oil shale resources in the Green River formation.

As stated in the June 9, 2005 call for nominations for the research, development, and demonstration (R, D and D) (70 FR 33753) leases, the BLM opted for a staged oil shale leasing program. The first stage is the research and development program followed by these proposed commercial leasing regulations.

BLM oil shale initiatives since 1983.

In 1973, four leases were issued in the oil shale prototype leasing program. During the 1973-74 oil shale prototype program, there were expectations of an economic boom in western Colorado which never materialized. The oil shale industry collapsed on May 2, 1982, commonly referred to as Black Sunday.

In 1983, the BLM established an Oil Shale Task Force to address:

(1) Access to unconventional energy resources (such as oil shale) on public lands;

(2) Impediments to oil shale development on public lands;

(3) Industry interest in research and development and commercial opportunities on public lands; and

(4) Secretarial options to capitalize on these opportunities.

On February 11, 1983, the BLM published a proposed rule for an oil shale leasing program (48 FR 6510). Due to apparent lack of interest in the development of oil shale, the BLM withdrew the proposed rule, effective September 25, 1985 (50 FR 38867).

In order to be better able to expand and diversify domestic energy production, on November 22, 2004, the BLM published a notice in the
Federal Register
(69 FR 67935) requesting public comments on the potential for oil shale development within the Piceance Creek Basin in Colorado, the Uinta Basin in Utah, and the Green River and Washakie Basins in Wyoming. The
Federal Register
notice also requested comments on a proposed draft oil shale R, D and D lease form. Comments received were incorporated, as appropriate, into the final R, D and D lease form.

On June 9, 2005, the BLM published a notice in the
Federal Register
(70 FR 33753) which initiated a R, D and D leasing program by soliciting nominations of 160-acre parcels of public land to be leased in Colorado, Utah, and Wyoming for conducting oil shale recovery technologies. In response to the 19 nominations of parcels that the BLM received, the BLM issued 6 R, D and D leases—5 in Colorado that were effective January 1, 2007, and an additional R, D and D lease in Utah that was effective on July 1, 2007. Each of the R, D and D leases contains a preference right for conversion to a commercial lease of additional acreage upon demonstration of a successful method of producing oil from shale rock.

One of the purposes of the R, D and D leases, as stated in the notice was to provide the BLM, state and local governments, and the public with important information that could be utilized as the BLM works with communities, states, and other Federal agencies to develop strategies for managing the environmental effects of production. The R, D and D lease form was published as an attachment (Appendix A) to the June 9, 2005,
Federal Register
notice.

The PEIS and National Environmental Policy Act (NEPA) Compliance

On December 13, 2005, the BLM published in the
Federal Register
a notice of intent (NOI) to prepare a PEIS (70 FR 73791) for oil shale and tar sands resources leasing on lands administered by the BLM in Colorado, Utah, and Wyoming. The NOI alerted the public that the BLM was intending to amend several resource management plans (RMPs) to open lands for oil shale and tar sands resources leasing in Colorado, Utah, and Wyoming. The NOI also informed the public of the development of the oil shale regulations required by Section 369(d)(2) of the EP Act. The RMPs are BLM planning documents prepared under Section 202 of the FLPMA that present guidelines for making resource management decisions.

The draft PEIS evaluates the following RMPs for possible amendment:

(1)
Wyoming
: Green River, Great Divide, and Kemmerer;

(2)
Utah
: Price River, San Juan, San Rafael, Henry Mountain, Book Cliffs, and Diamond Mountain; and

(3)
Colorado
: Grand Junction, White River, and Glenwood Springs.

Although the PEIS covers planning for tar sands, these proposed regulations do not address tar sands leasing since the BLM has regulations in place that address tar sands leasing (see 43 CFR part 3140).

On December 21, 2007, the BLM published the notice of availability for the draft PEIS and has made the draft PEIS available for public comment (72 FR 72751). The BLM intends to finalize the PEIS before these regulations are final. The PEIS is primarily intended to analyze the impacts of land use allocation and not site specific oil shale leasing.

Advance Notice of Proposed Rulemaking

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

key components of the proposed regulations:

(1) What should be the royalty rate and point of royalty determination?

(2) Should the regulations establish a process for bid adequacy evaluation,i.e., Fair Market Value (FMV) determination, or should the regulations establish a minimum acceptable lease bonus bid?

(3) How should diligent development be determined?

(4) What should be the minimum production requirement?

(5) Should there be provisions for small tract leasing?

On September 26, 2006, the BLM published a
Federal Register
notice reopening the comment period for the ANPR and extending the comment period until October 25, 2006 (71 FR 56085). In response to the ANPR, the BLM received 48 comments.

Comments were received from individuals, public interest groups, and industry representatives. Although the ANPR focused on the 5 areas previously identified, commenters addressed a variety of topics, including whether or not they were supportive of a commercial oil shale leasing program. Below is a discussion of the ANPR organized by topic. Public comments BLM received on the ANPR are discussed in this preamble at the appropriate section of this rule.

Royalty Rate and Point of Royalty Determination—Section 369(o) of the EP Act does not prescribe a royalty rate, but does provide that the royalty rate for oil shale should encourage development of the resource and should ensure a fair return to the United States. The ANPR comments received were extremely varied and recommended a wide range of royalty rates. Discussion of the ANPR royalty comments can be found in the discussion of section 3903.52 of this rule.

Bid Adequacy Evaluation (Fair Market Value)—It is the policy of the United States, stated in Section 102(a) of FLPMA (43 U.S.C. 1701(a)(9)) and Section 369(o)(2) of the EP Act, that the United States receive FMV for the issuance of Federal mineral leases. The BLM's purpose for requesting comments on the FMV it should receive for lease tracts was to solicit ideas on how FMV would be determined for a resource that has little or no history of comparable sales. The public comments received on the ANPR are discussed in section 3924.10 of this rule.

Diligent Development—Section 369(f) of the EP Act requires that the BLM establish work requirements and milestones to ensure diligent development of Federal oil shale leases. The BLM requested public comment on diligent development to assist us in determining lease diligence requirements for an industry that has yet to be successfully established. A discussion of the ANPR comments we received on diligence can be found in section 3927.50 of this proposed rule.

Minimum Production Requirement—The BLM specifically asked in the ANPR for suggestions from the public about what the minimum production requirement should be to assist us in determining lease production requirements for an industry that has yet to be successfully established. A discussion of the public comments we received on minimum production requirements can be found in section 3903.51 of this proposed rule.

Small Tract Leasing—In the ANPR the BLM requested comments on whether there should be small tract leasing or leasing small acreages of land for oil shale development. A discussion of the public comments we received on small tract leasing can be found in section 3927.20 of this proposed rule.

We also received several comments unrelated to the five questions in the ANPR. Those comments are discussed in the respective section discussions for the rule.

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

The BLM, in coordination with the Minerals Management Service (MMS), held three “listening sessions” with representatives of the governors of the States of Colorado, Utah, and Wyoming. The BLM and the MMS met with these representatives in Denver, Colorado (December 14, 2006), Salt Lake City, Utah (April 26, 2007), and Cheyenne, Wyoming (August 8, 2007). The purpose of the listening sessions was to provide the governors' representatives the opportunity to share their ideas, issues, and concerns relating to the proposed commercial oil shale leasing regulations.

Section 369(e) of the EP Act requires the Department of the Interior to consult with the governors of Colorado, Utah, and Wyoming, representatives of local governments, interested Indian tribes, and the public to determine the level of support for conducting oil shale lease sales. The BLM plans to consult with the affected states prior to conducting the first oil shale lease sale, and following publication of the final rule.

Consolidated Appropriations Act of 2008

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

III. Discussion of the Proposed Rule

Part 3900—Oil Shale Management—General

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

Subpart 3900—Oil Shale Management—Introduction

This subpart would establish competitive oil shale leasing administrative procedures for implementing a long-term commercial oil shale leasing program.

The proposed rule would contain specific provisions required by Section 369 of the EP Act. Many of the sections of the proposed rule contain regulatory requirements similar to the regulations in the BLM's existing mineral programs namely, coal, non-energy leasable minerals, and oil and gas. In creating a regulatory framework for this proposed oil shale commercial leasing program, the BLM proposes to adopt certain basic components and processes common to the BLM's leasing programs. Most of the BLM's leasing programs are governed by the MLA. The regulations governing those programs and this program would include the following types of provisions: Pre-lease exploration; leasing processes; bonding; operations (including plan of development); reclamation; and inspection and enforcement.

Section 3900.2 would contain the definitions and terms used in these proposed regulations. Many of the terms and definitions found in this section would be similar to terms and definitions in the regulations of other BLM mineral leasing programs. Because most of the terms and concepts in this section are well-established, this section of the preamble does not address each of the definitions, but focuses only on definitions for certain terms that directly affect the reader's understanding of the regulatory framework of the oil shale leasing program or that are unique to these regulations.

The term “commercial quantities” means production of shale oil quantities in accordance with the approved Plan of Development for the proposed project through the research, development, and demonstration activities conducted on the lease, based on and at the conclusion of which a reasonable expectation exists that the expanded operation would provide a positive return after all costs of production have been met, including the amortized costs of the capital investment.

The term “infrastructure” means all support structures necessary for the production or development of shale oil. The definition lists examples of the different types of support structures that the BLM would consider to be infrastructure. This term is defined in these proposed regulations because it is critical to the BLM's review of lease applications. Infrastructure impacts are a key component of the plan of operations that the BLM will review when undertaking various analyses such as those required by NEPA. Furthermore, the BLM believes that a detailed itemization of examples is necessary since installation of infrastructure is one of the proposed diligent development milestones.

The term “oil shale” means a fine-grained sedimentary rock containing:

(1) Organic matter which was derived chiefly from aquatic organisms or waxy spores or pollen grains, which is only slightly soluble in ordinary petroleum solvents, and of which a large proportion is distillable into synthetic petroleum; and

(2) Inorganic matter, which may contain other minerals. This term is applicable to any argillaceous, carbonate, or siliceous sedimentary rock which, through destructive distillation, will yield synthetic petroleum.

The BLM defined the term “production” to acknowledge the various technologies associated with operations for extraction of shale oil, shale gas, or shale oil by-products.

Section 3900.5 would leave a place holder for the information collection requirements in parts 3900-3930 under 44 U.S.C. 3501 et seq. The BLM will add the OMB form number once we receive OMB's approval for information collection in the final regulations. The table in paragraph (d) of this section lists the subparts in the rule requiring the information and its title and summarizes the reasons for collecting the information and how the BLM would use the information.

Section 3900.10 would identify which lands would be subject to leasing under parts 3900 through 3930. Section 21 of the MLA authorizes the issuance of oil shale leases (30 U.S.C. 241(a)).

Section 3900.20 would address the right to appeal the BLM decisions issued under these regulations to the Interior Board of Land Appeals under 43 CFR part 4. This section would adopt standard appeals language found in the regulations of other BLM mineral programs.

Section 3900.30 would contain standard language providing that documents (i.e., applications, statements of qualification, plans of development and supporting information, etc.) required by these proposed regulations be filed in the proper BLM office with the required fees. The term “proper BLM office” is defined in the definitions section of this rule.

Section 3900.40 would address the multiple use mandate of FLPMA, by providing that the BLM's issuance of an exploration license or lease for the development or production of oil shale would not preclude the issuance of other exploration licenses or leases on the same lands for deposits of other minerals or other resource uses. This provision is similar to regulatory provisions in the BLM's other leasing programs, which also promote multiple use of the public lands.

Section 3900.50 would clarify the relationship of land use plans and NEPA to the BLM's proposed commercial oil shale leasing program. This section would provide that any lease or exploration license issued under these regulations would be issued under the decisions, terms, and conditions of a comprehensive land use plan. The land use planning process is the key tool used by the BLM to protect resources and designate uses for BLM-administered lands. Compliance with NEPA and land use planning is required prior to the BLM's issuing a lease or exploration license.

Section 3900.61 would address the procedures the BLM would follow concerning consent and consultation where the surface of public land is administered by other Federal agencies outside of the Department of the Interior and procedures for particular situations where the U.S. has conveyed title to or transferred control of the surface. Paragraphs (a) and (b) would address those procedures the BLM would follow concerning consent and consultation where the surface of public lands is administered by other agencies outside of the Department of the Interior. Paragraph (c) would provide procedures an applicant may pursue in challenging a decision issued by a particular agency outside of the Department of the Interior relating to special stipulations or refusal of consent. Paragraph (d) would not allow the BLM to issue a lease or license on National Forest Service lands without the consent of the Forest Service. Under paragraph (d), the BLM's decision whether to issue the lease or license is based on a determination as to whether the interests of the United States would best be served by issuing the lease or license. The provisions of this section closely mirror BLM regulations for oil and gas, coal, and non-energy leasable minerals. Paragraph (e) would provide that the BLM make the final decision as to whether to issue a lease or license in those cases not involving a Federal agency, where the United States has conveyed title to any state or political subdivision or agency, including a college or any other educational corporation or association, to a charitable or religious corporation or association, or to a private entity.

Section 3900.62 would address situations where the BLM may require lease or exploration license stipulations to protect lands and resources. Stipulations are site specific provisions that the BLM may add to standard lease or license terms prior to issuance for the purpose of protecting Federal resource values and mitigating impacts to other values identified in a NEPA document. Stipulations frequently restrict operations on the lease or permit by limiting surface disturbance for the purpose of protecting the environment. This includes the protection of wildlife, plants, and cultural or other resources. This provision is similar to those found in the BLM's other mineral leasing programs.

Subpart 3901—Land Descriptions and Acreage

Section 3901.10 would contain the BLM's requirements for land descriptions in applications or documents submitted to the BLM. This section is similar to the regulatory provisions addressing land descriptions found in other BLM leasing programs and would establish consistent standards for land descriptions in applications submitted to the BLM.

Sections 3901.20 and 3901.30 would incorporate the provisions of Section 369(j)(2) of the EP Act that 50,000 acres would be the maximum acreage of oil shale leases on public lands that any entity may hold in any one state and that the oil shale lease acreage would not count toward acreage limitations associated with oil and gas leases. Another 50,000 acres may be held on acquired lands. Since the provisions in this section relating to maximum acreage holdings are statutory, the BLM

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

Subpart 3902—Qualification Requirements

Sections under this subpart would detail the various statutory requirements under Section 27 of the MLA relating to who can hold Federal oil shale leases and interests. These proposed regulations would mirror many of the qualification provisions of the BLM's other mineral leasing regulations, namely oil and gas (43 CFR subpart 3102), geothermal (43 CFR subpart 3202), coal (43 CFR subpart 3425), and non-energy leasable minerals (43 CFR subpart 3502).

Section 3902.10 would enumerate the requirements of the MLA relating to who is authorized to hold leases or interests in leases (30 U.S.C. 181, 352). These requirements have a longstanding statutory and regulatory history and are found in the regulations for the BLM's mineral leasing programs.

Sections 3902.21 and 3902.22 would explain the filing procedures for qualification documents, including when and where to file documents. Section 3902.21 would also require that all documentation submitted to the BLM as evidence of qualifications be current, accurate, and complete.

Sections 3902.23 through 3902.29 would detail the type of qualifications documentation that the BLM would require from:

(1) Individuals (section 3902.23);

(2) Associations, including partnerships (section 3902.24);

(3) Corporations (section 3902.25);

(4) Guardians or trustees (section 3902.26);

(5) Heirs and devisees (section 3902.27);

(6) Attorneys-in-fact (section 3902.28); and

(7) Other parties in interest (section 3902.29).

The requirements proposed in these sections are similar to the standard requirements of other BLM regulations to show evidence of qualifications to hold a lease under the MLA.

Subpart 3903—Fees, Rentals, and Royalties

For payments of required rental and royalties, sections 3903.20 and 3903.30 would address the acceptable forms of payment (section 3903.20) and where to submit payment for processing or filing fees, rentals, bonus payments, and royalties (section 3903.30). The acceptable forms of payment listed in section 3903.20 would mirror the forms of payment accepted in the BLM's other mineral leasing regulations.

Section 3903.40 would incorporate the requirement of Section 369(j) of the EP Act that the annual rental rate for an oil shale lease would be $2.00 per acre. Since the statute sets the rental rate, the BLM has no discretion to revise it.

Section 3903.51 would address the minimal annual production requirement that would apply to every lease. It also would discuss payments in lieu of production beginning with the 10th lease year. The BLM would determine the payment in lieu of annual production, but in no case would it be less than $4 per acre. Payments in lieu of production are not unique to this proposed rule. They are a requirement of other BLM mineral leasing regulations and the BLM believes they provide an incentive to maintain production.

Setting the payment in lieu of production at no less than $4 per acre should be an adequate payment to the Federal government to justify allowing the lessee to continue holding a lease absent production, but should not be high enough to cause the lessee to relinquish the lease. A payment in lieu of production of $4 per acre for the maximum lease size of 5,760 acres equals a payment of $23,040 per year.

In response to the ANPR, the BLM received comments expressing various ideas concerning minimum production amounts and requirements. The comments are summarized as follows:

(1) Minimum production should be 1,000 barrels a day;

(2) Minimum production should be based on the viability of the operation;

(3) Minimum production levels should be based on resource potential and production levels identified in the plan of development;

(4) Minimum royalties should be assessed at the end of the primary term;

(5) Minimum production should be based on a percentage of the projected resource base; and

(6) There should not be a minimum production requirement.

We agree with several of the commenter's suggestions. The suggestions to base minimum production on the approved plan of development and the specifics of the operation were incorporated into proposed sections 3930.30(c) and 3930.30(d). The suggestions related to defining the minimum production on a percentage of the resource base were not incorporated into the proposed rule because of the difficulties associated with defining the recoverable resource, the variables associated with the different development technologies, and the differing kerogen content of the shales. We consider the suggestion that identified 1,000 barrels a day as the correct minimum production requirement too inflexible a standard because it does not allow for differences in shale quality and differences in extraction technology.

Section 3903.52—Royalty Rates on Oil Shale Production

Section 3903.52 would establish a royalty rate for all products that are sold from or transported off of the lease area. The BLM recognizes that encouraging oil shale development presents some unique challenges compared to BLM's traditional role in managing conventional oil and gas operations. We received a wide range of comments presenting alternative royalty approaches as part of the ANPR process, and we address those comments below. However, while we have narrowed the range of options based on the ANPR comments, we have not yet settled on a single royalty rate for this proposed rule. Instead, we are presenting two royalty rate alternatives in the proposed rule (as outlined later in this section), and requesting public comment on those specific alternatives. In addition, we are considering a third alternative, a sliding scale royalty rate (also outlined in this preamble), and we are seeking public comment on the appropriate parameters for the sliding scale royalty rate should the BLM choose to adopt this alternative. We anticipate adopting one of these alternatives, or variations on one of these alternatives, at the final rule stage.

EP Act (Section 369(o)) directs the agency to establish royalties and other payments for oil shale leases that “shall—

(1) Encourage development of the oil shale and tar sands resources; and

(2) Ensure a fair return to the United States.”

The market demand for oil shale resources based on the price of competing sources (e.g., crude oil) of similar end products is expected to provide the primary incentive for future oil shale development. Additional encouragement for development may be provided through the royalty terms employed for oil shale relative to conventional oil and gas royalty terms, but we recognize that such incentives must be balanced against the objective of providing a fair return to taxpayers for the sale of these resources. Through the ANPR process, the BLM initially examined a wide range of royalty options, including:

(1) 12.5 percent royalty rate on the first marketable product;

(2) 12.5 percent royalty rate on the value of the mined oil shale rock, as proposed in 1983;

(3) 8 percent royalty rate on products sold for 10 years with optional increases of 1 percent per year up to a maximum of 12.5 percent, similar to the rates established by the State of Utah in 1980;

(4) Initial 2 percent royalty to encourage production and a 5 percent maximum upon establishment of infrastructure;

(5) Sliding scale royalty rate tied to timeframes up to a maximum of 12.5 percent;

(6) Sliding scale royalty rate tied to production amounts up to a maximum of 12.5 percent;

(7) Sliding scale royalty rate with royalty rates tied to the price of crude oil;

(8) Royalty rate of 1 percent of gross profit before payout and royalty rate of 25 percent net profit after payout—(Canadian oil sands model);

(9) Royalty based on cents per ton as proposed in the 1973 oil shale prototype program; and

(10) Royalty based on British Thermal Unit (Btu) content as compared to crude oil.

In evaluating an appropriate royalty rate system for oil shale that would meet the dual EP Act objectives of encouraging development and ensuring a fair return to the government, the BLM also reviewed other Federal royalty rates for Federal minerals set by statute and under existing regulations administered by Department of the Interior bureaus, and royalty rates applied to oil shale production in other countries.

The royalty rates for other Federal energy minerals vary. Specifically, current royalty rates for Federal energy minerals under Department of the Interior leasing programs include:

(1) Onshore oil and gas (12.5 percent);

(2) Offshore oil and gas (16.67 percent), Gulf of Mexico Region (18.75 percent);

(3) Underground coal (8 percent);

(4) Surface coal (12.5 percent) and

(5) Geothermal (for new leases: 1.75 percent for the first 10 years and 3.5 percent thereafter. For leases issued prior to the EP Act, 10 percent on net proceeds after deductions).

Many of these programs allow for royalty rate relief under certain circumstances.

The BLM also looked at royalty applications for oil shale and similar unconventional fuels in other countries, including:

(1) For oil sands, Canada applies a royalty rate of 1 percent of the gross revenue before payout (before companies have recouped investment costs) with a 25 percent net profit royalty rate applied after payout;

(2) Australia has a 10 percent gross royalty on the value of the shale oil produced;

(3) Brazil applies a 3 percent gross royalty rate;

(4) Estonia does not have a royalty; and

(5) No information on a royalty rate for shale oil produced in China was available.

It should be noted that Canada produces oil from oil sands, not oil shale. The oil in the sands is the same as crude oil, but dispersed in sand. Extraction and processing is more expensive than for conventional crude oil production, but less expensive than is anticipated for oil shale. Canadian operators have never reached the payout point due to the continued capital expenditures in new equipment, so to date, Canada has received a 1 percent royalty on oil sands production.

Australian operations are using the Alberta Taciuk Process, which is the same type of technology currently used by the Oil Shale Exploration Company (OSEC) in Utah. Despite their 10 percent royalty rate, the Australian oil shale project (the Stuart Project) was heavily subsidized by the Australian government through other means (tax incentives). Even the government subsidies could not sustain oil shale operations in Australia. The last three operators went into bankruptcy after brief operations. Suncor, the founder of the Stuart Project and a successful developer of the Canadian tar sands, exited the Australian oil shale business after losing approximately one hundred million dollars.
1

For its Utah demonstration project, OSEC is also expected to test the Petrosix horizontal retort process, which is currently being used by Petrobras, Brazil, for oil shale operations.

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

Australia and Brazil are the only other known countries that are producing or have produced oil shale using the same technologies as in the U.S. Oil shale developmental efforts in China and Estonia are owned by their respective governments. Because no other country has yet achieved successful commercial oil shale operations and because of the wide variety of oversight and revenue structures employed in each country, the BLM's review of these systems did not identify a useful model for a royalty system to be used for oil shale development on Federal lands in the U.S.

In the ANPR, the BLM solicited public input on the royalty rate and point of royalty determination. The BLM's purpose for requesting comments was to solicit ideas on these royalty issues for a resource that has little or no history of commercial development.

There were approximately thirty-one entities that provided comments through the ANPR process that were specific to royalty rate and royalty point of determination. The comments suggested royalty rates that ranged from a royalty rate of zero to a royalty rate of 12.5 percent. Of the royalty-related comments, three suggested that the royalty be set at 12.5 percent, the same rate as in BLM's oil and gas program, while some comments described a 12.5 percent royalty rate as unreasonable. It is contemplated that the primary products produced from oil shale will compete directly with those from onshore oil and gas production, which has a 12.5 percent royalty rate. However, the BLM recognizes that the nature of potential oil shale operations differs from that of conventional oil and gas operations and that these differences may suggest the need for a royalty system other than the traditional flat rate of 12.5 percent used for conventional onshore oil and gas operations.

In determining the royalty rate for oil shale, it should be noted that there is a significant difference between oil shale mineral deposits and a conventional crude oil reservoir. As discussed in the Background section of this preamble, oil shale is a marlstone that contains no oil, but kerogen, that needs to be refined and converted to synthetic crude oil.

Currently, proposed processes to extract kerogen from an oil shale deposit are also considerably different, as well as labor and capital intensive. Oil shale is a solid rock that must be mined or treated in place to release the kerogen. Two of these processes are discussed in the Background section of this preamble.

Seven of the comments recommended that a “very low royalty rate” be established until after companies have recouped the costs of their investments (debt service and capital investment). Many among the seven recommended that a 1 percent royalty rate be the starting point, and they used the Canadian oil sands royalty scheme as an example. As discussed above, the BLM looked at royalty applications for oil shale and similar unconventional fuels in other countries. The Canadian tar sand model presents two challenges. First, because of the continual infusion of capital to acquire new equipment the payout point is never being reached.

Secondly, because of the complexity of determining when payout may occur, such a royalty scheme is subject to easy manipulation and higher administrative costs. Therefore, the BLM considered the investment payout scheme as inconsistent with the premise of “a fair return” to the taxpayers as mandated in EP Act.

Three of the ANPR comments recommended that “royalties must be high enough” to support local communities and infrastructure; however, these comments did not provide specific royalty rates. Oil shale royalties are not designated for community and infrastructure support, but by statute are required to be split between the Federal Treasury and the states (30 U.S.C. 191). Presumably states could choose to direct a portion of the royalty revenues they receive to local community and infrastructure support, but that would be a state choice, and for the purposes of this rulemaking, these comments were not considered because they assume a use of royalty revenues not available under current law.

Three comments suggested that royalties should not be charged on hydrocarbons unavoidably lost or used on the lease for the benefit of the lease, but did not directly address the royalty rate issue.

One comment suggested the royalty be “based on the material as it exists naturally in the land, and as it is removed from the land.” This comment seems to suggest that royalty should be based on mined raw shale. While the BLM acknowledges the inherent differences between an oil shale deposit and other deposits from which similar products can be produced, this suggestion was not considered because there is no known value for raw oil shale since there is no oil shale industry or an established market for raw oil shale. However, it should be noted that in 1983 the BLM proposed a rule to establish a royalty rate equivalent to 12.5 percent of the value of oil shale after mining or resource extraction and before processing, as determined by the BLM. The 1983 proposed rule was published on February 11, 1983 (48 FR 6510). The 1983 proposed rule provided that “the derivation methodology for this value shall be announced prior to the solicitation of bids.” The proposed rule further stated that “the royalty rate shall, to the extent practicable, not be levied on any value added by the production process after the point of resource extraction.” It would be unreasonable to adopt such a proposal today, due to the changes in extraction methodology (in situ versus ex situ). It would also be challenging to develop a fair and transparent process to calculate the royalty equivalent in today's economic environment, and no values were assigned to the mined or unprocessed rock and tonnage in the 1983 proposed rule. As noted, the 1983 proposed rule deferred the determination of those parameters to a later date.

In addition to ANPR comments received on royalty rates, the BLM looked at an initial 2 percent royalty to encourage production and a maximum 5 percent rate upon establishment of infrastructure. This method recognizes the high costs involved in producing shale oil. However, we dismissed this approach because of the difficulty involved in determining when necessary infrastructure is in place.

The BLM also considered the 8 percent royalty rate established by the State of Utah for state oil shale leases. It was determined that this rate represents the historic base royalty rate for solid fuel minerals on the State of Utah School and Institutional Trust Lands Administration lands—including asphaltic sands, uranium, and coal. To date, none of the state leases in Utah have been developed. Based on these facts, the BLM determined that there is not currently a sufficient basis for simply adopting the State of Utah's royalty rate for oil shale on Federal lands.

After examining the basis for setting rates, as suggested in the ANPR comments, the BLM determined that a flat 12.5 percent royalty rate for all future production may not allow oil shale to become competitive with traditional oil and gas development and therefore could be viewed as inconsistent with the requirements of EP Act. The BLM has decided to consider other alternatives in this proposed rule that may provide some additional incentive beyond that of a flat 12.5 percent royalty rate while also meeting the EP Act objective of providing a fair return to taxpayers.

Royalty Rate Alternatives Proposed for Further Consideration

As noted previously, we are not proposing a single royalty system in the proposed rule. Based on the information the BLM has reviewed to date and considering the unique challenge of trying to set a royalty rate on oil shale production in light of the many uncertainties regarding the economics and technology of a potential future oil shale industry, we are instead presenting two different royalty rate alternatives in the proposed rule text:

1. A flat 5 percent royalty rate; and

2. A 5 percent royalty rate on a specific volume of initial production beginning within a prescribed timeframe, with a 12.5 percent rate applied thereafter.

In addition, we are seeking comment on the appropriate parameters for a third option: A two-three tiered sliding scale royalty based on the market price of competing products (e.g., crude oil and natural gas). A further explanation of each of these proposals is presented below. We are requesting the public to comment on these specific options.

Option 1. Flat 5 Percent Royalty

Although mitigated somewhat by the much greater geographic concentration of oil shale resources, there is a significant difference between the energy value of oil shale and crude oil. On a per-pound basis, very high quality oil shale rock generates 4,300 Btu, coal generates an average of 10,600 Btu, while crude oil generates 19,000 Btu. Even wood has more heating capacity than oil shale rock, generating an average of 6,500 Btu. Applying the relative Btu value of oil shale to crude oil would result in a 2.6 percent royalty for oil shale. Using the same comparison to the royalty rate for underground coal would result in a 3.2 percent royalty rate for oil shale. In other words, it would require almost 5 times as much oil shale to produce the Btu value of crude oil and more than 2 times as much oil shale to produce the equivalent Btu value of coal.

The BLM looked at royalty rates on leases issued under Interior's 1973 Prototype Leasing Program. The prototype leases provided for royalties of $.12 per ton for oil shale with a quality of 30 gallons of oil per ton (30 g/t) with the addition of $.01 for every increase in gallon per ton of oil shale. In 1973, the average price of a barrel of oil was $3.89. At $.24 per ton of 42 g/t or one barrel/ton of oil shale, the royalty per barrel of oil would have been 5 percent. This rate is similar to the rate derived by comparing production costs to royalty rates as recommended by these proposed regulations.

The BLM also estimated what royalty rates for shale oil might be, based on comparisons of production costs for similar products. The cost of removing oil from shale rock is currently estimated to be two to three times higher than the current cost of producing conventional crude oil from onshore operations. The current estimated production cost for shale oil ranges from about $37.75-$65.21 a barrel. The production cost for conventional onshore crude is

approximately $19.50 a barrel.
2

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

2
Energy Information Administration, Crude Oil Production, dated July 3, 2008.
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 $18 per barrel.

Technology

Estimated shale
oil production
costs per barrel

Royalty calculation based on difference in production cost of a barrel of conventional oil versus shale oil

Adjusted
royalty for shale oil
(percent)

Surface mining
$44.24
$19.50/$44.24 = 44.07% × 12.5% = 5.51%
5.5

Underground mining
54.00
$19.50/$54 = 36.11% × 12.5% = 4.51%
4.5

Fracturing and heating in place
65.21
$19.50/$65.21 = 29.90% × 12.5% = 3.74%
3.75

Heating only in place
37.75
$19.50/$37.75 = 51.65% × 12.5% = 6.46%
6.5

Adjusting royalty rates based on higher anticipated production cost for oil from oil shale is not a new concept and is similar to the situation in the coal program where underground coal operations compete with surface coal operations, which have lower production costs. Congress addressed this disparity in production costs by allowing for different royalty rates for coal mined underground versus coal mined at the surface.

Please specifically comment on whether or not the anticipated costs of producing oil shale should be considered in establishing the royalty rate for all oil shale products and whether the BLM has chosen appropriate reference points for this production cost comparison.

Therefore, one alternative that considers the decreased energy content and increased production costs, while encouraging production and ensuring an appropriate return to the government is to set a flat royalty rate of 5%. This alternative assumes that oil shale will continue to be more expensive to produce for many years when compared to new conventional oil.

Option 2. A 5 Percent Royalty on Initial Production, With 12.5 Percent Thereafter

This alternative would provide a reduced royalty rate of 5% as a temporary incentive for early production of oil shale (similar to royalty incentives offered to spur initial Outer Continental Shelf (OCS) deepwater production), but with the standard 12.5% onshore oil and gas royalty rate applying to all oil shale production after a set timeframe and a set amount of production has taken place. Like the other royalty options, this option would require oil shale lessees to pay royalties on the amount or value of all products of oil shale that are sold from or transported off of the lease. This section would explain that the standard royalty rate for the products of oil shale is 12.5 percent of the amount or value of production. However, under this option, for leases that begin production of oil shale within 12 years of the issuance of the first oil shale commercial lease, the royalty rate would be 5 percent of the amount or value of production on the first 30 million barrels of oil equivalent produced.

The advantage of this alternative over a flat 5% royalty (Option 1) is that it provides a better return to taxpayers on later production if oil prices remain high and oil shale production becomes competitive with new conventional oil projects. At $60/barrel, this would amount to roughly $1.8 billion in production allowed per lease at the lower 5% royalty rate, providing roughly a $135 million in savings per lease compared to using the standard onshore oil and gas royalty rate of 12.5%.

One potential downside to this alternative is that offering royalty incentives without regard to oil prices increases the likelihood that, if oil prices remain high, the government will sacrifice revenue without affecting actual oil shale development. For example, at $120/barrel, the savings would be worth $270 million, even though oil shale operations would be more profitable than at oil prices of $60/barrel.

Therefore, we are also requesting comment on whether, if this proposal were adopted in the final rule, the temporary 5% royalty on initial production should also be conditioned on crude oil and natural gas prices (similar to OCS deepwater royalty incentives) and if so, what oil and gas price level would trigger payment at the higher 12.5% rate if prices exceeded the threshold. We would also like comments on the 12 year timeframe for reduced royalty.

Option 3. Sliding Scale Royalty Based on the Market Price of Oil

Two comments suggested a sliding scale royalty format. One comment specifically suggested a sliding scale royalty scheme based on a royalty schedule that varies with the price of conventional crude, as follows:

At $10 per barrel of conventional crude, the royalty rate should be zero;

At $15 per barrel, royalty should be 0.25 percent and should increase by 0.25 percent for every $5 per barrel increase up to $35 per barrel;

At $40 per barrel, the royalty rate should be 2 percent and should increase by 0.5 percent for every $5 per barrel increase in the price of conventional crude oil until the price of conventional crude reaches $100 per barrel; and

At $100 per barrel, royalty rate should be 8 percent and should remain at 8 percent at prices above $100 per barrel.

Another comment suggested two approaches to calculating royalty. The first part of the comment suggested that a simple way to accomplish royalty rates would be to index the value of barrels of oil equivalent to some percentage of NYMEX futures (say, 30 day average front month) prices. The commenter suggested that the index should be some fraction of the price, such as 50 to 65 percent. In the second part of the comment, the commenter suggested that, as an alternative to indexing, the BLM use a sliding royalty rate that is calculated on the difference between product price and the highest-cost production in the industry. The commenter cautioned that “there need to be provisions that deferred portions of the royalty do not reduce mineral lease payments to the States, if an escalating royalty rate is used.”

The BLM, in consultation with the MMS, evaluated these variable royalty options, but decided that as presented, they would be highly complex, and therefore, cumbersome to administer. With price volatility in the crude oil market, an intricate sliding scale royalty scheme could make enforcing compliance very difficult for the MMS. In addition, there is uncertainty about the types of products that would be derived from oil shale refining. Royalties based on oil shale quality would also be difficult for the BLM to administer when attempting to verify production quantities. For instance, if oil shale is extracted in an underground heating system, it would be extremely difficult for the BLM to determine how much oil or other product came from a particular volume or area of in-place oil shale.

While the BLM and MMS are concerned about the complexity of administering some of the proposed sliding scale royalty proposals, we recognize that there is some merit to the sliding scale concept, and in a simpler form, a sliding scale royalty may prove useful in meeting the dual goals of encouraging production and ensuring a fair return to taxpayers from future oil shale development.

One of the concerns that has been expressed regarding oil shale development is that potential oil shale developers may be reluctant to make the large upfront investments required for commercial operations if they believe there is a chance that crude oil prices might drop in the future below the point at which oil shale production would be profitable (i.e., competitive with new conventional oil production). A sliding scale royalty system could allow the government to at least partially mitigate this development risk by providing for a lower royalty rate if crude oil prices fall below a certain price threshold. The basic concept is that in return for the government accepting a greater share of the price risk that an operator faces when prices are low (in the form of a lower royalty), the government would receive a greater share of the rewards (through a higher royalty) when prices are high.

The BLM has not decided on the specific parameters of a sliding scale royalty system, but is considering a simplified, two- or three-tiered system based on the current royalty rates already in effect for conventional fuel minerals and with a 5 percent royalty rate (Option 1) representing the first tier. The applicable royalty rate would be determined based on market prices of competing products (e.g., crude oil and natural gas) over a certain time period. If prices remain below a certain point during the applicable period, the royalty rate on oil shale products would be 5 percent for that period. If prices are above that range for the period, a higher royalty would be charged. In a three-tiered system, a third royalty rate would apply if prices rise above a second price threshold during the applicable period.

The BLM seeks comment on the specific parameters that could be applied to a sliding scale royalty system, should the BLM choose to adopt such a system in the final rule. More specifically, the BLM would like feedback on the following questions:

1. Should a sliding scale system include two or three tiers? Assuming a 5 percent royalty for the first tier, what would be appropriate royalty rates for the second and/or third tiers?

2. What are appropriate price thresholds to apply to each tier? Should the thresholds be fixed (in real dollar terms), or should they float relative to a published index?

3. Should the sliding scale apply to all products, or should nonfuel products pay a traditional flat rate?

4. Are there other ways to simplify a sliding scale royalty to reduce the administrative costs for BLM, MMS, and producers?

Under a sliding scale system, if prices fall below the lower range, producers would have a “safety net” in the form of the lower 5% royalty rate. Whether or not the lower royalty kicks in at some point, simply having it in place provides some added certainty for investors that would help encourage oil shale production. In return for this “safety net” that conventional oil and gas producers do not enjoy, oil shale producers would be required to pay a higher royalty rate(s) when crude oil and/or natural gas prices are high (and where oil shale is expected to be substantially more profitable).

There are a couple of advantages of this alternative. It reduces the risk for oil shale operators that oil prices might fall below the point that continued oil shale production would be economic. However, it also ensures an improved return to the government if prices remain within one of the higher expected ranges at which oil shale may be profitable. One disadvantage is that taxpayers accept a greater risk of lower returns if prices fall and remain well below the lowest threshold. However, with the lowest royalty rate step set at 5 percent, this risk is no greater than under a flat 5 percent royalty system (Option #1).

Other Royalty Issues

The BLM also received 5 comments specific to the royalty point of determination. Two of the comments suggested that royalty should be determined “at the point at which the oil product exits a process facility in a marketable state.” One comment suggested that “the point of royalty determination be at the earliest point of liquid or gaseous product marketability.” Another comment suggested that “the oil produced should be measured at the point at which the oil product exits a processing facility in a marketable state.” The last comment did not provide a specific suggestion; rather, it stated that the 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, under the proposed rule the royalty would be assessed on all products of oil shale that are sold from or transported off of the lease. This proposed point of royalty determination is similar to points of royalty determination for other Interior Department minerals programs.

The BLM received three ANPR comments relating to the oil shale research, development, and demonstration (R, D and D) program. One comment encouraged the BLM to “continue the existing BLM R, D and D leasing program for access to oil shale for companies wishing to test unproven technologies.” Another comment suggested that the BLM “should let several ‘boutique’ small companies with large R, D and D budgets to develop a small number of sites,” on the condition that those companies “would have to agree to allow their findings to be shared.” The last comment specifically requested that the “commercial leasing regulations make clear that the BLM will not hold a commercial lease sale for Federal oil shale resources until successful technologies have been developed and demonstrated on R, D and D leases.” These proposed regulations do not address the first comment. The Secretary has discretion under the EP Act to offer additional tracts for R, D and D leasing. These regulations do not decide whether additional R, D and D leasing is necessary. Although the BLM could require that proprietary information be made public as a condition of further R, D and D leasing, we believe that the industry would not be interested in leasing under such conditions.

Furthermore, as previously explained, these regulations do not address any new R, D and D leases. The BLM could not incorporate the third comment, because it suggested a limitation that is inconsistent with the terms of the EP Act. Sections 369(c) and 369(e) of the EP Act authorize the commercial leasing of oil shale following promulgation of regulations and consultation with interested parties without the limitations sought by the comment.

Finally, it is important to note that the proposed rule allows the Federal Government to readjust royalty rates on leases after the first 20-year term.

Currently, there is no oil shale industry and the oil shale extractive technology is still in its rudimentary stages; as such, commercial oil shale 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. Please specifically comment on the time necessary to develop an oil shale industry.

The BLM is proposing alternatives for the royalty rate and the products on which the royalties will be collected. The BLM anticipates selecting one of these alternatives, or based on public comment and further analysis, variations on these alternatives in the final rule in order to provide predictability for the industry and ease of administration both for the United States and for payers. 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 would predominantly sell from its leases mined 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 would develop that would provide FMV pricing for products of oil shale. Therefore, the MMS will promulgate royalty valuation regulations before oil shale leases are required to begin paying production royalties under this 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. For example, the MMS could promulgate regulations similar to the current Federal oil valuation regulation to value crude oil produced from oil shale. Under this 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.

Royalties would not be payable 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 requirements as provided in the lease or in an approved plan of development.

The Department seeks comments on what future royalty valuation regulations need to contain. In particular, the Department is seeking 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 also seeks comments on alternative approaches to valuation and royalty rates.

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 (EIA's 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 price as a critical variable determining a project's economic viability. Under EIA's 2007 low oil price projection 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.

Section 3903.53 would require the filing of documentation of all overriding royalties associated with a lease and would require that the filing must occur within 90 days of the date of execution of the assignment. This section is similar to that of the BLM's other mineral leasing programs.

Section 3903.54 would contain the requirements for filing an application for waiver, suspension, or reduction of rental or payment 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. This section is similar to the BLM's coal leasing regulations and similarly includes a case-by-case processing fee under 43 CFR 3000.11.

Section 3903.60 would provide that late payments or underpayment charges would be assessed under MMS regulations at 30 CFR 218.202.

Subpart 3904—Bonds and Trust Funds

Sections in this subpart would 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 collateral for personal 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 would be similar to the regulatory provisions in the BLM's other mineral leasing programs. The bonding requirements in this rule are consistent with the bonding

requirements under the BLM's mining law program. Both programs require that bonds cover the full cost of reclamation. Both programs also 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. Sections of this subpart would establish that the BLM would require two types of bonds; a lease or exploration license bond and a reclamation bond. This subpart would also explain that reclamation bonds would 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 would provide that prior to lease or an exploration license issuance, the BLM would require 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. The bond would be required to 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 would also require the lessee or operator to file a reclamation bond to cover all costs the BLM estimates would be necessary to cover reclamation on a lease. This is similar to the requirement found in other BLM mineral regulations.

Section 3904.11 would require the lessee or operator to file a lease bond prior to issuance of a lease, file a reclamation bond prior to approval of a plan of development, 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.

Section 3904.12 would require that a copy of the bond with original signatures be filed in the proper BLM office and section 3904.13 would describe the different types of bonds that the BLM would accept. These sections are similar to the bonding regulations in other BLM mineral leasing programs.

Section 3904.13 would address the types of personal and surety bonds the BLM would accept. Personal bonds would be limited to pledges of cash, cashier's check, certified check, or U.S. Treasury bond. The BLM state offices would list qualified sureties for bonds.

Section 3904.14 would provide that the BLM will establish bond amounts on a case-by-case basis. These regulations would set the minimum lease bond amount at $25,000. Although the minimum lease bond amount is greater than that required in other BLM mineral leasing programs, the BLM believes that it is justified because the potential liability may be greater and there are still some unknowns. Reclamation and exploration bond amounts would 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 would be covered.

This section would provide 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 would avoid 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.

Section 3904.15 would explain that under this proposed rule 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 proposed regulations. This section would also explain that the BLM would not decrease the bond amount below the minimum established in section 3904.14(a). This section would require the lessee or operator to submit a revised cost estimate of the reclamation costs to the BLM every three years after reclamation bond approval. If the current bond would 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.

Section 3904.20 would describe what actions the BLM would 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 would require 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 would allow 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 or until all of the terms and conditions of the license or lease have been fulfilled. Termination of the period of liability of a bond would end the period during which obligations continue to accrue, but would not relieve the surety of the responsibility for obligations that accrued during the period of liability.

Section 3904.40 would establish 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 plan of development;

(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 plan of development or later as a result of further inspections or reviews of the operations.

Subpart 3905—Lease Exchanges

This subpart would allow the BLM to approve oil shale lease exchanges.

Section 3905.10 would explain that the BLM would 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 would be governed by the regulations under 43 CFR part 2200. Section 206 of FLPMA

authorizes land exchanges of interests in Federal lands for non-Federal lands (43 U.S.C. 1716).

Part 3910—Oil Shale Exploration Licenses

The regulations proposed under this part would address exploration licenses. An exploration license would allow a licensee to enter the Federal land covered by an exploration license and explore for minerals, but it would not authorize the licensee to extract any minerals, except for experimental or demonstration purposes. Since regulatory provisions for the issuance and approval of exploration licenses are common to the BLM mineral leasing programs, this part would contain similar regulatory provisions, particularly with respect to:

(1) Lands that are subject to exploration (section 3910.21);

(2) Lands managed by agencies other than the BLM (section 3910.22);

(3) Requirements for conducting exploration activities (section 3910.23);

(4) Application procedures (section 3910.31);

(5) Environmental analysis (section 3910.32);

(6) License requirements (section 3910.40);

(7) Issuance, modification, relinquishment, termination, and cancellation (section 3910.41);

(8) Limitations on exploration licenses (section 3910.42);

(9) Collection and submission of data (section 3910.44); and

(10) Surface use (section 3910.50).

Section 3910.21 would authorize 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 would make it clear that the consent and consultation procedures under section 3900.61 that apply to leases also apply to exploration licenses. The BLM would issue these 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 regulations requiring consent and consultation for exploration licenses.

Section 3910.23 would require the operator to have a lease or license before conducting any exploration activities on Federal lands. This section would also allow 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.

Section 3910.31 would identify specific requirements for filing an application for an exploration license. Application requirements under this section would 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 would establish 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 which provide for exploration licenses, there would be no required application form. The $295 filing fee for an exploration license is based on the current filing fee for a coal exploration license. The BLM anticipates that the time required to process an oil shale exploration license would be similar to that for a coal exploration license, and therefore believes the same filing fee is justified.

Section 3910.32 would require the BLM to perform the appropriate NEPA analysis before issuing an exploration license. The section also explains that the BLM would include in an exploration license terms and conditions to mitigate impacts to the environment analyzed in a NEPA document and to protect Federal resource values of the area and to ensure reclamation of the lands disturbed by exploration activities.

Section 3910.40 would provide that a licensee must comply with all applicable Federal laws and regulations and 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.

Section 3910.41 would explain 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 would be 2 years. The requirements proposed here for oil shale exploration licenses are similar to existing requirements in regulations relating to exploration licenses in other BLM minerals programs, particularly coal.

Section 3910.42 would provide that issuance of an exploration license would not preclude the issuance of a Federal oil shale lease for the same area. This section would also make it clear that if an oil shale lease is issued for an area covered by an exploration license, the BLM would cancel the exploration license effective the date of lease issuance.

Section 3910.44 would address collection and submission of data relating to an exploration license and would include provisions relating to confidentiality of data. This section is similar to provisions in other BLM minerals programs.

Section 3910.50 would address the issue of surface damage resulting from exploration operations and would require 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 proposed oil shale leasing program would be 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, the BLM is proposing a 2-step process that would begin 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 would facilitate 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 would contain regulatory provisions relating to pre-leasing activities. Many of the sections would be similar to existing provisions of other BLM mineral leasing programs, particularly coal.

Section 3921.10 would explain that a BLM State Director may announce in the
Federal Register
a call for

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 regulations at 40 CFR parts 1500 through 1508 and Department of the Interior methods and procedures developed pursuant to NEPA.

Section 3921.30 would provide that the notice announcing calls for expressions of leasing interest would be published in the
Federal Register
and in at least 1 newspaper of general circulation in the affected state. The notice would allow a minimum of 30 days to submit expressions of leasing interest, including a legal land description and other specified information.

Section 3921.40 would require 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 proposed rule in response to discussion at the three listening sessions with the governors' representatives.

Section 3921.50 would explain that after analyzing expressions of leasing interest, the BLM would determine a geographic area for receiving applications to lease. This section would also explain that the BLM may add lands to those areas identified by the public in the expressions of leasing interest.

Under proposed section 3921.60, the BLM's call for applications would be published in the
Federal Register
and would identify the geographic area available for application under proposed subpart 3922. Under this section, the public would have at least 90 days to submit applications for lease.

Subpart 3922—Application Processing

The sections under this subpart would contain regulatory provisions relating to application requirements, including:

(1) A nonrefundable case-by-case processing fee (section 3922.10);

(2) Content of application (section 3922.20);

(3) Additional information (section 3922.30); and

(4) Tract delineation (section 3922.40).

These provisions are similar to existing regulations of other BLM mineral leasing programs.

Section 3922.10 would require 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 would provide that the applicant who nominates a tract will pay to the BLM the processing costs that the BLM incurs up to the publication of the competitive lease sale notice. That fee amount would be included 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 would be required to submit an application under section 3922.20 within 30 days after the lease sale and would 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 would also be responsible for any processing costs the BLM incurs after the date of the sale notice. If there is no successful bidder, the applicant would be responsible for processing costs, and there would 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 would 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 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 would 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 would be responsible for paying for the cost of that NEPA analysis and any additional NEPA analysis that would be necessary.

It should be noted that an applicant would 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 is proposing adopting case-by-case processing fees for applications that would 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 would 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 Environmental Impact Statements (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.

Section 3922.20 would identify specific information that an applicant would be 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. The NEPA

compliance documents at this stage in the leasing process are necessary because the PEIS addresses land use planning decisions and not leasing decisions and was unable to anticipate with any certainty the effects of oil shale leasing development due to the newness of the industry.

The possible oil shale development technologies are very different from conventional mining methods associated with other BLM minerals programs, as are the impacts associated with each. The technologies are yet to be proven, or commercially viable and their associated impacts are unknown. Because the BLM is presently uncertain of the mining methods (and associated impacts) that may be used for oil shale development, additional NEPA analysis will be performed during the application and leasing process. When required by applicable law, the BLM will conduct site-specific NEPA analysis, including a period of public review, to evaluate the impacts on known resource values on the lands in any application. Although no specific form is required, information the applicant would be 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 would 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.

Section 3922.30 would provide that the BLM could request additional information from the applicant, and explain 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 greatly impact the BLM's decision to proceed with a lease sale.

Section 3922.40 would make 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 would also clarify 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 would implement 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 a FMV for leasing its minerals. Also, Section 369(o) of the EP Act which requires that payments for leases under that section must ensure a fair return to the United States. Under section 3924.10 of the proposed rule, the BLM sales panel would determine 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, among other things, the geology, market conditions, mining methods, and industry economics.

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 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, but the vast quantities of oil shale within the Federal acreage 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 would set a minimum bid of $1,000 per acre, but the BLM invites comments supporting reasonable alternative minimum bid amounts.

Subpart 3924—Lease Sale Procedures

Provisions of this subpart would identify the process by which tracts of land would be made available for competitive lease sale. The BLM proposes to lease oil shale through a competitive bidding leasing procedure that would mirror competitive lease sales procedures currently in place for other solid minerals leasing programs, particularly coal.

Section 3924.5 would detail 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 would be 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.

Section 3924.10 would detail competitive lease sale procedures, including receipt and opening of sealed bids, submission of the 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 would also address the actions of the sale 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 is proposing to adopt this process because it has been successful in these other mineral leasing programs and because we believe this process is appropriate for oil shale leasing.

The BLM will rely on the appraisal process to estimate the fair market value (FMV) for commercial oil shale leases under the proposed regulations. 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 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 in 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 property such as mineral leases.

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 value of comparable competitive properties. When reliable comparable sales data are available, it generally is 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 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 would 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.

In the ANPR, the BLM solicited public input on the process for bid adequacy evaluation and minimum acceptable lease bonus bid. The BLM's purpose for requesting comments on the FMV it should receive for lease tracts was to solicit ideas on how FMV would be determined for a resource that has little or no history of comparable sales.

The public comments received were primarily concerned with the need to receive an appropriate value for the lease. The BLM received comments from 6 entities related to this question, specifically mentioning that: a FMV determination needs to reflect private sector valuations; competitive bidding should establish a lease's FMV; the process for establishing FMV should be modeled after the Federal coal leasing program; bonus payments are needed to stop speculation; and sealed bidding ensures the most competitive bonus bid. The comments also posed arguments for and against using a minimum acceptable bonus bid. In addition, the BLM received comments that bonus bids should be high and suggested that the 1974 bonus bid amounts pertaining to 4 oil shale leases that were offered in Colorado and Utah, with bonus bids that ranged from $74 million to $210 million, were indicative of expected bonus bid amounts.

In response to the ANPR comments and other considerations, the BLM proposes to establish oil shale lease FMV using a process similar to that used in the Federal coal leasing program. This proposed process relies on the appraisal process in an attempt to estimate the market value for those leases. As such, the proposed 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 proposed rule, utilize competitive bidding, specifically sealed bidding, for determining who receives the lease.

In the rule, the BLM is proposing to establish 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 value to limit or dissuade nuisance bids. The proposed rule requires a minimum acceptable bonus bid of $1,000 per acre. The assumption is that such an amount will not exceed FMV or be a deterrent to companies interested in bidding for the lease tracts. At the same time, the BLM has requested further comments on the value proposed.

As per comments on specific values, the proposed rule does not attempt to establish actual FMV for future Federal oil shale leases. Values received in the 1970's may not be an accurate indicator for future values.

Subpart 3925—Award of Lease

Section 3925.10 would provide that the lease would ordinarily be awarded to the qualified bidder submitting the highest bid which exceeds the minimum bid amount. It 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.

Subpart 3926—Conversion of Preference Right for Research, Demonstration, and Development Leases

Section 3926.10 would provide application procedures or requirements to convert R, D and D leases and preference rights acreages to commercial leases. Under this section, a lessee of any of the R, D and D lease would be 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 had 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 contiguous acreage of 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 would be required to demonstrate to the BLM that the technology tested in the original lease would have the ability to produce shale oil in commercial quantities. In addition, the lessee, as required in R, D and D leases, would be 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 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.

The BLM would approve the conversion application, in whole or in part, if it determined that:

(1) There have been commercial quantities produced from the lease;

(2) The bid payment for the lease met or exceeded 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 provided is consistent with section 3904.14; and

(5) Commercial scale operations can be conducted, subject to mitigation measures to be specified in stipulations or regulations, without unacceptable environmental consequences.

Subpart 3927—Lease Terms

Sections in this subpart would address lease form, lease size, lease duration, dating of leases, diligent development, and production.

Section 3927.10 would provide that the BLM would 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 would set the maximum oil shale lease size at 5,760 acres, which is the maximum size authorized under Section 369(j) of the EP Act. Several comments received in response to the BLM's ANPR included lease size recommendations varying from 500 acres to 10 square miles as the appropriate maximum lease size. Of those comments, one commenter supported a maximum lease size of 5,760 acres, which is consistent with the EP Act. One commenter stated that “Leases need to be large enough to encourage development yet not outlandishly large to allow for speculation.” 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).

Although the EP Act does not establish a minimum lease size, in keeping with the size restrictions of the oil shale R, D and D leases, section 3927.20 would also establish 160 acres as the minimum size of an oil shale lease. The BLM received several comments relating to whether the BLM's commercial oil shale leasing regulations should include provisions for small tract leasing, all of which generally were in favor of making small lease tracts available. One comment suggested that smaller tracts would be particularly appropriate in the early years of the commercial leasing program in light of new technologies, and it recommended a minimum tract size of 1,280 acres. Recommendations relating to a minimum tract size stated in other comments ranged from over 320 acres to one square mile. Two comments suggested that there should be restrictions for small tract leasing. Of those comments, one commenter stated that small tract leasing should not be a mechanism to thwart potential development. Another commenter recommended that small tracts should only be allowed in cases where “the tracts have been orphaned, in between larger leases, basin edge or other fee-owned lands.” Although section 3927.20 would not formally establish small tract leasing, the 160-acre minimum lease size set by this section would provide a lessee the opportunity to develop a relatively small-scale leasehold, identical to the lease size authorized under the BLM's oil shale R, D and D program. Thus, rather than the BLM incorporating small tract leasing as a separate component of the commercial oil shale leasing program, establishing a minimum lease size of 160 acres provides an opportunity for a lessee to utilize a preferred technology on a relatively small tract that is consistent with the size of existing R, D and D leases. For this reason, the BLM did not adopt ANPR comments that recommended a larger minimum lease size. With respect to the comment expressing concern that small tract leasing could thwart potential development and the comment recommending that small tract leasing should be allowed only in limited situations as stated above, it is the policy of the BLM, when delineating tracts to be offered through competitive lease sale, to make efforts to ensure that the configuration of any small acreage tracts would likely promote development of oil shale. The BLM believes that configuration of tracts in this manner would not impede development on any existing oil shale leases located in the vicinity of smaller tracts. As is the case in other BLM mineral leasing programs, the tract delineation process for a competitive lease sale includes the gathering of detailed information on tracts and conducting various analyses. Because the steps customarily included in the tract delineation process are designed to promote or encourage development of mineral resources, the BLM maintains that establishing a minimum lease size of 160 acres will not thwart potential development of oil shale resources. Likewise, the competitive leasing process and the required minimum bonus bids would discourage speculation.

One comment endorsing small tract leasing also recommended that a small tract lease should include a preference right for additional adjoining acreage. The BLM is not adopting this recommendation since it maintains that the concept of a preference right for the future leasing of additional acreage—a key component of the R, D and D leasing program—is not a necessary provision in a commercial leasing program in light of lease modification provisions under proposed subpart 3932. In the event that a lessee of a small tract has interest in obtaining additional acreage adjacent to its lease, under the proposed rule the lessee could apply for a lease modification to include Federal lands adjacent to the lease, but not to exceed the maximum lease size (see section 3932.10).

Two comments received in response to the ANPR contained recommendations relating to consolidation of leases into larger development units. One of the comments suggested that oil shale commercial leasing regulations should include a provision to allow for consolidation of multiple contiguous leases for individual leaseholders as long as there remains one operator. The BLM interprets these comments as a recommendation to establish a mechanism similar to a logical mining unit that exists in BLM's coal leasing program. As defined in the coal leasing regulations at 43 CFR 3480(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.” Due to the fact that the commercial oil shale leasing regulations proposed here today are aimed at establishing a new mineral leasing program; a program that does not have any history of oil shale development in the U.S., does not require any standardized extraction methods, and also adopts different diligence requirements than those of the coal leasing program, it is the BLM's position that establishing a mechanism similar to a LMU is not warranted at this time. After the promulgation of final regulations and after the oil shale industry is more well-established, if the BLM determines that the creation of a mechanism similar to an LMU is

warranted, then the BLM would pursue rulemaking to adopt this recommendation. Please specifically comment on whether or not the final rule should include provisions for the establishment of LMUs for oil shale leases.

Section 3927.30 would provide 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 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.

Section 3927.40 would identify 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.

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.

Section 3927.50 would require 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.

Part 3930—Management of Oil Shale Exploration Licenses and Leases

Sections in this part would address the requirements for exploration and leases, including general performance standards, operations, diligent development milestones, plans of development and exploration plans, lease modifications and readjustments, assignments and subleases, relinquishments, cancellations and terminations, post-mining and development hazards, production and sale records, and inspection and enforcement.

Sections 3930.10 through 3930.13 would explain the performance standards for exploration, development, production, and the preparation and the 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 of 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 would establish the various standard operating requirements associated with development of an oil shale lease, including requirements concerning the maximum economic recovery (MER) of the resource, how to report new geologic information, and compliance with Federal laws. The section would also address disposal and treatment of solid wastes. This section provides operational requirements that are common to other BLM mineral leasing programs.

The BLM received 6 comments regarding diligent development in response to the ANPR. The comments received primarily expressed the view that diligent development requirements are necessary to prevent speculation, but that they should not be so onerous as to prevent investment in oil shale development. Most of the comments concerning the diligence provisions were related to either plan of development requirements or production requirements and requiring payment of a minimum royalty in lieu of production. The comments received suggested:

(1) Making diligence a requirement of operations;

(2) Not starting the diligence requirement until after the needed infrastructure is in place;

(3) Requiring submittal of a plan of development;

(4) Staging the permitting process to essentially define diligence as accomplishing necessary sequential steps in the development process;

(5) Escalating minimum royalty;

(6) Requiring minimum production levels; and

(7) Requiring production of a percentage of the resource base.

The BLM incorporated the following commenter's suggestions into the proposed rule:

(1) Diligent development and staged development requirements (section 3930.30 (a));

(2) Requirements for a plan of development (section 3930.30(a)(1)); and

(3) Requirements for minimum production (section 3930.30(d)).

The BLM's proposed diligent development requirements are based on fulfilling tasks necessary to reach production, such as applying for permits, submitting plans of development, and installing needed infrastructure within specified timeframes. Comments related to basing diligence on production of a percentage of the reserve base were considered, but rejected based on the difficulty of administering such a scheme with varying technologies, recovery rates, and shale characteristics. The comment regarding infrastructure was incorporated into the proposed rule as a diligence development step towards production.

Section 3930.30 would list the milestones for diligent development of an oil shale lease. The requirement for establishing miles

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3AE8-16275. Public record. Not legal advice.