# Oil Shale Management-General > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3AE8-27025 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** November 18, 2008 - **Citation:** 73 FR 69414 ## Text DEPARTMENT OF THE INTERIOR Bureau of Land Management 43 CFR Parts 3900, 3910, 3920, and 3930 [LLWO-3200000 L13100000.PP0000 L.X.EM OSHL000.241A] RIN 1004-AD90 Oil Shale Management—General AGENCY: Bureau of Land Management, Interior. ACTION: Final rule. SUMMARY: The Bureau of Land Management (BLM) is finalizing regulations to set out the policies and procedures for the implementation of a commercial leasing program for the management of federally-owned oil shale and any associated minerals located on Federal lands. The Energy Policy Act of 2005 (EP Act) directs the Secretary of the Interior (Secretary) to: Make public lands available for conducting oil shale research and development activities; Complete a Programmatic Environmental Impact Statement (PEIS) for a commercial leasing program for both oil shale and tar sands resources on the BLM-administered lands in Colorado, Utah, and Wyoming; and Issue regulations establishing a commercial oil shale leasing program. These final regulations incorporate specific provisions of the Mineral Leasing Act of 1920 (MLA) and the EP Act relating to: Oil shale lease size; Acreage limitations; Rental; and Lease diligence. These regulations also address the diligent development requirements of the EP Act by establishing work requirements and milestones to ensure diligent development of leases. The rule also provides for other standard components of a BLM mineral leasing program, including lease administration and operations. DATES: This rule is effective on January 17, 2009. ADDRESSES: You may send inquiries or suggestions to Director (320), Bureau of Land Management, 1620 L Street, NW., Room 501, Washington, DC 20036, Attention: RIN-AD90. FOR FURTHER INFORMATION CONTACT: Mitchell Leverette, Chief, Division of Solid Minerals at (202) 452-5088 for issues related to the BLM's commercial oil shale leasing program or Kelly Odom at (202) 452-5028 for regulatory process issues. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339, 24 hours a day, 7 days a week, to leave a message or question with the above individuals. You will receive a reply during normal business hours. SUPPLEMENTARY INFORMATION: I. Background II. Final Rule as Adopted and Response to Comments III. Procedural Matters I. Background These regulations implement the EP Act (42 U.S.C. 15927), which became law on August 8, 2005. Section 369 of the EP Act addresses oil shale development and authorizes the Secretary to establish regulations for a commercial leasing program. The MLA of 1920 (30 U.S.C. 241(a)) provides the authority for the BLM to allow for the exploration, development, and utilization of oil shale resources on the BLM-managed public lands. Additional statutory authorities for these regulations are: (1) The Mineral Leasing Act for Acquired Lands of 1947 (30 U.S.C. 351-359); and (2) The Federal Land Policy and Management Act (FLPMA) of 1976 (43 U.S.C. 1701 et seq. , including 43 U.S.C. 1732).\ Oil shale is a fine-grained sedimentary rock containing organic matter from which shale oil may be produced. Oil shale is a marlstone and contains no oil; rather, it contains un-decayed algae called kerogen (not oil). In fact, the word kerogen is a Greek word interpreted to mean “to produce wax”—“kero” (wax), “gen” to produce. The waxy substance produced from oil shale rock is not the same as conventional crude oil. The kerogen only has a market value as an energy source after it has been refined and converted to synthetic crude oil. Oil shale is a solid rock and must be mined or treated in place to release the kerogen from the rock. Energy companies and petroleum researchers have, over the past 60 years, developed and tested a variety of technologies on a small scale for recovering shale oil from oil shale and processing it to produce fuels and by-products. Both surface processing and in-situ technologies have been examined. Generally, surface processing consists of three major steps: (1) Oil shale mining and ore preparation; (2) processing of oil shale to produce kerogen oil; and (3) processing kerogen oil to produce refinery feedstock and high-value chemicals. This sequence is illustrated below. Conversion of Oil Shale to Products (Surface Process) Resource → Ore Mi ning → Retorting → Oil Upgrading → Fuel and Chemical Markets For deeper, thicker deposits, not as amenable to surface- or deep-mining methods, the shale oil can be produced by in-situ technology. In-situ processes minimize or, in the case of true in-situ, eliminate the need for mining and surface processes by heating the resource in its natural depositional setting. This sequence is illustrated below. Conversion of Oil Shale to Products (True In-Situ Process) Resource → In-Situ Processing → Oil Upgrading → Fuel and Chemical Markets The American Association of Petroleum Geologists estimates that the total world oil shale resources contain the equivalent of 2.6 trillion barrels of oil. According to estimates by the U.S. Geological Survey, the United States holds more than 50 percent of the world's oil shale resources. The largest known deposits of oil shale in the world are located in a 16,000 square mile area in the Green River formation in Colorado, Utah, and Wyoming (underlying the Piceance, Uinta, Green River, and Washakie Basins), which is estimated to contain the equivalent of between 1.5 and 1.8 trillion barrels of oil. Federal lands comprise 72 percent of the total surface of oil shale acreage and 82 percent of the oil shale resources in the Green River formation. BLM Oil Shale Initiatives Since 1973 In 1973, four leases were issued in the oil shale prototype leasing program. During the 1973-74 oil shale prototype program there were expectations of an economic boom in western Colorado which never materialized. The oil shale industry collapsed on May 2, 1982, commonly referred to as Black Sunday. In 1983, the BLM established an Oil Shale Task Force to address: (1) Access to unconventional energy resources (such as oil shale) on public lands; (2) Impediments to oil shale development on public lands; (3) Industry interest in research and development and commercial opportunities on public lands; and (4) Secretarial options to capitalize on these opportunities. On February 11, 1983, the BLM published a proposed rule for an oil shale leasing program (48 FR 6510). Due to apparent lack of interest in the development of oil shale, the BLM withdrew the proposed rule, effective September 25, 1985 (50 FR 38867). In order to be better able to expand and diversify domestic energy production, on November 22, 2004, the BLM published a notice in the Federal Register (69 FR 67935) requesting public comments on the potential for oil shale development within the Piceance Creek Basin in Colorado, the Uinta Basin in Utah, and the Green River and Washakie Basins in Wyoming. The Federal Register notice also requested comments on a proposed draft oil shale Research, Development, and Demonstration (R, D and D) lease form. Comments received were incorporated, as appropriate, into the final R, D and D lease form. On June 9, 2005, the BLM published a notice in the Federal Register (70 FR 33753), which initiated a R, D and D leasing program by soliciting nominations of 160-acre parcels of public land to be leased in Colorado, Utah, and Wyoming for conducting oil shale recovery technologies. In response to the 19 nominations of parcels received, the BLM issued 6 R, D and D leases—5 in Colorado that were effective January 1, 2007, and an additional R, D and D lease in Utah that was effective on July 1, 2007. Each of the R, D and D leases contain a preference right for conversion to a commercial lease of additional acreage upon demonstration of a successful method of producing oil from shale rock. One of the purposes of the R, D and D leases, as stated in the notice, was to provide the BLM, state and local governments, and the public with important information that could be utilized as the BLM works with communities, states, and other Federal agencies to develop strategies for managing the environmental effects of production. The R, D and D lease form was published as an attachment (Appendix A) to the June 9, 2005, Federal Register notice. The PEIS and National Environmental Policy Act (NEPA) Compliance On December 13, 2005, the BLM published in the Federal Register a notice of intent (NOI) to prepare a PEIS (70 FR 73791) for oil shale and tar sands resources leasing on lands administered by the BLM in Colorado, Utah, and Wyoming. The NOI alerted the public that the BLM was intending to amend several resource management plans (RMPs) to make lands available for oil shale and tar sands resources leasing in Colorado, Utah, and Wyoming. The NOI also informed the public of the development of the oil shale regulations required by Section 369(d)(2) of the EP Act. The RMPs are BLM planning documents prepared under Section 202 of FLPMA that present guidelines for making resource management decisions. The draft PEIS evaluated the following RMPs for possible amendment: (1) Wyoming: Green River, Great Divide, and Kemmerer; (2) Utah: Price River, San Juan, San Rafael, Henry Mountain, Book Cliffs, and Diamond Mountain; and (3) Colorado: Grand Junction, White River, and Glenwood Springs. Although the PEIS covers planning for tar sands, these regulations do not address tar sands leasing since the BLM has regulations in place that address tar sands leasing (see 43 CFR part 3140). On December 21, 2007, the BLM published the notice of availability (NOA) for the draft PEIS and made the draft PEIS available for public comment (72 FR 72751). On September 5, 2008, the BLM published a NOA announcing the availability of the final PEIS (73 FR 51838). The PEIS is primarily intended to analyze the impacts of land use allocation and not site-specific oil shale leasing. The Record of Decision (ROD) has not yet been signed. The ROD will describe and approve the BLM's proposal to amend 12 RMPs to identify the most geologically prospective public lands in Colorado, Utah, and Wyoming for oil shale and tar sands resources, and to designate certain of these lands as available for application for commercial leasing and future exploration and development of these resources. Advance Notice of Proposed Rulemaking The BLM recognized that the creation of the rules governing the development of oil shale would need to address different possible technologies that have different associated impacts and costs. Therefore, to increase public participation and to aid in the development of oil shale regulations, the BLM published in the Federal Register an advance notice of proposed rulemaking (ANPR) (71 FR 50378) on August 25, 2006. The ANPR requested public comments on the following five key components of the proposed regulations: (1) What should be the royalty rate and point of royalty determination? (2) Should the regulations establish a process for bid adequacy evaluation, i.e., Fair Market Value (FMV) determination, or should the regulations establish a minimum acceptable lease bonus bid? (3) How should diligent development be determined? (4) What should be the minimum production requirement? (5) Should there be provisions for small tract leasing? On September 26, 2006, the BLM published a Federal Register notice reopening the comment period for the ANPR and extending the comment period until October 25, 2006 (71 FR 56085). In response to the ANPR, the BLM received 48 comments. Comments were received from individuals, public interest groups, and industry representatives. Although the ANPR focused on the 5 areas previously identified, commenters addressed a variety of topics, including whether or not they were supportive of a commercial oil shale leasing program. The BLM considered the ANPR comments in drafting the proposed and final rules. Listening Sessions With Governor's Representatives From Colorado, Utah, and Wyoming The BLM, in coordination with the Minerals Management Service (MMS), held three “listening sessions” with representatives of the governors of the States of Colorado, Utah, and Wyoming. The BLM and the MMS met with these representatives in Denver, Colorado (December 14, 2006), Salt Lake City, Utah (April 26, 2007), and Cheyenne, Wyoming (August 8, 2007). The purpose of the listening sessions was to provide the governors' representatives the opportunity to share their ideas, issues, and concerns relating to the proposed commercial oil shale leasing regulations. Section 369(e) of the EP Act requires the Department of the Interior (Department) to consult with the governors of Colorado, Utah, and Wyoming, representatives of local governments, interested Indian tribes, and the public to determine the level of support for conducting oil shale lease sales. The BLM plans to consult with the affected states prior to conducting the first oil shale lease sale, and following publication of this rule. On July 23, 2008, the BLM published in the Federal Register a proposed rule entitled Oil Shale Management—General (73 FR 42926). The comment period on the rule closed on September 22, 2008. The BLM received over 75,000 comment letters on the proposed rule from individuals, Federal and state governments and agencies, interest groups, and industry representatives. Substantive comments on the proposed rule are discussed in this preamble in the section discussions of this rule. If we received no substantive comment on a particular section of the rule, that section remains as proposed. II. Final Rule as Adopted and Response to Comments Part 3900—Oil Shale Management—General This part contains regulations on the general management of the oil shale program, including discussions of the descriptions and acreage in oil shale leases, qualifications requirements, fees, rentals, royalties, bonds and trust funds, and lease exchanges. Subpart 3900—Oil Shale Management—Introduction This subpart establishes competitive oil shale leasing administrative procedures for implementing a commercial oil shale leasing program. The rule contains specific provisions required by Section 369 of the EP Act. Many of the sections of the rule contain regulatory requirements similar to the regulations in the BLM's existing mineral programs namely, coal, non-energy leasable minerals, and oil and gas. In creating a regulatory framework for the oil shale commercial leasing program, the BLM is adopting certain basic components and processes common to the BLM's leasing programs. Most of the BLM's leasing programs are governed by the MLA. The regulations governing those programs and this program include the following types of provisions: Pre-lease exploration; leasing processes; bonding; operations (including plan of development (POD)); reclamation; and inspection and enforcement. Section 3900.2 contains the definitions and terms used in these regulations. Many of the terms and definitions found in this section are similar to terms and definitions in the regulations of other BLM mineral leasing programs. Because most of the terms and concepts in this section are well-established, this section of the preamble does not address each of the definitions, but focuses only on definitions for certain terms that directly affect the reader's understanding of the regulatory framework of the oil shale leasing program or that are unique to these regulations. The BLM removed the definition for “Director” in the final rule because the term is not used in the regulatory text. The term “commercial quantities” was discussed in the proposed rule as production of shale oil quantities in accordance with the approved Plan of Development for the proposed project through the research, development, and demonstration activities conducted on the R, D and D lease, based on and at the conclusion of which a reasonable expectation exists that the expanded operation would provide a positive return after all costs of production have been met, including the amortized costs of the capital investment. One commenter stated that the report, Oil Shale Development in the United States , (James Bartis, 2005) estimates that the minimum size of a commercial scale operation will likely be over 100,000 barrels per day. The BLM interprets this as a recommendation to define commercial quantities as production of at least 100,000 barrels per day. Another commenter stated that an alternative method of defining commercial quantities would be to set it at no less than 1/2 of 1% of the recoverable resource on the lease. The BLM did not adopt these recommendations because “commercial quantities” does not apply to commercial lease production, but is a condition in an R, D and D lease that must be met before an R, D and D lessee can convert the R, D and D acreage and preference acreage to a commercial lease. One commenter expressed the view that the definition in the proposed rule for “commercial quantities” was subjective and that the definition should be revised to confirm that an oil shale lessee will only be required to pay royalties once operations convert from the test phase to a commercial operations phase. The definition of “commercial quantities,” applies only to the R, D and D leases and mirrors the definition for “commercial quantities” that is in the existing R, D and D leases. Provisions in the R, D and D leases also address the payment of royalties, therefore, we have revised the definition for “commercial quantities” in the final rule to make it clear that the definition only applies to R, D and D leases. Another commenter stated that there is an inconsistency between the “commercial quantities” definition and the “diligent development” definition in that section 3927.50 provides that market conditions are not considered a valid reason to waive or suspend the requirements for annual minimum production. As stated previously, the definition for “commercial quantities” only applies to R, D and D leases; therefore, there is no connection, or inconsistency, between the definition for “commercial quantities” and the diligent development requirements in section 3927.50. Finally, commenters said that the commercial quantities definition needs to take into account all of the related costs. The term “commercial quantities” pertains only to the R, D and D leases. As stated in the commercial quantities definition of this rule, the BLM will evaluate all costs of production, including the amortized costs of the capital investment when determining whether an R, D and D lease should be converted to a commercial lease. We did not revise the definition of commercial quantities as a result of public comment. One commenter requested that the BLM clarify the definition for “exploration license” to indicate that the holder of an exploration license does not have an automatic right to a lease to develop oil shale. We made a change in the final rule to address this concern by making it clear that an exploration license confers no right to a lease to develop oil shale. One commenter noted the absence of a definition for “royalty” and suggested that the BLM describe whether royalty is based on net or gross revenue and the components thereof. Please see the discussion of royalty valuation in subpart 3903 for a response to this comment. The term “infrastructure” means all support structures necessary for the production or development of shale oil. The definition lists examples of the different types of support structures that the BLM considers to be infrastructure. This term is defined in these regulations because it is critical to the BLM's review of lease applications. Infrastructure impacts are a key component of the plan of operations that the BLM will review when undertaking various analyses such as those required by NEPA. Furthermore, the BLM believes that a detailed itemization of examples is necessary since installation of infrastructure is one of the diligent development milestones. We received several comments discussing the need to modify the definition of the term maximum economic recovery (MER). The commenters pointed out that the oil shale industry is not yet established and therefore there currently are no standard industry operating procedures. The BLM agrees with the commenter in that, at this time, there is no established oil shale industry. However, the concept of MER is incorporated into many of the BLM's other mineral leasing regulations either as MER or as ultimate maximum recovery. The term specifically means that there is a need to prevent wasting of resources and that there should be requirements to recover the maximum amount of the resource that is technologically and economically possible, without jeopardizing safety considerations. The commenter also said that the term is used in various sections of the regulations and the phrase “standard operating procedures” needs to be clarified. In response to the comment, the BLM believes that even though there is no established oil shale industry and that technology in most cases is still untested, once an industry is established, there will be standard industry procedures that will be evaluated in determining MER taking into account such factors as the differences in technologies, resource characteristics, and geologic conditions. The BLM will also evaluate economics associated with the individual operation, market conditions, and standard operating procedures that are appropriate for the technologies of the established industry. In the future, the BLM will determine additional standard operating procedures that might be adopted for a future oil shale industry. As a result of the comments submitted on MER, the BLM revised and simplified the definition of maximum economic recovery in the final rule. The revised definition of maximum economic recovery reads as follows: Maximum Economic Recovery (MER) means the prevention of wasting of the resource by recovering the maximum amount of the resource that is technologically and economically possible, without jeopardizing safety considerations. We received several comments requesting that the BLM add additional definitions in the regulations. Some suggestions included adding to the definition section: Raw oil shale, charred spent oil shale, de-charred oil shale, char, raw shale oil, raw shale gas, hydrotreated shale oil, processed/separated gas, process energy efficiency, energy self sufficient effective resource recovery, minimum environmental impact, and Fischer Assay (FA)/TOSCO Assay. The suggested terms are used to describe various parts and components of shale oil extraction and processing. However, the BLM did not include the terms in the final rule because they are terms that describe processes, components, or items that were not being regulated or were terms that did not need an explanation or definition in the final rules. Some of the terms we consider subsets of other defined terms. The BLM believes that the comment on including a definition for the term “spent shale” is too restrictive, but decided to address the “waste” resulting from the mining, in-situ, and retorting operations. Therefore, the BLM added a definition of the term “mining waste” because it is more inclusive and could be defined as pertaining to the waste from surface, underground, and in-situ operations and oil shale retorting operations. In the final rule, mining waste is defined as “All tailings, dumps, deleterious materials or substances produced by mining, retorting, or in-situ operations.” The term “mining waste” is incorporated into both the definitions section 3900.2 and the contents of an operating plan in section 3931.11 of the regulations. The term “oil shale” means a fine-grained sedimentary rock containing: (1) Organic matter which was derived chiefly from aquatic organisms or waxy spores or pollen grains, which is only slightly soluble in ordinary petroleum solvents, and of which a large proportion is distillable into synthetic petroleum; and (2) Inorganic matter, which may contain other minerals. This term is applicable to any argillaceous, carbonate, or siliceous sedimentary rock which, through destructive distillation, will yield synthetic petroleum. The BLM defined the term “production” to acknowledge the various technologies associated with operations for extraction of shale oil, shale gas, or shale oil by-products Section 3900.5 explains the information collection requirements for the rule. The OMB has reviewed and approved the information collection requirements in parts 3900 through 3930 under 44 U.S.C. 3501 et seq. and assigned clearance number 1004-0201. The table in paragraph (d) of this section lists the subparts in the rule requiring the information and its title and summarizes the reasons for collecting the information and how the BLM will use the information. Section 3900.10 identifies which lands are subject to leasing under parts 3900 through 3930. Section 21 of the MLA authorizes the issuance of oil shale leases (30 U.S.C. 241(a)). The final rule expands this section to make it clear that certain National Park Service lands are not available for oil shale leasing. We also added a new paragraph (c) to this section to make it clear that the BLM may not issue oil shale leases on lands within incorporated cities and towns and to be consistent with the MLA (30 U.S.C. 181). Section 3900.20 addresses the right to appeal BLM decisions issued under these regulations to the Interior Board of Land Appeals (IBLA) under 43 CFR part 4. This section adopts standard appeals language found in the regulations of other BLM mineral programs. Section 3900.30 contains standard language providing that documents (i.e., applications, statements of qualification, PODs and supporting information, etc.) required by these regulations be filed in the proper BLM office with the required fees. The term “proper BLM office” is defined in the definitions section of this rule. Several commenters expressed concern about the release of confidential data or information and requested greater specificity regarding the information that is entitled to confidentiality when it is submitted to the BLM. Section 3900.30(b) of the proposed and final rule references the Freedom of Information Act (FOIA) (5 U.S.C. 552), which includes an exemption for confidential data and for certain geological information. This exemption under the FOIA is the most common standard that the BLM is required to follow concerning proprietary information; other statutory grounds for withholding information might apply in particular circumstances. Section 3900.40 addresses the multiple use mandate of FLPMA by providing that the BLM's issuance of an exploration license or lease for the development or production of oil shale would not preclude the issuance of other exploration licenses or leases on the same lands for deposits of other minerals or other resource uses. This provision is similar to regulatory provisions in the BLM's other leasing programs, which also promote multiple use of the public lands. One comment suggested that the oil shale lessee should be able to obtain the predominant right to develop the oil shale without competing uses. Another comment suggested that the BLM should reconsider the extent to which it is issuing oil and gas leases in oil shale areas. The BLM must manage the public lands under the principles of multiple use as mandated by FLPMA (43 U.S.C. 1732) (see also 43 CFR 3000.7), therefore, a predominant right should not be considered to have been granted to an oil shale lessee. In the event of unavoidable conflict, the Federal mineral lease for the same lands with the earlier effective date has priority for operations because later lessees have constructive notice of the prior lease, unless the prior lease is specifically subordinated to later-approved uses. Prior to issuing any mineral lease, the BLM considers potential conflicts and the impact on other resources, including mineral resources, and takes measures, including adding lease stipulations, to ensure that resources are not unnecessarily lost or damaged. Section 3900.50 clarifies the relationship of land use plans and NEPA to the BLM's commercial oil shale leasing program. This section provides that any lease or exploration license issued under these regulations must be issued under the decisions, terms, and conditions of a comprehensive land use plan. The land use planning process is the key tool used by the BLM to protect resources and designate uses for BLM-administered lands. Compliance with NEPA and land use planning is required before BLM can issue a lease or exploration license. Section 3900.61 addresses the procedures the BLM will follow concerning consent and consultation where the surface of public land is administered by other Federal agencies outside of the Department and procedures for particular situations where the United States has conveyed title to or transferred control of the surface. Paragraphs (a) and (b) address those procedures that the BLM will follow concerning consent and consultation where the surface of public lands is administered by other agencies outside of the Department. One commenter expressed confusion regarding consent and consultation as they apply to section 3900.61(a), Public lands, and section 3900.61(b), Acquired lands. Under this final rule, in most cases leasing public lands does not require consent from the surface management agency. However, the BLM will consult with the surface management agency prior to leasing. Where acquired lands or National Forest System (NFS) lands are involved, the BLM will obtain consent from the surface management agency prior to leasing. Paragraph (c) provides procedures an applicant may pursue in challenging a decision issued by a particular agency outside of the Department relating to special stipulations or refusal of consent. A comment requested clarification of the timeframe for filing an appeal with the BLM when a counterpart appeal has been filed with the surface management agency. An appeal to the BLM must be timely filed, as presumably would an appeal to the surface management agency. When appropriate, though, the BLM will issue its decision after the surface management agency renders its decision. Paragraph (d) does not allow the BLM to issue a lease or license on NFS lands without the consent of the Forest Service. Under paragraph (d), the BLM's decision whether to issue the lease or license is based on a determination as to whether the interests of the United States would best be served by issuing the lease or license. The provisions of this section closely mirror BLM regulations for oil and gas, coal, and non-energy leasable minerals. Paragraph (e) provides that the BLM make the final decision as to whether to issue a lease or license in those cases not involving a Federal agency, where the United States has conveyed title to the surface to any state or political subdivision or agency, including a college or any other educational corporation or association, to a charitable or religious corporation or association, or to a private entity. Paragraph (e) has been edited for clarity. Section 3900.62 addresses situations where the BLM may require lease or exploration license stipulations to protect lands and resources. Stipulations are site specific provisions that the BLM may add to standard lease or license terms prior to issuance for the purpose of protecting Federal resource values and mitigating impacts to other values identified in a NEPA document. Stipulations frequently restrict operations on the lease or permit by limiting surface disturbance for the purpose of mitigating potential impacts to a specific non-mineral resource value. This includes the protection of wildlife, plants, and cultural or other resources. This provision is similar to those found in the BLM's other mineral leasing programs. Subpart 3901—Land Descriptions and Acreage Section 3901.10 contains the requirements for land descriptions in applications or documents submitted to the BLM. This section is similar to the regulatory provisions addressing land descriptions found in other BLM leasing programs and establishes consistent standards for land descriptions in applications submitted to the BLM. Sections 3901.20 and 3901.30 incorporate the provisions of Section 21(a)(4) of the MLA, as amended by Section 369(j)(2) of the EP Act, 30 U.S.C. 241(a)(4), that establish 50,000 acres as the maximum acreage of oil shale leases on public lands that any entity may hold in any one state and that the oil shale lease acreage does not count toward acreage limitations associated with other mineral leases such as oil and gas leases. Another 50,000 acres may be held on acquired lands. Since the provisions in this section relating to maximum acreage holdings are statutory, the BLM does not have the authority to revise the requirements in this section. We received a comment stating that section 3901.20 appears to be in conflict with section 3927.20. We disagree. Section 3901.20 concerns the amount of acreage an entity is allowed to hold, and section 3927.20 concerns how many acres can be in each lease. One comment expressed concern that conceivably one entity could hold as much as 300,000 acres in the three states of Colorado, Utah, and Wyoming, combined, which could result in speculation. It is true that one lessee could potentially hold as much as 300,000 acres, however, we believe that the competitive leasing process requiring FMV bonus payments up front and the diligent development milestones at section 3930.30 will deter speculation. We made no changes to subpart 3901 as a result of this comment. Subpart 3902—Qualification Requirements Sections under this subpart detail the various statutory requirements under Section 27 of the MLA relating to who can hold Federal oil shale leases and interests. These regulations mirror many of the qualification provisions of the BLM's other mineral leasing regulations, namely oil and gas (43 CFR subpart 3102), geothermal (43 CFR subpart 3202), coal (43 CFR subpart 3472), and non-energy leasable minerals (43 CFR subpart 3502). Section 3902.10 enumerates the requirements of the MLA relating to who is authorized to hold leases or interests in leases (30 U.S.C. 181, 352). These requirements have a longstanding statutory and regulatory history and are found in the regulations for the BLM's mineral leasing programs. A commenter requested that BLM clarify section 3902.10(b) that a foreign citizen could hold a majority or controlling share in a domestic corporation. Proposed section 3902.10(b) does not place any limits regarding shareholdings; therefore, we have not revised the final rule as a result of this comment. Sections 3902.21 and 3902.22 explain the filing procedures for qualification documents, including when and where to file documents. Section 3902.21 also requires that all documentation submitted to the BLM as evidence of qualifications be current, accurate, and complete. Sections 3902.23 through 3902.29 detail the type of qualifications documentation that the BLM will require from: (1) Individuals (section 3902.23); (2) Associations, including partnerships (section 3902.24); (3) Corporations (section 3902.25); (4) Guardians or trustees (section 3902.26); (5) Heirs and devisees (section 3902.27); (6) Attorneys-in-fact (section 3902.28); and (7) Other parties in interest (section 3902.29). The requirements in these sections are similar to the standard requirements of other BLM regulations to show evidence of qualifications to hold a lease under the MLA. We received one comment regarding section 3902.23(b), which stated that acreage holdings are attributed to an individual if that individual holds more than 10 percent of the stock in a corporation, association, or partnership. The commenter thought that this was a low threshold. The 10 percent threshold is set in the Act for all leasable minerals (30 U.S.C. 184(e)(1)). Therefore we made no change to final section 3902.23(b) as a result of this comment. Subpart 3903—Fees, Rentals, and Royalties For payments of required rental and royalties, sections 3903.20 and 3903.30 address the acceptable forms of payment (section 3903.20) and where to submit payment for processing or filing fees, rentals, bonus payments, and royalties (section 3903.30). The acceptable forms of payment listed in section 3903.20 mirror the forms of payment accepted in the BLM's other mineral leasing regulations. Section 3903.40 incorporates the requirement of Section 369(j) of the EP Act that the annual rental rate for an oil shale lease is $2.00 per acre. One comment stated that the EP Act must be revised so that the rental rate is coupled to resource thickness, overburden depth, and quality of oil, etc. Since the statute sets the rental rate, the BLM has no discretion to revise it. A change in the EP Act is beyond the scope of this rulemaking. Another comment we received brought to our attention that there is no due date for rental payments. We revised final section 3903.40 to reflect that rental payments are due on or before the lease anniversary date. The lease anniversary date is the anniversary of the effective date of the lease (see section 3927.40). We also revised section 3903.40(b) to make it clear that there is only one notice sent by BLM demanding payment of late rentals. Section 3903.51 addresses the minimal annual production requirement that applies to every lease. It also discusses payments in lieu of production beginning with the 10th lease year. The BLM determines the amount required for payment in lieu of annual production, but in no case will it be less than $4 per acre. Payments in lieu of production are not unique to this rule. They are a requirement of other BLM mineral leasing regulations and the BLM believes they provide an incentive to maintain production. Setting the payment in lieu of production at no less than $4 per acre is an adequate payment to the Federal Government to justify allowing the lessee to continue holding a lease absent production, but should not be so high as to cause the lessee to relinquish the lease. A payment in lieu of production of $4 per acre for the maximum lease size of 5,760 acres equals a payment of $23,040 per year. In response to the ANPR, the BLM received comments expressing various ideas concerning minimum production amounts and requirements. The comments are summarized as follows: (1) Minimum production should be 1,000 barrels a day; (2) Minimum production should be based on the viability of the operation; (3) Minimum production levels should be based on resource potential and production levels identified in the POD; (4) Minimum royalties should be assessed at the end of the primary term; (5) Minimum production should be based on a percentage of the projected resource base; and (6) There should not be a minimum production requirement. We agree with several of the commenters' suggestions. The suggestions to base minimum production on the approved POD and the specifics of the operation were incorporated into sections 3930.30(c) and 3930.30(d). The suggestions related to defining the minimum production on a percentage of the resource base were not incorporated into the rule because of the difficulties associated with defining the recoverable resource, the variables associated with the different development technologies, and the differing kerogen content of the shales. We consider the suggestion that identified 1,000 barrels a day as the correct minimum production requirement too inflexible a standard because it does not allow for differences in shale quality and differences in extraction technology. Section 3903.52—Royalty Rates on Oil Shale Production Section 3903.52 establishes a royalty rate for all products that are sold from or transported off of the lease area. The BLM recognizes that encouraging oil shale development presents some unique challenges compared to BLM's traditional role in managing conventional oil and gas operations. We received a wide range of comments presenting alternative royalty approaches on both the proposed rule and the ANPR, and we address those comments below. In the proposed rule we narrowed the range of options based on the ANPR comments and did not settle on a single royalty rate. Instead, we presented two royalty rate alternatives in the proposed rule (as outlined later in this section), and requested public comment on those specific alternatives. In addition, the rule considered a third alternative, a sliding scale royalty rate based on market prices for competing products, and we sought public comment on the appropriate parameters for the sliding scale royalty rate. The EP Act (Section 369(o)) directs the agency to establish royalties and other payments for oil shale leases that “shall (1) Encourage development of the oil shale and tar sands resources; and (2) Ensure a fair return to the United States.” The market demand for oil shale resources based on the price of competing sources (e.g., crude oil) of similar end products is expected to provide the primary incentive for future oil shale development. Additional encouragement for development may be provided through the royalty terms employed for oil shale relative to conventional oil and gas royalty terms, but we recognize that such incentives must be balanced against the objective of providing a fair return to the United States for these resources. Through the ANPR process, the BLM initially examined a wide range of royalty options, including: (1) 12.5 percent royalty rate on the first marketable product; (2) 12.5 percent royalty rate on the value of the mined oil shale rock, as proposed in 1983; (3) 8 percent royalty rate on products sold for 10 years with optional increases of 1 percent per year up to a maximum of 12.5 percent, similar to the rates established by the State of Utah in 1980; (4) Initial 2 percent royalty to encourage production and a 5 percent maximum upon establishment of infrastructure; (5) Sliding scale royalty rate tied to timeframes up to a maximum of 12.5 percent; (6) Sliding scale royalty rate tied to production amounts up to a maximum of 12.5 percent; (7) Sliding scale royalty rate with royalty rates tied to the price of crude oil; (8) Royalty rate of 1 percent of gross profit before payout and royalty rate of 25 percent net profit after payout—(Canadian oil sands model); (9) Royalty based on cents per ton as proposed in the 1973 oil shale prototype program; and (10) Royalty based on British Thermal Unit (Btu) content as compared to crude oil. In evaluating an appropriate royalty rate system for oil shale that meets the EP Act's dual objectives of encouraging development and ensuring a fair return to the government, the BLM also reviewed other Federal royalty rates for Federal minerals set by statute and regulations administered by Department bureaus, and royalty rates applied to oil shale production in other countries. The royalty rates for other Federal energy minerals vary. Specifically, current royalty rates for Federal energy minerals under Department leasing programs include: (1) Onshore oil and gas (12.5 percent); (2) Offshore oil and gas (16.67 percent), Gulf of Mexico Region (18.75 percent); (3) Underground coal (8 percent); (4) Surface coal (12.5 percent); and (5) Geothermal (for new leases: 1.75 percent for the first 10 years and 3.5 percent thereafter. For leases issued prior to the EP Act, 10 percent on net proceeds after deductions). All of these programs allow for royalty rate relief under certain circumstances (30 U.S.C. 241 and 209). The BLM also looked at royalty applications for oil shale and similar unconventional fuels in other countries, including: (1) For oil sands, Canada applies a royalty rate of 1 percent of the gross revenue before payout (before companies have recouped investment costs) with a 25 percent net profit royalty rate applied after payout; (2) Australia has a 10 percent gross royalty on the value of the shale oil produced; (3) Brazil applies a 3 percent gross royalty rate; (4) Estonia does not have a royalty; and (5) No information on a royalty rate for shale oil produced in China was available. It should be noted that Canada produces oil from oil sands, not oil shale. The oil in the sands is the same as crude oil, but dispersed in sand. Extraction and processing is more expensive than for conventional crude oil production, but less expensive than is anticipated for oil shale. Australian operations are using the Alberta Taciuk Process, which is the same type of technology currently used by the Oil Shale Exploration Company (OSEC) in Utah. Despite their 10 percent royalty rate, the Australian oil shale project (the Stuart Project) was heavily subsidized by the Australian government through other means (tax incentives). Even the government subsidies could not sustain oil shale operations in Australia. The last three operators went into bankruptcy after brief operations. Suncor, the founder of the Stuart Project and a successful developer of the Canadian tar sands, exited the Australian oil shale business after losing approximately one hundred million dollars. 1 For its Utah demonstration project, OSEC is also expected to test the Petrosix horizontal retort process, which is currently being used by Petrobras, Brazil, for oil shale operations. 1 Environmental News Service, July 22, 2005, http://www.ens-newswire.com . Australia and Brazil are the only other countries known to be producing, or to have produced, oil shale using the same technologies as in the United States. Oil shale developmental efforts in China and Estonia are owned by their respective governments. Because no other country has yet achieved successful commercial oil shale operations and because of the wide variety of oversight and revenue structures employed in each country, the BLM's review of these systems did not identify a useful model for a royalty system to be used for oil shale development on Federal lands in the United States. In the ANPR, the BLM solicited public input on the royalty rate and point of royalty determination. The BLM's purpose for requesting comments was to solicit ideas on these royalty issues for a resource that has little or no history of commercial development. There were approximately thirty-one entities that provided comments through the ANPR process that were specific to royalty rate and royalty point of determination. The comments suggested royalty rates that ranged from a royalty rate of zero to a royalty rate of 12.5 percent. Of the royalty-related comments, three suggested that the royalty be set at 12.5 percent, the same rate as in BLM's oil and gas program, while some comments described a 12.5 percent royalty rate as unreasonable. It is contemplated that the primary products produced from oil shale will compete directly with those from onshore oil and gas production, which has a 12.5 percent royalty rate. However, the BLM recognizes that the nature of potential oil shale operations differs from that of conventional oil and gas operations and that these differences may suggest the need for a royalty system other than the traditional flat rate of 12.5 percent used for conventional onshore oil and gas operations. In determining the royalty rate for oil shale, it should be noted that there is a significant difference between oil shale mineral deposits and a conventional crude oil reservoir. As discussed in the “Background” section of this preamble, oil shale is a marlstone that contains no oil, but kerogen, that needs to be refined and converted to synthetic crude oil. Currently, proposed processes to extract kerogen from an oil shale deposit are considerably different, as well as labor and capital intensive. Oil shale is a solid rock that must be mined or treated in place to release the kerogen. Two of these processes are discussed in the “Background” section of this preamble. We received a wide range of comments on the appropriate royalty rate as a result of the ANPR. Seven of the comments recommended that a “very low royalty rate” be established until after companies have recouped the costs of their investments (debt service and capital investment). Many among the seven recommended that a 1 percent royalty rate be the starting point, and they used the Alberta oil sands royalty scheme as an example. As discussed above, the BLM looked at royalty applications for oil shale and similar unconventional fuels in other countries. The Alberta tar sand model presents two challenges. First, because of the continual infusion of capital to acquire new equipment, the payout point is being reached only after many years of operation. Secondly, because of the complexity of determining when payout may occur, such a royalty scheme requires a more robust and costly administrative process to guard against manipulation; those costs would reduce the net return to the United States. Therefore, the BLM considered the investment payout scheme as inconsistent with the premise of “a fair return” to the United States as mandated in EP Act. Three of the ANPR comments recommended that “royalties must be high enough” to support local communities and infrastructure; however, these comments did not provide specific royalty rates. Oil shale royalties are not designated for community and infrastructure support, but by statute are required to be split between the Federal Treasury and the states (30 U.S.C. 191). Presumably states could choose to direct a portion of the royalty revenues they receive to local community and infrastructure support, but that would be a state choice, and for the purpose of this rulemaking, these comments were not considered because they assume a use of royalty revenues not available under current law. Three comments suggested that royalties should not be charged on hydrocarbons unavoidably lost or used on the lease for the benefit of the lease, but did not directly address the royalty rate issue. One comment suggested the royalty be “based on the material as it exists naturally in the land, and as it is removed from the land.” This comment seems to suggest that royalty should be based on mined raw shale. While the BLM acknowledges the inherent differences between an oil shale deposit and other deposits from which similar products can be produced, this suggestion was not considered because there is no known value for raw oil shale since there is no oil shale industry or an established market for raw oil shale. However, it should be noted that in 1983 the BLM proposed a rule to establish a royalty rate equivalent to 12.5 percent of the value of oil shale after mining or resource extraction and before processing, as determined by the BLM. The 1983 proposed rule was published on February 11, 1983 (48 FR 6510). The 1983 proposed rule provided that “the derivation methodology for this value shall be announced prior to the solicitation of bids.” The proposed rule further stated that “the royalty rate shall, to the extent practicable, not be levied on any value added by the production process after the point of resource extraction.” It would be unreasonable to adopt such a proposal today, due to the changes in extraction methodology (in situ versus ex situ). It would also be challenging to develop a fair and transparent process to calculate the royalty equivalent in today's economic environment, and no values were assigned to the mined or unprocessed rock and tonnage in the 1983 proposed rule. As noted, the 1983 proposed rule deferred the determination of those parameters to a later date. In addition to ANPR comments received on royalty rates, the BLM considered an initial 2 percent royalty to encourage production and a maximum 5 percent rate upon establishment of infrastructure. This method recognized the high costs involved in producing shale oil. However, we did not adopt this approach because of the difficulty involved in determining when necessary infrastructure is in place. In the proposed rule the BLM also considered an 8 percent royalty rate established by the State of Utah for state oil shale leases. It was determined that this rate represents the historic base royalty rate for solid fuel minerals on the State of Utah School and Institutional Trust Lands Administration lands—including asphaltic sands, uranium, and coal. To date, several oil shale leases issued by the State of Utah are in the infancy stages of research and development. These leases were issued with an initial royalty rate of 5 percent for the first 5 years after production begins. The royalty rate may increase by 1 percent per year to 12 1/2 percent. After examining the basis for setting rates, as suggested in the ANPR comments, the BLM determined that an initial flat 12.5 percent royalty rate for all future production may not allow oil shale to become competitive with traditional oil and gas development and therefore could be viewed as inconsistent with the requirements of EP Act. Royalty Rate Alternatives Proposed for Further Consideration As noted previously, we did not propose a single royalty system. Based on the information the BLM reviewed, and considering the unique challenge of trying to set a royalty rate on oil shale production in light of the many uncertainties regarding the economics and technology of a potential future oil shale industry, we presented different royalty rate alternatives in the proposed rule: 1. A flat 5 percent royalty rate; and 2. A 5 percent royalty rate on a specific volume of initial production beginning within a prescribed timeframe, with a 12.5 percent rate applied thereafter. In addition, we sought comment on the appropriate parameters for a third option: A two or three tiered sliding scale royalty based on the market price of competing products (e.g., crude oil and natural gas). A further explanation of each of these proposals is presented below. Proposed Option 1. Flat 5 percent royalty. Although mitigated somewhat by the much greater geographic concentration of oil shale resources, there is a significant difference between the energy value of oil shale and crude oil. On a per-pound basis, very high quality oil shale rock generates 4,300 Btu, coal generates an average of 10,600 Btu, while crude oil generates 19,000 Btu. Even wood has more heating capacity than oil shale rock, generating an average of 6,500 Btu. Applying the relative Btu value of oil shale to crude oil would result in a 2.6 percent royalty for oil shale. Using the same comparison to the royalty rate for underground coal would result in a 3.2 percent royalty rate for oil shale. In other words, it would require almost 5 times as much oil shale to produce the Btu value of crude oil and more than 2 times as much oil shale to produce the equivalent Btu value of coal. The BLM looked at royalty rates on leases issued under Interior's 1973 Prototype Leasing Program. The prototype leases provided for royalties of $.12 per ton for oil shale with a quality of 30 gallons of oil per ton (30 g/t) with the addition of $.01 for every increase in gallon per ton of oil shale. In 1973, the average price of a barrel of oil was $3.89. At $.24 per ton of 42 g/t or one barrel/ton of oil shale, the royalty per barrel of oil would have been 5 percent. This rate is similar to the rate derived by comparing production costs to royalty rates as recommended by the proposed regulations. The BLM also estimated what royalty rates for shale oil might be, based on comparisons of production costs for similar products. The cost of removing oil from shale rock is currently estimated to be two to three times higher than the current cost of producing conventional crude oil from onshore operations. The current published estimated production cost for shale oil ranges from about $37.75-$65.21 a barrel. Current unpublished estimates are in the $75-$90 range. The production cost for conventional onshore crude is approximately $19.50 a barrel. 2 The table below compares the estimated cost of shale oil production for different technologies with the estimated cost of current onshore United States conventional oil production. The table also estimates what royalty rates for oil shale production might be for the different production methods compared to a 12.5 percent royalty rate for conventional oil production, adjusted to account for differences in production costs. 2 Energy Information Administration, Crude Oil Production, dated July 3, 2008. http://www.eia.doe.gov/neic/infosheets/crudeproduction.html and http://www.eia.doe.gov/emeu/perfpro/tab_12.htm . The production cost at the time of analysis was approximately $19.50 per barrel. 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 costs for oil from oil shale is not a new concept and is similar to the situation in the coal program where underground coal operations compete with surface coal operations, which have lower production costs. Congress addressed this disparity in production costs by allowing for different royalty rates for coal mined underground versus coal mined at the surface. Therefore, one alternative that considers the decreased energy content and increased production costs, while encouraging production and ensuring an appropriate return to the government is to set a flat royalty rate of 5%. This alternative assumes that oil shale will continue to be more expensive to produce for many years when compared to new conventional oil. Proposed Option 2. A 5 percent royalty on initial production, with 12.5 percent thereafter. As stated in the proposed rule, this alternative would have provided a reduced royalty rate of 5% as a temporary incentive for early production of oil shale (similar to royalty incentives offered to spur initial Outer Continental Shelf (OCS) deepwater production), but with the standard 12.5% onshore oil and gas royalty rate applying to all oil shale production after a set timeframe and a set amount of production has taken place. Like the other royalty options, this option would have required oil shale lessees to pay royalties on the amount or value of all products of oil shale that are sold from or transported off of the lease. The proposal established that the standard royalty rate for the products of oil shale is 12.5 percent of the amount or value of production. However, under this option, for leases that begin production of oil shale within 12 years after the issuance of the first oil shale commercial lease, the royalty rate would have been 5 percent of the amount or value of production on the first 30 million barrels of oil equivalent (BOE) produced. The advantage of this alternative over a flat 5% royalty (Option 1) is that it provides a better return to taxpayers on later production if oil prices remain high and oil shale production becomes competitive with new conventional oil projects. At $60 a barrel, this would amount to roughly $1.8 billion in production per lease at the lower 5% royalty rate, providing roughly a $135 million in savings to the lessee compared to using the standard onshore oil and gas royalty rate of 12.5%. One potential downside to this alternative is that offering royalty incentives without regard to oil prices increases the likelihood that, if oil prices remain high, the government will sacrifice revenue without affecting actual oil shale development. For example, at $120 a barrel, the savings would be worth $270 million to the lessee, even though oil shale operations would be more profitable than at oil prices of $60 a barrel. Therefore, in the proposed rule we requested comment on whether the temporary 5% royalty on initial production should also be conditioned on crude oil and natural gas prices (similar to OCS deepwater royalty incentives) and if so, what oil and gas price level would trigger payment at the higher 12.5% rate if prices exceeded the threshold. We also requested comments on the 12 year timeframe for reduced royalty. Proposed Option 3. Sliding scale royalty based on the market price of oil. Two comments on the ANPR suggested a sliding scale royalty format. One comment specifically suggested a sliding scale royalty scheme based on a royalty schedule that varies with the price of conventional crude, as follows: At $10 per barrel of conventional crude, the royalty rate should be zero; At $15 per barrel, royalty should be 0.25 percent and should increase by 0.25 percent for every $5 per barrel increase up to $35 per barrel; At $40 per barrel, the royalty rate should be 2 percent and should increase by 0.5 percent for every $5 per barrel increase in the price of conventional crude oil until the price of conventional crude reaches $100 per barrel; and At $100 per barrel, royalty rate should be 8 percent and should remain at 8 percent at prices above $100 per barrel. Another ANPR comment suggested two approaches to calculating royalty. The first part of the comment suggested that a simple way to accomplish royalty rates would be to index the value of barrels of oil equivalent to some percentage of the New York Mercantile Exchange (NYMEX) futures (for instance, a 30 day average front month) prices. The commenter suggested that the index should be some fraction of the price, such as 50 to 65 percent. In the second part of the comment, the commenter suggested that, as an alternative to indexing, the BLM uses a sliding royalty rate that is calculated on the difference between product price and the highest-cost production in the industry. The commenter cautioned that “there need to be provisions that deferred portions of the royalty do not reduce mineral lease payments to the States, if an escalating royalty rate is used.” The BLM, in consultation with the MMS, evaluated these variable royalty options, but decided that as presented, they would be highly complex, and therefore, cumbersome to administer. With price volatility in the crude oil market, an intricate sliding scale royalty scheme could make enforcing compliance very difficult for the MMS. In addition, there is uncertainty about the types of products that would be derived from oil shale refining. Royalties based on oil shale quality would also be difficult for the BLM to administer when attempting to verify production quantities. For instance, if oil shale is extracted in an underground heating system, it would be extremely difficult for the BLM to determine how much oil or other product came from a particular volume or area of in-place oil shale. While the BLM and MMS are concerned about the complexity of administering some of the sliding scale royalty proposals, we recognize that there is some merit to the sliding scale concept, and in a simpler form, a sliding scale royalty may prove useful in meeting the dual goals of encouraging production and ensuring a fair return to taxpayers from future oil shale development. One of the concerns that has been expressed regarding oil shale development is that potential oil shale developers may be reluctant to make the large upfront investments required for commercial operations if they believe there is a chance that crude oil prices might drop in the future below the point at which oil shale production would be profitable (i.e., competitive with new conventional oil production). A sliding scale royalty system could allow the government to at least partially mitigate this development risk by providing for a lower royalty rate if crude oil prices fall below a certain price threshold. The basic concept is that in return for the government accepting a greater share of the price risk that an operator faces when prices are low (in the form of a lower royalty), the government would receive a greater share of the rewards (through a higher royalty) when prices are high. At the time of the proposed rule the BLM had not yet decided on the specific parameters of a sliding scale royalty system, but considered a simplified, two-or three-tiered system based on the current royalty rates already in effect for conventional fuel minerals and with a 5 percent royalty rate (Option 1) representing the first tier. The proposed rule explained that the applicable royalty rate would be determined based on market prices of competing products (e.g., crude oil and natural gas) over a certain time period and that if prices remain below a certain point during the applicable period, the royalty rate on oil shale products would be 5 percent for that period. If prices are above that range for the period, a higher royalty would be charged. In a three-tiered system, a third royalty rate would apply if prices rise above a second price threshold during the applicable period. In the proposed rule the BLM sought comment on the specific parameters that could be applied to a sliding scale royalty system. More specifically, the BLM asked for feedback on the following questions: 1. Should a sliding scale system include two or three tiers? Assuming a 5 percent royalty for the first tier, what would be appropriate royalty rates for the second and/or third tiers? 2. What are appropriate price thresholds to apply to each tier? Should the thresholds be fixed (in real dollar terms), or should they float relative to a published index? 3. Should the sliding scale apply to all products, or should nonfuel products pay a traditional flat rate? 4. Are there other ways to simplify a sliding scale royalty to reduce the administrative costs for BLM, MMS, and producers? As explained in the proposed rule, under a sliding scale system, if prices fall below the lower range, producers would have a “safety net” in the form of the lower 5% royalty rate. Whether or not the lower royalty kicks in at some point, simply having it in place provides some added certainty for investors that would help encourage oil shale production. In return for this “safety net” that conventional oil and gas producers do not enjoy, oil shale producers would be required to pay a higher royalty rate(s) when crude oil and/or natural gas prices are high (and where oil shale is expected to be substantially more profitable). There are a couple of advantages of this alternative. It reduces the risk for oil shale operators that oil prices might fall below the point that continued oil shale production would be economic. However, it also ensures an improved return to the government if prices remain within one of the higher expected ranges at which oil shale may be profitable. One disadvantage is that taxpayers accept a greater risk of lower returns if prices fall and remain well below the lowest threshold. However, with the lowest royalty rate step set at 5 percent, this risk is no greater than under a flat 5 percent royalty system (proposed Option 1). Other Royalty Issues The BLM also received 5 ANPR comments specific to the royalty point of determination. Two of the comments suggested that royalty should be determined “at the point at which the oil product exits a process facility in a marketable state.” One comment suggested that “the point of royalty determination be at the earliest point of liquid or gaseous product marketability.” Another comment suggested that “the oil produced should be measured at the point at which the oil product exits a processing facility in a marketable state.” The last comment did not provide a specific suggestion; rather, it stated that the BLM “must set the royalty rate and point of royalty determination with reference to the economic cost of emissions that would be created from developing, and then burning, the oil shale resource.” After a careful evaluation of these comments and consultation with the MMS, we have concluded that the royalty would be assessed on all products of oil shale that are sold from or transported off of the lease. This point of royalty determination is similar to points of royalty determination for other Interior Department minerals programs. Currently, there is no oil shale industry and the oil shale extractive technology is still in its rudimentary stages; as such, commercial shale oil production does not exist anywhere in the world. As research and development of oil shale technology progresses, the BLM will have adequate time to reexamine and readjust royalty rates for oil shale production, either up or down. In the proposed rule we asked for specific comment on the time necessary to develop an oil shale industry. The proposed rule requested comments on what future royalty valuation regulations need to contain. In particular, the Department asked for comments on the potential types of oil shale products, the most equitable and practical point and method to determine the value on which to apply the royalty rate, and whether there are or should be opportunities to determine value by market proxy or indices. The Department solicited comments on alternative approaches to valuation and royalty rates. Several commenters suggested the royalty be based on the material as it exists naturally in the land, and as it is removed from the land. One commenter stated that royalties should be assessed at the first point of sale. Another commenter recommended that the point of sale of the synthetic crude should be the point of price determination. Likewise, other commenters stated that the Department should determine royalties after processing or manufacturing. We received one comment that said that the BLM should charge royalty on production that is used on the lease. The comment is based upon one commenter's estimate that about 1/3 of the product is likely to be natural gas and that it would attempt to use natural gas to heat the shale in subsequent development. One commenter stated that making this royalty-free- short-changes the public. One commenter stated that lease production used on or for the benefit of the lease should not be subject to royalty. The commenter urged that products of oil shale that are transported off-lease for use in a facility in the general area to develop resources on the lease should be viewed as use of that product on the lease. The “point of royalty measurement” and the “point of royalty determination” are two different concepts. The point of royalty measurement concerns the volume upon which royalty is assessed and is where the particular mineral product is measured for royalty purposes. For oil and gas leases, royalty is due on “all” oil or gas removed or sold from the leases except for oil or gas unavoidably lost as determined by BLM or used on or for the benefit of the lease (see, e.g., 30 CFR part 202, subparts C and D). For coal, royalty is due on “[all coal (except coal unavoidably lost as determined by BLM under 43 CFR part 3400) . * * * This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease” (30 CFR 206.153(a)]. Generally, the BLM determines where the product is measured for onshore minerals and MMS for offshore minerals. The point of royalty determination is generally the point at which value is assessed and is not a specified fixed point under any existing rules. Under the MLA, the Secretary is required to establish a royalty rate on the amount or value of the production removed or sold from the lease (30 U.S.C. 226(b)(1)(A))(see also the Outer Continental Shelf Lands Act, 43 U.S.C. 1337(a)(1)(A)). The Department has consistently interpreted this phrase to mean that royalties may be determined at a point off of the lease (see, e.g., Amoco Production Co. v. Watson , 410 F.3d 722, 729 (D.C. Cir. 2005), cert. denied in relevant part sub nom. BP America Co. v. Watson , 547 U.S. 1068 2006). The Department then allows certain applicable transportation and processing deductions from that off-lease royalty value, to arrive at a value for “the production removed or sold from the lease.” With respect to the first comment that the royalty should be assessed on the oil shale as it exists in situ, this comment seems to suggest that the point of royalty determination be based on mined raw shale. While the Department acknowledges the inherent differences between an oil shale deposit and other deposits from which similar products can be produced, the Department did not consider this suggestion because there is no known value for raw oil shale, there being no established market for raw oil shale. Similarly, the Department is not in the position to definitively state that the point of royalty determination should be on processed or manufactured products. As many of the commenters acknowledged, there is not enough information at this date to determine how products will be extracted, nor is there enough information on the products that will result from extraction or how those products will be marketed. It would be premature to fix the point of royalty determination at the lease or at the tailgate of a processing plant at this time. Therefore, the Department is retaining the point of royalty determination it proposed in this final rule as being on all products that are sold from or transported off of the lease area. With respect to royalty-free use of fuel on the lease, as discussed above, for decades the Department's valuation rules have not assessed royalties on fuel used for the benefit of the lease. However, until the Department has more information on the extraction processes involved, it is premature to determine whether the Department will assess royalty on fuel used on the lease. One commenter stated that if net royalty is being considered, the definition of royalty basis should be revenue from sales of hydrocarbon products, less transportation costs, all direct operating costs (mining and extraction) and administration costs, together with a deduction for the capital costs of assets employed based on Internal Revenue Service amortization methods. One commenter recommended that the Department define the term “royalty,” indicate whether royalty is based on net or gross revenue, and specify the components thereof. One commenter stated that MMS's valuation of the products from oil shale will be significantly less than the market price of the final refined products because MMS will allow manufacturing/processing allowances. One commenter stated that kerogen is worthless unless processed. The monetary value of kerogen is tied to the net proceeds between the market price of products and production costs and the technical and economic effectiveness of the process. The commenter also stated that a royalty and bonus process should be replaced with a competitive annual payment from the lessee to the Federal Government based on the value of the kerogen in the ground and net proceeds (time varying market price of products minus time varying production cost). One commenter believes that royalty should be assessed on the first sale. Several commenters stated that MMS should propose valuation regulations concurrently with these BLM regulations to give potential oil shale lessees certainty, which will in turn “encourage development.” This final rule establishes a royalty rate for Federal oil shale leases; however, the Department is not proposing corresponding MMS valuation regulations at this time. Because the oil shale industry is still in the research and development phase, it would be speculative to predict whether the industry as it matures will predominantly sell from the leases it mines solid oil shale, shale oil, synthetic petroleum, shale gas, natural gas, or products in several different forms or stages of processing. It is also difficult to predict whether or when multi-buyer/multi-seller markets will develop that would provide FMV pricing for products of oil shale. The comment that kerogen is worthless unless processed and, thus royalty should be based on a market price minus production costs, asks the Federal Government to share in production costs. Thus, and many of the comments regarding valuation and the point of royalty determination discussed above, suggest that MMS should abandon the marketable condition rule and share in production costs with the lessee. While it is premature to address this comment directly in this rule, it is important to note that the Department generally does not share in the costs of production or the costs of placing production in marketable condition for minerals produced from Federal leases. The MMS will promulgate royalty valuation regulations before oil shale leases are required to begin paying production royalties under this rule. As stated in the proposed rule, to the extent possible, the MMS will ensure that any oil shale valuation regulation is consistent with other valuation regulations and will incorporate principles of simplicity, early certainty, and reduced administrative costs in the oil shale valuation regulations it promulgates. In addition, the MMS will consider the comments submitted to the BLM proposed rulemaking when formulating oil shale valuation regulations. For example, the MMS could promulgate regulations similar to the current Federal oil valuation regulation to value crude oil produced from oil shale. Under such regulation, the value of oil sold at arm's-length would be based on gross proceeds less allowable costs of transporting oil to the point of sale. The value of oil not sold at arm's-length would be based on a market index price or the affiliate's arm's-length resale price. In both arm's-length and non-arm's-length situations, the regulations provide for adjustments for location, quality, and transportation allowances. Further, lessees also can petition for alternate valuation agreements that are situation specific when regulatory provisions do not apply. The regulations promulgated here, however, do not address those valuation issues. The Federal Government does not typically require payment of royalties on potentially valuable minerals or inorganic matter that are not sold or transported off the lease for commercial purposes. Those materials would be considered waste, and would be subject to management and reclamation requirements as provided in the lease or in an approved POD. One commenter suggested that non-fuel products should pay a 12.5% royalty rate. Another commenter suggested that different minerals produced may require different royalties. Several commenters recommended that there be no royalties on spent oil shale. One commenter stated that royalties should not be assessed on by-products such as sulfur removed from the gas stream to meet air quality requirements and sold, whether at a loss or a profit. The commenter said that items transported off of the lease for recycling or disposal should not be considered products or by-products. Consistent with current Department policy, by-products that are not sold or bartered, including produced water, CO 2 , ammonia, etc., are not royalty-bearing. The BLM and the lessee must take measures to minimize damage or loss of resource by-products and other resources on the lease. Finally, one commenter stated that royalty should only apply to all fuel products and that by-products should be royalty free. The final rule establishes a royalty for all products that are sold or transported off the lease. The royalty rate for by-products will be the same, except for those commodities whose rates are already established under the mineral leasing laws or regulations. Title 30 U.S.C. 241(4), states that “For the privilege of mining, extracting, and disposing of the oil and other minerals covered by the lease under this section the lessee shall pay to the United States such royalty. * * *” The Secretary has the discretion to reduce the royalty rate for all products produced from the lease to encourage use or the disposal of a product stream. The BLM will apply the same royalty rate for all oil shale products sold or transported off of the lease area. In the economic analysis for this rule, the BLM analyzed the royalty implications of a range of royalty rates. Specifically, the BLM conducted a simulation-based analysis to estimate the revenue, profit, and royalty implication of a production scenario 3 using three discount rates (7 percent, 3 percent, and 20 percent), three world crude oil price projections (Energy Information Administration's (EIA) 2007 reference, high, and low price projections 4 ), and six different royalty rates (1 percent, 3 percent, 5 percent, 7 percent, 9 percent, and 12.5 percent). The likelihood of a company, in the face of numerous technological challenges, having the incentive to develop Federal oil shale reserves and experiencing economic success will depend on a number of factors. However, because the simulated scenario analysis is based on a given production scenario and set production costs, the analysis did not assist in determining the project(s) economic viability due to the royalty rate applied. The analysis did, however, clearly identify world oil prices as a critical variable determining a project's economic viability. Under the EIA's low price projections, which project oil prices to be below $36 per barrel through 2030, all operations are assumed to be uneconomic based on the set production costs used in the analysis of the rule. 3 America's Strategic Unconventional Fuels Resources, Volume III Resource and Technology Profiles , Task Force on Strategic Unconventional Fuels, September 2007, page III-17, Table III-4. Potential Oil Shale Development Schedule—Base Case, ( http://www.unconventionalfuels.org ). 4 Department of Energy, Energy Information Administration, Annual Energy Outlook 2007, Report #: DOE/EIA-0383(2007), February 2007. Public Comments on the Proposed Royalty Rates The BLM received many royalty-related comments. Few provided substantial data or rationale for justifying a particular royalty rate. Many commenters suggested variable-scale or sliding-scale royalty schemes albeit in various forms (1-3%, 1-5%, 0-6%, 2-12.5%, 5-16.67%). The industry submitted the majority of the comments that stated that the flat 5% royalty rate was too high and that it provided no incentive to encourage oil shale development. One commenter provided information on a new oil sands royalty framework proposed in the Alberta Legislative Assembly in the fall of 2008. Under the new framework, the “base rate is 1% of gross revenue, and increases for every dollar that oil is priced above $55 a barrel, to a maximum of 9% when oil is $120 or higher.” The commenter also stated “there are currently 89 active oil sands projects in the province, of which 39 are in post-payout and 50 in pre-payout.” In the proposed rule preamble, the BLM incorrectly stated that “operators have never reached the payout point due to the continued capital expenditures in new equipment. The same commenter also requested the BLM refer to oil sands operators as “Alberta operators” rather than “Canadian operators.” We appreciate these corrections. Other comments on the proposed rule's royalty alternatives are summarized as follows: (1) Several commenters suggested that the royalty rate for oil shale should start at 1%; (2) A few commenters agreed with a flat 5% royalty rate; (3) A few commenters suggested a 3% royalty rate; (4) Some commenters suggested an 8% royalty rate; (5) A few commenters agreed with a royalty scheme in which the rate starts at 5% and increases to 12.5%; (6) A few commenters agreed with a sliding scale royalty rate, but proposed varying modifications; (7) Some commenters suggested a 1% royalty rate, with several commenters suggesting a 1% rate for the first 10 years of production and an increase to 3% thereafter; (8) A few commenters suggested a 1% royalty rate to be increased to 5%; (9) A few commenters suggested a flat 12.5% royalty rate; (10) A small number of commenters suggested a sliding scale scheme of 2-12.5%; 0-12.5%; and (11) The majority of the commenters did not suggest a specific royalty rate. The BLM addresses these comments in 4 groups: (1) Flat royalty rate of less than 5%; (2) Flat royalty rate equal to or greater than 5%; (3) Sliding scale royalty rate of 1-5%; and (4) Sliding scale royalty rate of 0-12.5%. Flat Royalty Rate Less Than 5% The commenters who advocated a flat royalty rate of less than 5% stated that the proposed royalty rates do not take into account the differences between the economics for oil shale production versus crude oil production. They stated that no adjustment was made for the difference in the amount of capital investment required between conventional oil and oil shale operations. They suggested that the production royalty rate should be reduced to 3% until the first plant on each lease is fully amortized in a minimum timeframe of 10 years. One commenter stated that “the 5% fixed royalty rate is too high,” and that “U.S. oil shale resources have no value if they are uneconomic to produce.” The BLM considered the comments and decided not to adopt the suggested 3% flat royalty rate or any rate below 5%. The BLM did not adopt the lower rates because the BLM's analysis of comparable production costs in the proposed rule indicated that the proposed rate of 5% better reflects the differences between the economics for oil shale production versus crude oil production. The commenters who advocated the suggested royalty rate of 3% did not provide sufficient data to support their analysis. One comment offered a new royalty rate scheme as an alternative if the BLM disapproves their suggested royalty rate of 1-3%. The commenter suggested that “royalty should reflect the fact that the extracted oil shale has no economic value of its own. It contains kerogen, which must be processed to produce a low-quality shale oil.” The commenter also suggested that royalty should be based on a mathematical computation which would incorporate FA, the NYMEX, the price of conventional crude oil, and a royalty rate of 3%. The commenter suggested that the royalty payment for a ton of (underground) mined and processed oil shale should be assessed according to the following formula: (FA/42) × (Current NYMEX/$100/BBL) of the oil shale that is produced for conversion into shale oil multiplied by a selected index reflecting the value of the shale oil. In essence the formula converts the FA into barrels (42 gallons per barrel), multiplies FA by the ratio of NYMEX and a fixed bench mark price of $100 per barrel of conventional crude oil. After careful consideration, the BLM did not adopt the comment because the suggested formula assigns too little a value to oil shale products, lacks the potential to yield a fair return to the taxpayers, and would be very complex and expensive for MMS to administer. A commenter also stated that royalty “should not be so high as to stifle the emergence of a new domestic energy industry.” The BLM shares this concern and took steps to ensure that the initial royalty rate for oil shale production will encourage oil shale development consistent with the requirements of EP Act. The commenter went on to state that “increasing production costs, and massive R, D & D costs, and many taxes, all argue for a royalty rate well below 5%,” and therefore, the royalty regime should be simple, transparent, and easy to administer. The final rule establishes a flat, easy to administer 5 percent royalty rate for the first 5 years of commercial production and a transparent, simple to understand escalating rate of 1 percent after year 5 until it reaches a level comparable to the royalty rate on conventional crude oil (12 1/2 %). This royalty system should provide some royalty relief during the first years of capital intensive production activities. Flat Royalty Rate Equal to or Greater Than 5% The commenters who advocated a flat royalty rate equal to or greater than 5% stated that since the processes that will be used to develop oil shale are similar to the processes used to develop other solid minerals, the royalty rate for oil shale should be the same. The commenters who suggested a flat royalty rate greater than 5% asserted that the State of Utah has a royalty rate of 8% for asphaltic sands, uranium, and coal. Other commenters stated that “if royalty will be set, it should be 12.5%” because the “current royalty rate for conventional oil and gas is 12.5%.” The BLM did not adopt the suggestions of this group of commenters who advocated a flat royalty rate greater than 5%. First, an 8% royalty rate is not an accurate depiction of the royalty structure in Utah. The royalty rate for oil shale development in Utah begins at 5%, may increase annually after the first five years, and ultimately reaches 12 1/2 % at some point. The practical implications of the Utah royalty regime is also undetermined since, no production has occurred on any Utah State lease. Second, the BLM is concerned that an initial 12 1/2 % royalty rate may be a disincentive to oil shale development because it will discourage the much-needed capital investment in the industry. The BLM believes that the Utah royalty system is worthy of consideration and provides a comparable domestic royalty rate for oil shale development. If oil shale development succeeds on State lands in Utah, a similar Federal royalty system would appear to meet EP Act's objectives of encouraging development and providing a fair return to taxpayers. In the final rule, the BLM has chosen to adopt a royalty rate similar to Utah's by establishing an initial royalty rate of 5% during the first five years of production. Following five years of successful production, the rate will rise yearly by 1 percent until it reaches a level comparable to the royalty rate on onshore conventional crude oil. This will ensure that over the long-term the taxpayers are guaranteed a fair return, as required by EP Act, should oil shale development be economically viable. Sliding Scale Royalty Rate of 1-5% The commenters who advocated a sliding scale royalty rate of 1-5% stated that a 12 1/2 % royalty rate is too high. These commenters suggested that the oil shale industry is fundamentally a mineral extraction industry and should be viewed as such when establishing royalties. These commenters stated that the projects, related development, and operating costs associated with oil shale development are typical of mineral extraction industries (i.e., trona and potash). The commenters believe that due to the similarity of oil shale to other mineral extraction industries, the BLM should adopt a royalty rate of 1% of the producer's net return at the point of sale of the synthetic crude oil shale for the first 10 years of production. After 10 years, they suggested re-evaluating “the 1% rate to see if 3% net royalty would be appropriate with a transition step-up period of a 1% increase every 5 years to impose the 3% net rate after a 10 year transition period.” One commenter stated that if BLM adopts option 2 a 5% percent royalty on initial production with 12.5% thereafter that “there should be a floor at which royalties and annual minimum royalties are automatically suspended if WTI falls below $80” a barrel. The BLM reviewed the above suggestions and decided not to adopt them because while they seek to encourage development, they are difficult as well as costly to administer. Based on the BLM's analysis of comparable Btu values and production costs, we also do not believe rates lower than 5 percent represent a fair return to the United States. The BLM agrees with the commenters that a 12.5% royalty rate is too high if adopted as an initial rate. Also, the BLM did not adopt the suggestion that asks for a royalty rate of 1% on the producer's net return at the point of sale of the synthetic crude oil shale for the first 10 years of production “due to the similarity of oil shale to other mineral extraction industries.” First, experience shows that there is no similarity between oil shale extraction and the other extractive industries (trona and potash) cited by the commenter. Second, the estimated resource value of oil shale far exceeds the combined values of trona and potash. Given the economic potential of oil shale, it would be difficult to ensure a fair return to taxpayers if the royalty rate is set at 1% of net revenue. Another commenter stated that the “5 % royalty rate for option 1 and the 5% and 12.5% rates for option 2 are too high for a frontier resource.” The same commenter further stated that unlike coal or oil and gas, the government is providing access to a solid ore, and that the investor is responsible for adding value by recovering and converting the kerogen in the ore to oil. The commenter suggested setting a royalty rate of 1% for the first 6 years, and 5% thereafter with assurance from the government that the higher royalty rate of 5% would be implemented at a later date. The commenter added that “royalties should be suspended if the NYMEX crude oil prices fall below, say $60.” One commenter suggested that a better alternative would be a 1% royalty rate for the first 10 years, followed by 3% royalty thereafter, and concluded that “Alberta established a similar approach and has been successful.” This commenter stated that “if royalties are too high during the development phase, the startup costs will be too prohibitive and the resources won't be developed.” The BLM agrees that the oil shale industry is subject to high start-up costs and that the resources would not be developed without an economically viable technology. This technology could not be developed if costs become prohibitive. After careful consideration, the BLM does not agree with the idea of a starting royalty at 1% rate. The BLM's comparison of Btu values and production costs show a 1 percent rate to be too low. States and local governments share in Federal royalties and may view the lower rate (1% royalty rate) as not providing the revenue necessary to cover related infrastructure concerns and local community impact concerns. Furthermore, a royalty rate based on a sliding scale tied to NYMEX would be subject to frequent fluctuations thereby making it cumbersome and difficult for the MMS to administer. Sliding Scale Royalty Rate of 0-16.67% Some commenters advocated sliding scale royalty schemes ranging from 0% to 16.67%. One commenter specifically suggested that “reduced royalty rates should be conditioned on prices similar to OCS deepwater royalty incentives,” and stated that “there is no basis for a 12-year timeframe based on a reduced royalty rate that is not price sensitive.” Instead the commenter suggested that the royalty rate should be tied directly to NYMEX, and there should be no fixed timeframe. The same commenter gave an example that if NYMEX is below $60 a barrel the rate would be 5%, but when it exceeds $60 a barrel, it would be 12.5%. In the proposed rule, the suggestion for a reduced royalty rate for production that occurs within 12 years of the issuance of the first oil shale lease was meant to encourage speedy development, while providing some royalty relief during the costly up front years of development. However, the BLM did not adopt this provision in the final rule. The BLM also did not adopt the suggestion to tie the royalty to NYMEX prices because to do so would make royalty rates impracticable as well as cumbersome and costly for the BLM and MMS to administer. On the other hand, a 16.67% royalty rate will not encourage development, and without development, there will be no fair return to the taxpayers. To address comments that support a 16.67 percent royalty rate comparable to offshore rates, available information shows that shale oil production costs are much higher than costs of producing conventional crude oil. Yet, the maximum royalty rate for onshore oil and gas production is 12.5%. Given the cost differential, it would be a disincentive to production to set a higher royalty rate (16.67%) for a product that is costlier to produce. Another commenter suggested another alternative that would set the initial royalty rate at 2% or 2.5%, which would “increase to 12.5% once 30 million barrels of oil equivalent have been produced.” Then, the commenter concluded by stating “do not adopt a sliding scale since there are too many unknowns that could thwart development.” The BLM did not adopt this proposal because the initial 2% royalty rate is too low to ensure a fair return considering the available information on comparable resource values and production costs. The BLM has no information to determine whether the production of 30 million barrels of oil equivalent is relevant when establishing a higher rate. The final rule provides for an increasing royalty of 1 percent per year that is based on time, rather than on production. Another commenter stated that “it is difficult to comment with any confidence on the merits of various royalty rates without also knowing the parameters the lessor will use to value production from the lease, particularly for a mineral resource that have [sic] never been commercially produced and sold.” The commenter also stated that royalty “should not be so high as to stifle the emergence of a new domestic energy industry.” As stated previously, the MMS will address valuation issues in a future rulemaking, but will apply royalty to the amount or value of production. The BLM agrees with the commenter that the royalty rate should not be so high as to stifle the emergence of a new industry. This comment is consistent with a requirement of the EP Act that royalty be set in a manner that encourages development. One comment stated that Option 2 (base of 12.5% with a reduction to 5% for the first million barrels of oil equivalent of any lease that begins production within 12 years) is ill conceived. This commenter suggested the following two sliding scale options based on the following set of assumptions: Commenter's price-trigger option: First 5 years, rate is 0% with no adjustment based on price thresholds. After the first 5 years, the base rate is 1%; provided that the average daily closing NYMEX price for the calendar year exceeds $150 a barrel. The rate would increase to 3%; provided further that the average daily NYMEX closing price for the year exceeds $200 a barrel, the rate for production for that calendar year would be 5%. All prices would be indexed to 2008 levels. Commenter's production-trigger option: A 1% rate for the first 60 million BOE operating within the first 20 years of the lease; a 3% rate for the following 60 million BOE within the first 20 years of the lease; and a 5% rate for any volume of production above the 120 million BOE within the first 20 years of the lease. These production triggers would be subject to the same price thresholds outlined in the price trigger option above. Therefore, if crude prices exceed the prescribed levels, the rate would increase by 2 or 4% respectively. The commenter's options above are based on the assumptions that: (1) MMS valuation of the products from oil shale will be significantly less than the market price of the final refined products because MMS will account for manufacturing/processing allowances; (2) Lease production used on or for the benefit of the lease will not be subject to royalty; and (3) Royalties should not be assessed on by-products such as sulfur removed from the gas stream to meet air quality requirements and sold whether at a loss or a profit. Items transported off of the lease for recycling or disposal would not be considered products or by-products. These, including produced water, CO 2 , ammonia, etc., would not be royalty-bearing. The BLM considered and opted not to use this sliding scale option because the initial rates are too low (less than 5%) and such royalty schemes are not simple, transparent, or particularly easy to administer. The BLM also found no justification or rationale to support the price or production trigger thresholds. In addition, a zero percent royalty for the first 5 years of production would not provide a fair return to the United States. Other General Comments Commenters stated that it was important that royalty rates be consistent across ownerships in order to prevent oil shale development from concentrating on land with a lesser royalty rate. We agree with this comment. However, it must be recognized that, other than the State of Utah, there are no domestic royalty “rates” that apply to oil shale production. They also suggested that the BLM should adjust the royalty rate more frequently than the 20 year period in the proposed rule. The BLM cannot adjust lease royalty rates more frequently because the MLA authorizes the re-adjustment of royalty rates only after the initial 20 year term of a lease and every 20 years thereafter. The BLM can, however, change the regulatory royalty rate at any time should information become available that suggest the Federal rate is not comparable to rates on private or state lands. The new rates would apply to any lease issued or readjusted thereafter. Another commenter stated that the BLM based the rates in the rule on estimated production costs, but provided no support for the cost estimates that it used in the calculation. The production costs used in the proposed rule's calculations were obtained from the Strategic Unconventional Fuels Report ( America's Strategic Unconventional Fuels, Volume III ) prepared for Congress and the President. The Task Force that published those production costs was established by Congress under Section 369 of the EP Act. The same commenter suggested that the BLM defer the royalty rate determination until it has reliable information on the costs, recovery rate of technologies to be used on a lease, and the value of the product produced. The BLM disagrees with this suggestion because establishing a royalty rate early in the life of the oil shale industry provides the oil shale industry with the level of certainty necessary to obtain the capital investment required for oil shale development. Equally significant, delaying the establishment of a royalty regime until “reliable information on the costs, recovery rate of technologies to be used on a lease, and the value of the product produced” would not attract investment for oil shale development. The royalty rate is also a part of fair market value received by the United States and could affect bonus bids offered for leases. These comments appear to be inconsistent with Section 369 of the EP Act, which requires the Secretary to establish royalty rates in a manner that encourages development and ensures a fair return to the United States. Other comments were placed in the form of questions or general statements. Some of these questions/statements include: (1) Why is “complexity” inconsistent with “fair return?”; (2) “Any process that heats with electricity should be banned;” and (3) “There's one way to find out if 12.5% is too high. Put parcels up for bid based on 12.5% royalty and see if there are any takers.” The BLM examined the “complexity” issue and disagrees because, in practice, “complexity” can be inconsistent with “fair return.” The more complex the system, the more expensive and inefficient it is to administer and audit. A simple royalty regime promotes certainty and reduces the administrative costs (audit, compliance and reporting costs) better than a complex royalty scheme. The BLM did not agree with the comment which suggested banning any process that uses electricity to heat/produce oil shale, because the commenter failed to provide any scientific data or rationale to support their idea. All resource production requires energy. The BLM also believes that putting oil shale “up for bid based on 12.5% royalty and see if there are any takers” is an unnecessary expense or gamble. Such an option would not provide the certainty that industry seeks and could discourage the investment that is needed now to potentially make oil shale economically competitive in the future. One commenter asserted “specifically, the MLA says that the royalty is to be “not less than 12.5% in amount or value of the production removed or sold from the lease.” The BLM examined and disagrees with the assertion because the MLA does not establish a royalty rate for oil shale nor require that oil shale royalty be set at par with that of oil and gas. Instead, the EP Act directs the Secretary to establish a royalty rate for oil shale for the dual purposes of encouraging production and ensuring fair return to the United States. The BLM agrees that there is merit in eventually reaching royalty rate parity with that of onshore oil and gas, as reflected in the royalty system chosen for these final regulations. As noted elsewhere in this preamble, the BLM believes that an initial lower royalty rate on oil shale would be beneficial in spurring investment in developing the resource, consistent with the EP Act's direction. Another commenter suggested that no Federal royalty should be payable on spent shale, even if revenues are generated from the spent shale. This will encourage development of economic uses of spent shale and minimize onsite disposal costs. The BLM examined this comment and affirms its position that royalty is payable on products and by-products of oil shale produced and sold/removed from the lease. So, if in the future spent shale becomes a valuable product, the appropriate royalty will apply at that time. Oil Shale Production Royalties After careful consideration of the public comments discussed in this rule, the BLM determined that a royalty system similar to that of the State of Utah is best suited to meet the dual requirements of the EP Act to encourage production and to ensure a fair return to the United States. In the final rule, the production royalty for oil shale will have an initial rate of 5% through the first five years of commercial production and increase by 1% annually beginning in the sixth year of production until a maximum rate of 12.5% is reached in the 13th year. By establishing an initial royalty rate of 5% during the first five years of production, we are encouraging development as mandated by EP Act. Based on our analysis, this initial rate (1) reflects the production cost disparity between shale oil and crude oil production, (2) addresses the high start up costs associated with new infrastructure required for developing, refining, and transporting oil shale products, and (3) could promote higher bonus bids to defray socioeconomic impacts to states and counties. Following five years of successful production, the rate will eventually rise to a level comparable to the royalty rate on conventional crude oil. This will help to ensure that over the term of the lease the United States is guaranteed a fair return, as required by EP Act, should oil shale development be economically successful. A more certain royalty scheme, independent of the NYMEX indices, will lower administrative costs (lower audit, compliance and reporting cost) relative to a variable royalty rate tied to NYMEX. In summary, a low initial rate should encourage development and production during the early years when costs are high. As the technology becomes more efficient and cost effective the royalty rates will increase. If the costs to produce oil shale do not decrease, and operations become uneconomic, or marginally economic, royalty rate relief is available under section 3903.54. Whenever the Secretary determines it necessary to promote development or finds that the lease cannot be successfully operated under its terms, the Secretary may waive, suspend, or reduce the rental, or reduce the royalty, but not advance royalty, on an entire leasehold, or on any deposit, tract, or portion thereof, except that in no case can the royalty rate be reduced to zero percent. A lessee must apply for any of these benefits. As mentioned previously, the royalty rates can also be changed by regulation should future information indicate the need. Leases issued or readjusted after a regulatory change in the rate will be subject to the new rate. The MLA provides for readjustment of the royalty rate at the end of the 20th lease year and each 20 year period thereafter (see 30 U.S.C. 241). Section 3903.53 requires the filing of documentation of all overriding royalties associated with a lease and requires that the filing must occur within 90 days after the date of execution of the assignment. This section is similar to that of the BLM's other mineral leasing programs. A comment on the proposed rule pointed out that we do not define “overriding royalties.” Section 3903.53 of the final rule has been revised to clarify that an overriding royalty is a payment out of production to an entity other than the United States. Section 3903.54 contains the requirements for filing an application for waiver, suspension, or reduction of rental or payments in lieu of production, or a reduction in royalty, or waiver of royalty in the first 5 years of the lease. As with the BLM's other mineral leasing programs, this section is intended to encourage the maximum ultimate recovery of the mineral(s) under lease. The proposed rule's preamble erroneously mentioned a cost recovery fee that was not in the regulation text for the proposed rule. Therefore, in the final rule there is no cost recovery fee for this section. One comment indicated that there is some confusion regarding the distinction between a suspension or reduction in rental or royalty and a waiver of royalty. The authority for a suspension, waiver, or reduction of rental or a reduction in royalty is 30 U.S.C. 209 and applies to numerous minerals under the MLA including, but not limited to, coal, oil, gas, and oil shale. The authority for a waiver of the rental and royalty for the first 5 years under an oil shale lease is 30 U.S.C. 241 and only applies to oil shale. Section 3903.60 provides that late payments or underpayment charges are assessed under MMS regulations at 30 CFR 218.202. Subpart 3904—Bonds and Trust Funds Sections in this subpart address the requirements associated with bonding and trust funds, including the: (1) Types of bonds the BLM requires and when bonds would be required (section 3904.10); (2) When and where bonds would be filed (sections 3904.11 and 3904.12); (3) Acceptable types of bonds (section 3904.13); (4) Individual lease, exploration license, and reclamation bonds (section 3904.14); (5) Amount of bond coverage (section 3904.15); (6) Default (section 3904.20); and (7) Long-term water treatment trust funds (section 3904.40). Since all of the BLM's mineral leasing programs require bonds, the requirements in subpart 3904 are similar to the regulatory provisions in the BLM's other mineral leasing programs. The bonding requirements in this rule are similar to the bonding requirements under the BLM's mining law program in that both programs require that bonds cover the full cost of reclamation and allow for the use of long-term trust funds as a mechanism to address potential long-term water issues. Bonding ensures performance at a cost up to the bond amount in the event of default by a lessee or licensee. This subpart requires two types of bonds; a lease or exploration license bond and a reclamation bond. This subpart also explains that reclamation bonds will be required to be in an amount sufficient to cover the entire cost of reclamation of the disturbed areas as if they were to be performed by a contracted third party. Section 3904.10 provides that prior to lease or exploration license issuance, the BLM requires a lease or exploration license bond for each lease or exploration license to cover all liabilities on a lease, except reclamation, and all liabilities on a license. One commenter requested an explanation of what liabilities the lease bond covers. A lease bond covers the lessee's compliance with the terms and conditions of the lease and will be calculated to cover payments for rental, minimum or production royalty, outstanding bonus bid payments, and assessments. The bond also could be used to cover any other payments required of the lessee that are associated with noncompliance with the terms and conditions of the lease. The bond will be executed by the lessee and will cover all record title owners, operating rights owners, operators, and any person who conducts operations on or is responsible for making payments under a lease or license. This section also requires the lessee or operator to file a reclamation bond to cover all costs the BLM estimates necessary to cover reclamation on a lease. Section 3904.11 requires the prospective licensee, lessee, or operator to file a lease bond prior to issuance of a lease, file a reclamation bond prior to approval of a POD, and file an exploration bond prior to exploration license issuance. This section is similar to other BLM bonding regulations as it would require the filing of a bond before liabilities may accrue. We received a comment requesting a revision to section 3904.11 clarifying when a lease bond is filed. Section 3925.10 of the rule provides that the successful bidder will submit a bond as a condition of lease issuance. Therefore, no change is made to section 3904.11 in the final rule. A commenter requested that the regulation provide that bonds be “a condition of” issuance of licenses or leases, or of approval of PODs. We did not change the section because proof of bond coverage is a pre-condition to issuance or approval of those documents. We revised this section in the final rule to make it clear that submission of a bond is a condition precedent of the approvals mentioned in the section. Section 3904.12 requires that a copy of the bond with original signatures be filed in the proper BLM office, and section 3904.13 describes the different types of bonds that the BLM will accept. Section 3904.13 addresses the types of personal and surety bonds the BLM will accept. Personal bonds are limited to pledges of cash, cashier's checks, certified checks, or U.S. Treasury bonds. The BLM state offices have available for public review a Treasury Department list of qualified sureties for bonds. We received several comments requesting that the types of personal bonds that will be accepted should be expanded. We believe that the number and types of bonds available to lessees and licensees are varied enough to provide flexibility and accessibility to all holders. Section 3904.14 provides that the BLM will establish bond amounts on a case-by-case basis, and sets the minimum lease bond amount at $25,000. One comment expressed concern that $25,000 is an inadequate minimum bond amount. The actual bond amount for a lease, as opposed to the minimum bond amount, will be calculated each year to cover the rental payments, minimum royalty, outstanding bonus payments, assessments, if applicable, and other payments that are due for the lease. The minimum lease bond amount, established by the regulations, however, is greater than that required in other BLM mineral leasing programs. The BLM chose this higher minimum bond amount to insure coverage of unpredictable lease liabilities due to the unknown nature of future oil shale development and the likelihood of large, outstanding bonus bid payments. In addition to the lease bond, the reclamation bond amount and the bond amount for a license will be calculated to cover actual reclamation costs. Reclamation and exploration bond amounts will be established to cover the costs of reclamation as if it were to be performed by a contracted third party. Past oil shale operations have required extensive reclamation, and this has demonstrated the need to have a reclamation bond that covers the full cost of reclamation. By requiring that the bond equal the estimated costs of having a third party perform the reclamation, the BLM anticipates that the cost of reclamation will be covered. This section also provides that the BLM may enter into agreements with states to accept a state-approved reclamation bond to satisfy the BLM's reclamation requirements and protect the BLM, to the extent the bond is adequate to cover all the operator's liabilities on Federal, state, and private lands. This avoids duplicate procedures and the inconvenience and cost of filing separate bonds with both the state and the BLM. Such agreements were recommended by state representatives at the BLM listening sessions and are also addressed in regulatory provisions of other BLM mineral leasing programs. We received a comment suggesting that this section should provide for the establishment of an escrow account or trust fund as an option to replace bonding as a method of insuring reclamation. With the exception of special circumstances, as outlined in section 3904.40 of this rule, the BLM believes that requiring escrow accounts or trust funds would impose unnecessary costs on lessees as well as additional administrative costs to the BLM while offering no advantage to ensure that funds will be available in case the lessee or licensee cannot meet reclamation obligations. Although these rules will not specifically provide for escrow accounts or trust funds, as suggested by the commenter, state approved reclamation rules may allow for them. In these cases, and where the BLM has an agreement with the state, the BLM will indirectly accept escrow accounts and trust funds, but the state will be responsible for managing them. Section 3904.15 explains that the BLM may increase or decrease the bond amount if it determines that a change in coverage is warranted to cover the costs and obligations of complying with the requirements of the lease or license and these regulations. This section also explains that the BLM will not decrease the bond amount below the minimum established in section 3904.14(a). This section requires the lessee or operator to submit a revised estimate of the reclamation costs to the BLM every three years after reclamation bond approval. If the current bond does not cover the revised estimate of the reclamation costs, the lessee or operator would be required to increase the reclamation bond amount to meet or exceed the revised cost estimate. This section is consistent with the bonding regulations that currently exist for other BLM minerals programs. A commenter requested a revision to section 3904.15 to require the BLM to audit cost estimates provided by lessees or operators under this section. In the final rule we revised section 3904.15 to state that the BLM will verify the cost estimates provided by the lessee or operator. A commenter proposed changes to provide for incremental bonding. We did not revise the rule because this section allows the BLM to increase or decrease bond amounts as the need for coverage changes. This allows for incremental bonding where appropriate. Section 3904.20 describes what actions the BLM will take in the event of a default payment from a lease, exploration, or reclamation bond to cover nonpayment of any obligations that were not met. It also requires the bond to be restored to the pre-default level. This section is similar to sections in the other BLM mineral re [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3AE8-27025. Public record. Not legal advice.