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Geothermal Royalty Payments, Direct Use Fees, and Royalty Valuation

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AGENCY:

Minerals Management Service (MMS), Interior.

ACTION:

Final rule.

SUMMARY:

The MMS is promulgating new regulations to implement the provisions of the Energy Policy Act of 2005 (EPAct) governing the payment of royalty on geothermal resources produced from Federal leases and the payment of direct use fees in lieu of royalties. The EPAct provisions amend the Geothermal Steam Act of 1970 (GSA). The new regulations amend the current MMS geothermal royalty valuation regulations and simplify the royalty and direct use fee calculations for geothermal resources for leases issued under the EPAct and leases whose terms are modified under the EPAct. The new regulations also amend various related provisions in the MMS rules.

EFFECTIVE DATE:

June 1, 2007.

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FOR FURTHER INFORMATION CONTACT:

Sharron Gebhardt, Lead Regulatory Specialist, Minerals Revenue Management (MRM), MMS, telephone (303) 231-3211, fax (303) 231-3781, or e-mail sharron.gebhardt@mms.gov. The principal authors of this rule are Sarah L. Inderbitzin and Herb Black of MRM, MMS, Department of the Interior.

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SUPPLEMENTARY INFORMATION:

I. Background

A. Pre-EPAct Statutory Provisions and Existing Regulations

The existing rules applicable to geothermal resources were promulgated in 1991 under the GSA (30 U.S.C. 1001 et seq.) before its amendment by the EPAct (Pub. L. 109-58, 119 Stat. 594). The current royalty valuation methods for geothermal resources are grouped first by usage, i.e., electrical generation, direct use, and byproducts. Within each usage category, valuation methods are grouped by the method of disposition of the resources, i.e., arm's-length (unaffiliated) sales, non-arm's-length sales, and no sales.

The Secretary of the Interior established the Royalty Policy Committee (RPC) on August 1, 1995, in accordance with Public Law 92-463, Federal Advisory Committee Act, dated October 6, 1972. The RPC convened its first meeting in Denver, Colorado, on September 12-13, 1995.

The mission of the RPC is to provide policy advice representing the collective viewpoint of the states, Indians, mineral industry, and other parties to the Secretary of the Interior through the Director of the Minerals Management Service (MMS) and other officers of the Department of the Interior. This policy advice concerns the performance of discretionary functions involved in the Department's management of Federal and Indian mineral leases and revenues. The RPC reviews and comments on royalty management and other mineral-related policies and provides a sounding board to convey views representative of mineral lessees, operators, revenue payors, recipients, governmental agencies, and the interested public. The RPC may establish subcommittees or workgroups as it deems necessary for the purposes of compiling information or conducting research. Subcommittees or workgroups may not conduct business independent of the RPC and must report its recommendations to the full RPC for consideration. Subcommittees or workgroups meet as necessary to accomplish their assignments, subject to the approval of the RPC Chairperson.

On October 28, 2004, the RPC formed the Geothermal Valuation Subcommittee (Subcommittee) to address the MMS geothermal royalty valuation regulations to simplify the regulations and reduce administrative costs to the geothermal industry. The Subcommittee was comprised of members from one industry association, several geothermal producers, two of the major States affected, and MMS employees. A representative of the Bureau of Land Management (BLM) served as technical advisor to the Subcommittee. The RPC requested that the Subcommittee work together to develop more efficient royalty valuation methods that will ensure a fair return to the Federal Government as well as encourage geothermal development. The Subcommittee prepared a report and submitted it to the RPC; and on May 26, 2005, the RPC accepted the Subcommittee's recommendations.

B. The EPAct

On August 8, 2005, the President signed into law the EPAct, Pub. L. 109-58, 119 Stat. 594. Sections 221 through 237 of the EPAct, entitled the “John Rishel Geothermal Steam Act Amendments,” amended the GSA, 30 U.S.C. 1001 et seq. (1970). Congress enacted the EPAct geothermal amendments to encourage geothermal production through regulatory streamlining and incentives. S. Rep. No. 78, 109th Cong., 1st Sess. (2005).

C. The Proposed Rule

On July 21, 2006, MMS published a proposed rule in the Federal Register (71 FR 41516) that addressed implementing the EPAct provisions. It also incorporated most of the Subcommittee's concepts, with modifications necessary to comply with the EPAct.

For 30 CFR part 206, subpart H, we: (1) Explained the general royalty calculation and payment, direct use fee, and royalty valuation provisions of this subpart; (2) defined which leases the subpart applies to; (3) provided definitions of terms used in the subpart; (4) proposed some changes to conform to plain English writing; and (5) proposed changes necessary to implement provisions of the EPAct.

For 30 CFR parts 202, 210, and 218, we proposed changes necessary to implement provisions of the EPAct and reflect the proposed amendments to 30 CFR part 206, subpart H.

II. Comments on the Proposed Rule

The MMS received comments on the proposed rule from two States, one trade association, and two geothermal producers. These comments are analyzed and discussed below:

A. 30 CFR Part 202—Royalties

1. 202.351(a)(2)(ii) Royalties on geothermal resources

Public Comments: The trade association commented that the definition of “gross proceeds” in § 206.351 of the proposed rule should state that “station usage power (including auxiliary load) * * * are not included [in the gross proceeds].”

MMS Response: The MMS specifically stated in proposed § 202.351(b)(2)(ii) that it “will allow free of royalty or fees a reasonable amount of geothermal energy necessary to generate electricity for internal power plant operations or to generate electricity returned to the lease for lease operations” (71 FR 41531). We believe that § 202.351(b)(2) would allow a lessee to use a reasonable amount of station usage power royalty free. Therefore, we did not include it in the definition of “gross proceeds” in § 206.351.

However, § 202.351 has been revised in the final rule in several respects to better reflect the new basis for royalty for leases issued under the EPAct (and leases whose royalty terms are converted to EPAct terms under the BLM final rule). Under 30 U.S.C. Start Printed Page 244491004(a)(1), a lease issued under the EPAct whose geothermal resource production is used for commercial production or generation of electricity must provide for a royalty as a specified percentage of the gross proceeds from the sale of the electricity. The royalty under such leases is no longer imposed on the volume of geothermal resources produced; it is imposed only on the proceeds derived from sale of the electrical energy, regardless of the volume used to generate the electricity.

In paragraph (a) of § 202.351, MMS has modified the proposal to clarify that royalties on electricity produced using geothermal resources will be at the royalty rate specified in the lease. Similarly, in paragraph (b)(1), MMS has added language to clarify that royalties are due on all proceeds derived from the sale of electricity generated using the geothermal resources produced from a lease.

We have made a number of clarifying changes to proposed paragraph (b)(2). Paragraph (b)(2) of the proposed rule identified certain volumes of geothermal resources that would be free of royalty or direct use fees—namely, (1) unavoidably lost resources and resources reinjected before use; (2) resources used to generate “electricity for internal power plant operations” (referred to in the final rule as “plant parasitic electricity,” which is defined in a revised definition in § 206.351); (3) resources used to generate electricity returned to the lease for lease operations (referred to in the final rule as “electricity for Federal lease operations”); and (4) commercially demineralized water necessary for power plant operations or otherwise used on or for the benefit of the lease.

The relevance and consequences of these volume categories are different depending on the legal category of the lease involved and the use of the geothermal resources produced from the lease. The different legal categories to which a lease may belong are defined in § 206.351 of the final rule. As more fully prescribed in that section, “Class I leases” are leases issued before the date of enactment of the EPAct (or in response to an application pending on that date) which the lessee does not convert to EPAct terms. “Class II leases” are leases issued after the date of enactment of the EPAct (except for leases issued in response to an application pending on that date which the lessee does not convert to EPAct terms). “Class III leases” are leases issued before the date of enactment of the EPAct that the lessee converts to EPAct royalty terms. Paragraph (b)(2) in the final rule addresses what is free of royalty or direct use fees first by the legal category of the lease and then by the use of the resource.

Clause (i) of paragraph (b)(2) addresses Class I leases, which are covered by the existing rule. This paragraph preserves the existing rule's treatment for royalty purposes of each of the volume categories identified above—i.e., that all of them are free of royalty. The determination of the reasonable amount of the resource used to generate plant parasitic electricity under a Class I lease is subject to MMS jurisdiction. (Commercially demineralized water is relevant only under Class I leases, and therefore is not mentioned in the subsequent clauses addressing Class II and Class III leases.)

Clause (ii) of paragraph (b)(2) addresses Class II leases and Class III leases (leases with EPAct royalty terms) whose geothermal resources are used for the commercial production or generation of electricity or are sold at arm's length for the commercial production or generation of electricity. For these leases, if the lessee sells electricity on the commercial market, the lease provides for royalty as a percentage of gross proceeds derived from sale of the electricity. Unavoidably lost or reinjected resource volumes and volumes associated with generating plant parasitic electricity or electricity for lease operations do not result in generation of any electricity that is sold. It follows that there are no gross proceeds from the sale of electricity that result from them. Therefore, these volumes have no royalty consequence.

However, under a Class II lease or Class III lease, if the lessee sells the geothermal resource at arm's length before commercial production or generation of electricity, under the final rule royalty is a function of the gross proceeds derived from the sale of the resource. To the extent that any loss of resources is avoidable, MMS would require the lessee to pay royalties on that volume. Thus, it is appropriate to clarify that only unavoidably lost or reinjected volumes are not royalty-bearing. MMS will also allow free of royalty a reasonable amount of resource volumes used to generate electricity for Federal lease operations. (There is no plant parasitic electricity if the lessee sells the resource and, therefore, no resources are used to generate it.)

The existing rule and the proposed rule refer to electricity “returned to the lease for lease operations.” In the final rule, the phrasing of the term has been clarified to “electricity for Federal lease operations.” First, it is not necessary that this electricity be generated off the lease and then “returned to the lease.” Second, MMS wishes to clarify that resources used to generate electricity for non-Federal (e.g., state or private) lease operations are not royalty-free. Approval of the amount of resources used to generate electricity for lease operations that is royalty-free is subject to BLM, rather than MMS, jurisdiction.

In addition to the royalty effects discussed above, the rule must also address the question of what resources, if any, might be subject to direct use fees. Under 30 U.S.C. 1001(g), the term “direct use” means “utilization of geothermal resources for commercial, residential, agricultural, public facilities, or other energy needs other than the commercial production of electricity.” The definition of the term “direct use” in the final rule at 30 CFR 206.351 is essentially identical. Section 206.351 then defines the term “commercial production or generation of electricity” to include the electricity or energy that is reasonably required both to produce the resource and to convert geothermal energy into electrical energy for sale. This definition includes the generation of both plant parasitic electricity and electricity for lease operations, as well as other uses of resources for lease operations. Therefore, where the lessee of a Class II lease or Class III lease sells electricity commercially, use of resources for these purposes, by definition, does not constitute a direct use under the final rule. The resources therefore are not subject to direct use fees.

The text of clause (ii) covers each of the situations and consequences described above.

Clause (iii) addresses direct use fees when the geothermal resources produced from a Class II lease or Class III lease are used for direct use purposes other than commercial production or generation of electricity, as those terms are defined in 30 CFR 206.351. It is appropriate to allow unavoidably lost and reinjected resource volumes to be free of direct use fees because they are not used and are not avoidably lost. However, because generating electricity for direct use lease operations falls within the definition of “direct use” under § 206.351, a direct use fee will be imposed on the associated volumes.

2. 202.353 Measurement standards for reporting and paying royalties

Public Comments: One State commented that proposed § 202.353, which adds a new paragraph requiring reporting to the “nearest whole million” for direct use leases, “could encourage a lessee to control its incremental production to avoid royalties.” The State recommended “eliminating it.” Start Printed Page 24450

MMS Response: In the proposed rule, the MMS proposed to change the existing rule, at § 202.353(b)(2), which requires reporting to the “nearest hundred gallons” to require reporting to the “nearest million gallons.” The MMS also proposed to add a new subparagraph 202.353(b)(3), which states that lessees may report the quantity of direct use resources in “millions of pounds to the nearest million pounds of geothermal fluid produced if valuation is in terms of mass.” The MMS used millions of gallons because that is the volume measurement the Royalty Policy Committee (RPC) Geothermal Valuation Subcommittee recommended for the fee schedule. In addition, the MMS added the “millions of pounds” and changed to the “millions of gallons” to conform to the fee schedule we proposed in § 206.356. Therefore, we are not eliminating the requirement to report to the “nearest whole million.” In addition to this change, we have reformatted this section to make it easier to use.

B. 30 CFR Part 206—Product Valuation, Subpart H—Geothermal Resources

1. 30 CFR 206.351 What definitions apply to this subpart?

Definition of Class I, II, and III Leases

MMS did not receive any comments on its definition of the classes of leases subject to this rulemaking. However, after consultation with BLM, MMS determined that its definitions did not accurately reflect the royalty rate or direct use fees terms of the BLM regulations for each class of leases. Therefore, to clarify the classes of leases and be consistent with BLM regulations, we are changing the description of the lease classes in this final rule.

For Class I leases, we have eliminated any cross-references to “Class II” leases and clarified in part (1) that a conversion under 43 CFR 3212.25 relates to converting royalty rate terms. Thus, in the final rule, a Class I lease means:

(1) A lease that BLM issued before August 8, 2005, for which the lessee has not converted the royalty rate terms under 43 CFR 3212.25; or

(2) A lease that BLM issued in response to an application that was pending on August 8, 2005, for which the lessee has not made an election under 43 CFR 3200.8(b).

For Class II leases, in MMS's proposed rule, we inadvertently omitted a category of leases that qualify as “Class II.” The proposed rule defined Class II leases as only those leases BLM issues on or after the effective date of the final BLM regulation under 43 CFR subparts 3203, 3204, or 3205. However, a lease that BLM issued in response to an application that was pending on August 8, 2005, either before or after the date of the final BLM regulation, for which the lessee has made an election under 43 CFR 3200.8(b), is also a “Class II” lease. Therefore, we modified the Class II definition to capture all eligible leases issued after August 8, 2005. So, in the final rule, a Class II lease means:

A lease that BLM issued after August 8, 2005, except for a lease issued in response to an application that was pending on August 8, 2005, for which the lessee does not make an election under 43 CFR 3200.8(b).

With respect to Class III leases, in our proposed rule, we stated that a “Class III lease means a Class I lease that the lessee converts to a Class II lease under 43 CFR subpart 3212.” (Emphasis added.) However, that definition misstated the leases to which it applied in two ways. First, only lessees of Class I leases that BLM issued before August 8, 2005, can convert the royalty terms of their leases under 43 CFR 3212.25. Lessees of leases that BLM issued in response to an application that was pending on August 8, 2005, for which the lessee has not made an election under 43 CFR 3200.8(b), could not convert the royalty terms of their leases under 43 CFR 3212.25 even though they are Class I leases. Therefore, the definition of Class III leases in the proposed rule referring to all Class I leases was inaccurate. Second, contrary to the definition in the proposed rule, a Class III lease would not convert to a Class II lease. Indeed, the royalty terms of a Class II lease are different from those of a Class III lease that BLM issued before August 8, 2005, for which the lessee has converted to the royalty rate or direct use fee terms under 43 CFR 3212.25. In other words, Class III leases have different royalty terms (including direct use fees in lieu of royalties) than Class II leases. Thus, the definition in the proposed rule stating that Class III leases were converted to Class II leases was incorrect.

Accordingly, in the final rule, a Class III lease means:

A lease that BLM issued before August 8, 2005, for which the lessee has converted to the royalty rate or direct use fee terms under 43 CFR 3212.25.

The lessee of a Class III lease may also elect, under 43 CFR 3200.7(a)(2), to be subject to all of the BLM regulations for leases issued after August 8, 2005.

Definition of Direct Use

Public Comments: One commenter observed that both MMS and BLM have definitions of direct use but defined the term to include “generation” in “slightly different ways.” The commenter suggested that MMS and BLM agree on one definition.

MMS Response: In section 236 of the EPAct (adding 30 U.S.C. 1001(g)), Congress defined direct use to mean the “utilization of geothermal resources for commercial, residential, agricultural, public facilities, or other energy needs other than the commercial production of electricity” (emphasis added). In the proposed rule, we proposed to use that definition, but substitute the word “generation” for “production” because Congress did not define the term commercial production of electricity. 71 FR 41518. As we explained in the preamble to the proposed rule:

Other sections of the EPAct (see the new 30 U.S.C. 1004(b), added by EPAct section 223(a), and new 30 U.S.C. 1003(f), added by EPAct section 223(b)) use the term commercial generation of electricity. The two terms appear from the statutory context to have the same meaning. Therefore, commercial production or generation of electricity would mean generation of electricity that is sold or is subject to sale, including the electricity that is required to convert geothermal energy into electrical energy for sale.

Id. However, as the result of a clerical error, MMS proposed to define the term as only “the commercial generation of electricity,” whereas BLM defined it to include “commercial production or generation of electricity” (43 CFR 3200.1) (71 FR 41543). To be consistent, we are changing the definition in the final rule to conform to BLM's definition and include the term “commercial production or generation of electricity” (emphasis added).

Definition of Gross Proceeds

Public Comments: As discussed above, the trade association commented that the definition of gross proceeds in 30 CFR 206.351 of the proposed rule should state that “station usage power (including auxiliary load) and wheeling and transmission charges * * * are not included [in the gross proceeds].”

MMS Response: As discussed above, § 202.351(b)(2) would allow the use of station usage power royalty-free. However, the definition of gross proceeds in our geothermal regulations has never included wheeling and transmission charges as part of gross proceeds. In the 1991 final rule, wheeling and hydrogen sulfide abatement were deleted from the definition “because these operations are associated with utilization of the geothermal resource rather than production; any reimbursements the lessee receives for these operations Start Printed Page 24451would be deducted from the lessee's costs of performing them when calculating the transmission and generating cost rates under the netback procedure” (58 FR 57271). In the proposed rule at § 206.352(b)(1), we explained that lessees who are currently using the netback method who choose not to convert to the EPAct royalty terms will continue to be allowed to deduct transmission and generating allowances, including wheeling charges. However, as we explained in the preamble to the proposed rule, such charges are not excluded from the definition of gross proceeds because lessees who do convert to the EPAct royalty terms will have a royalty rate that accounts for the previous transmission and generating deductions in order to remain revenue neutral (71 FR 41519). Therefore, MMS is not changing the definition of gross proceeds in the final rule.

In the final rule, MMS has modified the definition of “commercial production or generation of electricity” to clarify that the term includes electricity or energy that is required to produce the resource, as well as that required to convert the resource into electrical energy for sale. This was MMS's intent in the proposed rule. This term is important in determining whether geothermal resource production is subject to royalties or direct use fees, as explained more fully in the preamble to the final BLM rule. The revised definition is consistent with the definition in the BLM final rule.

In the definition of “plant parasitic electricity” in the final rule, MMS has specified that it means electricity used to operate a power plant that is used for commercial production or generation of electricity. Plant parasitic electricity does not include electricity generated to power a direct use operation. (The term “plant parasitic electricity” is actually used only in 30 CFR 202.351, the provision addressing which geothermal resources are free of royalty and direct use fees. It is not used in part 206. However, it is more efficient to define it in part 206, together with other related terms that are used in both part 206 and part 202, and which part 202 incorporates by reference to the part 206 definitions.)

2. 30 CFR 206.352 How do I calculate the royalty due on geothermal resources used for commercial production or generation of electricity?

Public Comments: One State commented that because paragraphs (b)(2) and (b)(3) do not allow any deductions from gross proceeds, it creates an ambiguity because the definition of gross proceeds in § 206.351 does not also state there are no deductions from gross proceeds. The State also expressed concern that the proposed rules “appear to imply that royalties can be determined by the ‘netback’ method for arm's length transactions” and suggested that we clarify that the “netback method” only applies to current leases. One producer commented that it was unsure how to value geothermal production when it is sold directly to the ratepayers. The commenter believes that the only valuation options would be to request an alternative valuation methodology or convert the leases to direct use leases and pay fees in lieu of royalties.

MMS Response: Although lessees may not take deductions from their gross proceeds under paragraphs (b)(2) and (b)(3) of this section, as explained above, in proposed § 206.352(b)(1), lessees who are currently using the netback method who chose not to convert to the EPAct royalty terms will continue to take transmission and generating deductions from their gross proceeds. Therefore, MMS is not changing the definition of gross proceeds in the final rule.

With respect to the comment that the proposed rule implies that the netback calculation applies to royalty calculations for arm's-length transactions, § 206.352(a) clearly states that for geothermal resources purchased “at arm's length that the purchaser uses to generate electricity, then the royalty on the geothermal resources is the gross proceeds accruing to you from the sale of the geothermal resource to the arm's-length purchaser multiplied by the royalty rate in your lease or that BLM prescribes or calculates under 43 CFR 3211.17.” Therefore, MMS sees no need for clarification regarding the netback method and arm's-length situations.

With respect to how to value geothermal resources when electricity is sold directly to ratepayers (consumers of the electricity), rather than the typical situation where the lessee sells electricity under an arm's-length contract to a utility, we are assuming that the sales to the ratepayers are also arm's length. We are further assuming that the lessee would have contractual agreements with the ratepayers for the sales of electricity. In that instance, the gross proceeds would be the combination of the sales to multiple ratepayers. The same would hold true if a lessee sold electricity to multiple utilities. Therefore, the lessee would pay under § 206.352(b)(1). Of course, the commenter is correct that the lessee could request a value or gross proceeds methodology under § 206.364. However, the lessee could not convert to a direct use fee lease. The fee schedule is only for direct use of a geothermal resource that is not used for commercial electrical generation purposes.

3. 30 CFR 206.353 How do I determine transmission deductions? and 30 CFR 206.354 How do I determine generating deductions?

Public Comments: One commenter objected to our proposal to amend §§ 206.353 and 206.354 by deleting paragraph (f) of those sections. That paragraph provided for a one-time refund of royalties based on the royalty percentage of actual dismantlement costs of transmission lines and power plants in excess of income from salvage at the completion of dismantlement and salvage operations. The commenter stated that the MMS explanation that this provision has never been used did not take into account that geothermal power plants are relatively new and last many years “such that no plant or transmission line has ever been dismantled.” The commenter believes that elimination of the refunds would have a “potentially significant financial impact in the future and remove the incentive intended to ensure such actions are taken * * *.”

MMS Response: With respect to dismantlement costs, the preamble to the existing rule discussed the rationale for allowing a refund:

The MMS recognizes that the costs of dismantling, decommissioning, or abandoning the power plant and/or transmission line are indeed part of the lessee's costs associated with those facilities. However, these are future costs that are not easily estimated tens of years in advance, and in fact may not even occur at the end of a given project if the facilities are converted to other uses. Nevertheless, it is MMS' intent to recognize power plant and transmission line dismantlement costs when those costs actually occur. This will be accomplished by allowing the lessee a one-time refund of royalty equal to the royalty amount of actual dismantlement costs in excess of actual salvage income (i.e., royalty rate times the amount of dismantlement costs in excess of salvage income) * * * (56 FR 57256, 57263).

As the commenter noted, the main reason this refund has not been used is the lack of geothermal power plant dismantlements. The intent of the proposed rule was not to change the existing regulations substantively so that lessees who stay under the existing regulations will continue paying royalties as they are now. Therefore, MMS is reinstating the dismantlement costs refund as it is in the existing regulations at §§ 206.353(f) and 206.354(f), rewritten in plain English. Start Printed Page 24452

In the final rule, MMS has changed a provision of § 206.353(b)(1) regarding determination of transmission line costs that corrects an inadvertent inconsistency in both the existing rule and the proposed rule. The existing rule (at § 206.353(b)(1)) and the proposed rule (at § 206.353(b)(1)(ii)) both provide that the lessee must redetermine the transmission line cost rate annually, beginning either at the same month of the year in which the transmission line was placed into service, the same month of the year in which the power plant was placed into service, or at a time coinciding with the beginning of the lessee's annual corporate accounting period. Both the existing rule and the proposed rule then provide that the period selected must be the same period used in redetermining the generating cost rate under § 206.354(b)(1).

However, § 206.354(b)(1) (in both the existing rule and the proposed rule) does not provide an option for redetermining the generating cost rate beginning at the same month of the year in which the transmission line was placed into service. It provides only for either the same month of the year in which the power plant was placed into service or at the beginning of the lessee's annual corporate accounting period. Thus, it is not possible to elect to redetermine the transmission line cost rate beginning at the same month of the year in which the transmission line was placed into service, and no lessee attempted to do so. For these reasons, the final rule eliminates this option.

The proposed rule, at § 206.353(h), provided that to compute depreciation for a transmission line (as part of calculating actual transmission line costs), the lessee could elect to use either a straight-line depreciation method based on the life of the equipment or on the life of the reserves that the transmission line services, or a return on capital investment method. This proposed provision would have changed the requirement in the existing rule (at § 206.353(b)(2)(iv)(A)) to compute depreciation using a straight-line method based on the life of the geothermal project (usually the term of the electricity sales contract) or other depreciation period acceptable to MMS. There was no discussion or explanation of this provision in the preamble to the proposed rule. It is uncertain how the change in language arose, because MMS intended no change in the existing provision.

Further, the proposed rule in the same paragraph omitted language in the existing rule to the effect that a change in ownership of a transmission line does not alter the depreciation schedule established by the original lessee-owner for purposes of determining transmission line costs. Again, MMS intended no change in the existing rule in this regard. Both of these errors are corrected in § 206.353(h) of the final rule.

A similar unexplained change appeared in the depreciation provisions of the proposed rule for calculating generating deductions at § 206.354(h). The proposed rule would have added to the existing rule (at § 206.354(b)(2)(iv)(A)) an option to compute depreciation on a unit-of-production method. This does not appear to be appropriate in the geothermal context. The proposed rule again omitted language in the existing rule regarding a change in ownership of the power plant not altering the original depreciation schedule. Both of these errors have been corrected in the final rule.

4. 30 CFR 206.356 How do I calculate royalty or fees due on geothermal resources I use for direct use purposes?

Public Comments: Two commenters objected to MMS's minor modifications to the fee schedule proposed by the Subcommittee. Specifically, a commenter requested that MMS eliminate the efficiency factor in the denominator of the equation for calculating fees, and one commenter objected to the increase in fees in the proposed schedule from the schedule the Subcommittee recommended. Another commenter stated that, under the proposed rule, a lessee could not produce electricity from a Class III lease.

MMS Response: With respect to the efficiency factor, MMS used the same formula as the Subcommittee, which included the efficiency factor. The Subcommittee used the efficiency factor because:

Valuation using coal, wood chips, or natural gas is based on “displaced energy,” where the binary valuation is based on “extracted energy.” Displaced energy uses an efficiency factor to account for heat lost during the combustion of the alternative fuels. The efficiency factor typically adds 25 percent to 33 percent to the value of those fuels.

Royalty Policy Committee Geothermal Valuation Subcommittee Report (May 2005), Attachment 3, page 2.

If we eliminate the efficiency factor from the formula, it would erroneously assume that the use of geothermal resources for direct use purposes is 100 percent efficient. Because the direct use of geothermal energy is not 100 percent efficient, MMS will keep the efficiency factor to account for heat lost during the direct use of geothermal resources.

With respect to the increase in fees in the proposed schedule from the fees in the Subcommittee Report, the Subcommittee recommended using Powder River Basin coal prices to determine what a Btu of heating energy was worth. That measure was to be used in calculating royalty owed on geothermal resources used in direct use projects and not sold. Powder River Basin coal prices had been relatively stable for some time. However, the Subcommittee contemplated that MMS would change the fee schedule from time to time. In the interim between the Subcommittee Report and publication of the proposed rule, Powder River Basin coal prices increased. The MMS believes it is eminently reasonable to update the fee schedule to reflect current coal prices, rather than past prices. Thus, we will retain the proposed fee schedule.

It is possible that a lessee of a geothermal lease may use the geothermal resource first to produce electricity and then either sell or use the still-hot water for direct use in another operation. (This is sometimes known as “cascading.”) Cascading is a process in which the user gains the use of the heat after its use by the same or a different party who is using the higher-grade geothermal resource to generate electricity. As we stated in the preamble to the final 1991 geothermal rule, “the issue of royalties due on geothermal resources utilized in cascading steps is straightforward: the lessee is responsible for paying royalty on the total thermal energy yielded by the resource” (56 FR 57268). The MMS believes that this philosophy also is consistent with the intent of Congress in the EPAct.

The MMS knows of two operations that involved “cascading” in the past, but there appears to be no current operation that involves a second use of the resource after commercial generation of electricity. Nevertheless, such a situation may arise again in the future, and MMS therefore has addressed this issue here.

Thus, for example, assume that the lessee uses the geothermal resource to generate electricity. Also assume that the lessee then uses the still-hot geothermal resource, after it is used in the plant for electrical generation, in a direct use operation. In that instance, as with the existing regulations, under this rule, the lessee of a Class I lease would have to pay royalties on both the direct use and electrical generation. For Class II and Class III leases, the lessee would have to pay royalties on the gross proceeds derived from commercial Start Printed Page 24453electrical generation and fees for the direct use. MMS has added language to § 202.351(b)(1) to clarify this principle.

5. 30 CFR 206.357 How do I calculate royalty due on byproducts?

Public Comments: We received one comment that the rule is contrary to the EPAct because it requires that royalties be paid on byproducts other than those named under the EPAct.

MMS Response: In the EPAct, for new leases, Congress changed the byproducts upon which royalties are due, to include “any mineral or minerals specified in the Mineral Leasing Act, 30 U.S.C. 181” (30 U.S.C. 1004(a)(2)). Therefore, we agree that, although Congress did not change the definition of “byproduct,” in 30 U.S.C. 1001, it did provide that under leases issued under the EPAct royalties are due only on those byproducts that also are minerals identified in § 181, i.e. phosphate, sodium, and potassium. We refer you to the BLM regulations at 43 CFR 3211.19(a), which incorporate this change.

We also revised § 206.357 in the final rule to separate the introductory language in the proposed rule into two paragraphs and clarify that royalty is due on those byproducts that are royalty-bearing under the lease terms of Class I leases and of Class III leases that do not elect to convert to all of the regulations promulgated in the final BLM rule for leases issued after August 8, 2005. Conversion of a Class I lease to a Class III lease (conversion of the royalty terms) does not by itself modify the lease terms pertaining to byproducts. However, the BLM rule at 43 CFR 3200.7(a)(2) allows a lessee who does convert the royalty terms of a Class I lease an additional option to also convert all other terms, which would include the provisions regarding byproducts. Thus, some Class III leases may retain the original lease terms regarding byproducts, while others will effectively convert to the EPAct byproduct terms.

For Class II leases and those Class III leases that do elect to convert to all the terms of the BLM rule for leases issued after August 8, 2005, royalty is due under 30 U.S.C. 1004(a)(2) on those byproducts that are identified in 30 U.S.C. 181.

There is one geothermal lessee of a Class I lease who has paid royalty on sulfur as a byproduct in the past. No lessee has paid royalty on any byproducts for more than two years.

Though theoretically possible, MMS believes that it is extremely unlikely that phosphate, sodium, or potassium will be produced as a byproduct of geothermal hot water or steam. To MMS' knowledge, there are no instances of commercially viable production of such byproducts in the past. MMS therefore does not expect any significant production of any royalty-bearing byproducts from Class II leases or from Class III leases that convert all their terms to the new rule.

6. 30 CFR 206.359 How do I determine byproduct transportation allowances?

The proposed rule at § 206.359(h) provided that in computing depreciation, the lessee may elect to use either a straight-line method based on the life of the transportation system, the life of the reserves which the transportation system services, or a unit-of-production method. This would have changed the option in the existing rule (at § 206.358(b)(2)(iv)(A)) to use either a straight-line method based on the life of equipment or the life of the geothermal project that the transportation system services. As with the other depreciation provisions discussed above, there was no explanation of this proposed change in the preamble. MMS again does not intend a change to the meaning of the existing rule. The proposed rule (as with the other provisions) also omitted language regarding a change in ownership of the transportation system not altering the depreciation schedule established by the original lessee-owner. Both of these errors have been corrected in § 206.359(h) of the final rule.

MMS does not expect wide applicability of these provisions in view of the fact that no lessees currently are reporting royalties on byproducts or byproduct transportation allowances. Nevertheless, these provisions may become applicable in the future, and the final rule should not create unnecessary confusion. It is therefore appropriate to make the corrections described above.

C. 30 CFR Part 217—Audits and Inspections, Subpart H—Geothermal Resources

Although the regulatory text of part 217 was omitted from the proposed rule, an opportunity for public comment was provided in the preamble discussion, including the information collection requirements. No comments were received regarding part 217, which contains technical, noncontroversial audit information. The regulatory text of part 217 is included in this final rule.

D. 30 CFR Part 218—Collection of Royalties, Rentals, Bonuses and Other Monies Due the Federal Government, Subpart F—Geothermal Resources

1. 30 CFR 218.303 May I credit rental towards royalty?

Public Comments: We received one comment stating that the proposed rule's requirement that the credit be taken “only in the year paid-goes beyond the law, is too strict, and will have the unforeseen consequence of imposing financial burdens when companies can least afford additional costs.”

MMS Response: In section 230 of the EPAct, Congress added a new 30 U.S.C. 1004(e) that authorized lessees to credit “[a]ny annual rental under this section that is paid with respect to a lease before the first day of the year for which the annual rental is owed shall be credited to the amount of royalty that is required to be paid under the lease for that year” (emphasis added). We think it is clear from the language of the EPAct that lessees may credit annual rental paid in a particular year only to royalties paid “that year.” Thus, Congress, not MMS, has directed that credits for rentals paid be restricted to the year for which they are paid. Any other construction is contrary to the statute's plain language.

Title 30 U.S.C. 1004(e), as added by section 230 of the EPAct, provides that “[a]ny annual rental under this section that is paid with respect to a lease before the first day of the year for which the annual rental is owed shall be credited to the amount of royalty that is required to be paid under the lease for that year.” It is apparent that Congress intended this provision to apply to post-EPAct leases. It is only under section 1004(a)(3), as added by the EPAct, that a lessee must continue to pay annual rental regardless of whether the lease is in production. Under the terms of pre-EPAct leases, rental ceases when the lease goes into production (and the lease is then subject to minimum royalty).

Thus, the rental crediting provision will apply to Class II leases, as defined in 30 CFR 206.351. In addition, Class III leases as defined in that section may elect to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005, under 43 CFR 3200.7(a)(2). That election would operate to convert the rental terms to EPAct terms. Crediting annual rental against royalty therefore should apply to those leases as well. Class III leases that do not elect to be subject to all of the regulations promulgated for post-EPAct leases will retain their existing rental terms. The crediting provision therefore Start Printed Page 24454should not apply to those Class III leases. MMS has revised the language of § 218.303(a) in the final rule to clarify this principle.

2. 30 CFR 218.304 May I credit rental towards direct use fees?

Public Comments: We received three comments urging that lessees who pay fees under direct use leases should be allowed to credit rental towards fees because the commenters believe “fees” are “royalties.” One commenter alleged that payment of the fees and rental would increase monies paid the Government for direct use to ten times that paid for electricity. Another commenter stated that collecting fees and rentals for direct use is contrary to the “intent of the EPAct where the agency is directed to encourage direct use of geothermal resources.”

MMS Response: In section 223 of the EPAct, Congress added a new 30 U.S.C. 1004(b) that directed the Secretary to “establish a schedule of fees, in lieu of royalties” (emphasis added). “In lieu of” means “instead of; in place of; in substitution of.” It does not mean “in addition to.” Black's Law Dictionary 787 (6th ed. 1990). Thus, the plain language of the EPAct makes it clear that “fees” are not “royalties.” In 30 U.S.C. 1004(e) (added by section 230 of the EPAct), Congress authorized lessees to credit “[a]ny annual rental under this section that is paid with respect to a lease before the first day of the year for which the annual rental is owed will be credited to the amount of royalty that is required to be paid under the lease for that year” (emphasis added). Therefore, the MMS correctly concluded that rentals could not be credited towards fees because fees are not royalties.

With respect to the concerns that payment of fees and rentals will increase direct use lease payment to ten times that of those for electricity and is contrary to the EPAct, MMS can find no support for that position. As we stated in the preamble to the proposed rule, for commercial generation of electricity, “[b]ecause the EPAct mandates that the royalty revenues received by MMS should be the same as what would have been received under the valuation methods of the current regulations, there would be no revenue impact for electrical generation projects” (71 FR 41523). Direct use projects are paying substantially less under the EPAct than under the old rules. As stated in the preamble to the proposed rule, for direct use projects:

Current direct use lessees who do not sell the geothermal resources would have the option to convert their leases to the new fee schedule, which would result in a reduction of $60,000 per year from the current level of royalties, a 95-percent reduction. In addition, all new direct use lessees who do not sell the geothermal resources under the new regulations would use the same fee schedule, also paying about 95 percent less than they would have under the current regulations.

71 FR 41524. With a 95-percent reduction in payments made under a direct use lease, it is not possible that payment of rentals would increase revenues paid on a lease to ten times the royalty paid on geothermal resources used in electrical generation plants, whose payments remain the same.

For example, assume a lessee has a 1,000-acre pre-EPAct direct use lease and was paying an average of $15,000 per year in royalties. Because royalties would exceed the $2,000 in rentals for any year ($2×1,000 acres), the lessee would owe no rentals. Therefore, the lessee's total lease payments would be $15,000. However, if the lessee converted to the EPAct's fee terms, the lessee would owe only $750 in fees (a 95% reduction) and $5,000 in rental ($5×1,000 acres) for a combined annual payment of $5,750. The $5,750 is only 38 percent of what the lessee was paying prior to conversion. Thus, we believe a 62-percent decrease in monies paid on a lease does encourage the direct use of geothermal resources and ensures a “fair return to the United States for use of the resource” 30 U.S.C. 1004(b).

3. 30 CFR 218.305 How do I pay advanced royalties I owe under BLM regulations?

The new section 5(f) of the Geothermal Steam Act (30 U.S.C. 1004(f)), added by the EPAct, provides that a lease will remain in force notwithstanding a cessation of production if, during the period in which production is ceased, “the lessee pays royalty in advance at the monthly average rate at which royalty was paid during the period of production.” We have added language to § 218.305 to clarify that you must calculate the average monthly royalty by including the amount against which you applied the annual rental as a credit. Under § 218.303, the annual rental may be credited against the advanced royalty due, and we have added specific language in § 218.303(a)(2) in the final rule to effect that result. Thus, both royalty and advanced royalty will be treated identically for purposes of crediting annual rental.

4. 30 CFR 218.306 May I receive a credit against production royalties for in-kind deliveries of electricity I provide under contract to a State or county government?

This provision implements the new 30 U.S.C. 1004(d), added by EPAct section 224. The maximum credit for the value of the electricity provided to a State or county government is the share of royalty payments that the State or county would receive under the permanent indefinite appropriation established by 30 U.S.C. 1019, as amended by EPAct section 224(b). Under section 1004(d)(3), the electricity delivered will serve as the payment of the State's or county's share. The preamble to the proposed rule gave an hypothetical example of the operation of this provision as follows:

For example, assume that you have a geothermal lease in New Mexico and that you delivered 10,000 megawatt-hours of electricity in a month to New Mexico under a contract MMS approved. Furthermore, assume that the wholesale value of megawatt-hours in the area where your lease is located is $30.00 per megawatt-hour that month. If you had paid royalties in money on the basis of that wholesale value, and further assuming that you have a Class I lease with a 10-percent royalty rate, you would have paid $30,000 to MMS. The MMS then would have paid 50 percent of that amount ($15,000) to the State of New Mexico. You would be entitled to a credit of $15,000 against the amount you would otherwise owe to MMS when royalty is calculated on that basis. You would have to pay the remaining $15,000 to MMS in money.

71 FR 41523. The last sentence of this explanation inadvertently overlooked explaining one further consequence of this provision, which we explain here for purposes of clarity.

Under 30 U.S.C. 1019, the State in which a lease is located receives 50 percent of the royalties paid to the United States, the county receives 25 percent, and 25 percent is deposited to miscellaneous receipts in the Treasury. When the lessee delivers the electricity in kind and takes the credit against royalties of $15,000, the in-kind delivery serves as payment of the State's 50 percent share under 30 U.S.C. 1019. The royalty paid in money therefore is divided evenly between the county and the Treasury.

Under the hypothetical as stated, for the lessee to claim the $15,000 credit against royalties, it would have to deliver $15,000 worth of electricity (which would equal 500 megawatt-hours in this example) in kind to New Mexico. If it did, instead of realizing $300,000 from the sale of all 10,000 megawatt-hours, the lessee would Start Printed Page 24455realize $285,000 from the sale of 9,500 megawatt-hours and no money for the in-kind delivery of the 500 megawatt-hours. The royalty owed in money under this lease, before application of the credit, would be $28,500.

In the hypothetical, the lessee would apply the $15,000 credit against royalties to the $28,500 it would owe in money, and would actually pay $13,500. That amount would be distributed 50 percent to the county and 50 percent to the Treasury—in this case, $6,750 to each. In contrast, if no electricity had been delivered in kind and the lessee had paid $30,000 as royalty in money, the State of New Mexico would have received $15,000, the county in which the lease is located would have received $7,500, and the Treasury would have received the remaining $7,500. Thus, use of the in-kind credit results in a slight adverse monetary consequence to the county and the Federal government. This hypothetical illustrates that use of the in-kind credit reduces not only the royalty paid to the United States as a result of the credit but also reduces the lessee's proceeds on which royalty is calculated.

In the final rule, MMS has also made several changes from the proposed rule to eliminate duplicative language, clarify potential ambiguities, and express provisions in plainer English. None of those changes effects any change in substantive meaning.

III. Procedural Matters

1. Effective Date

This rule becomes effective 30 days following publication, rather than 60 days, because the Department and the geothermal industry are interested in having competitive geothermal lease sales as soon as possible. Lease sales cannot be held until both the BLM and MMS final rules become effective because it is these rules that prescribe key terms and conditions of new leases. The Department intends for both the BLM and MMS rules to become effective simultaneously.

2. Summary Cost and Royalty Impact Data

Of the changes to the geothermal valuation regulations outlined above, only a few will have a royalty impact on industry, States, or the Federal Government. This section addresses those changes and discusses the extent of their impacts. There are no “Costs and Benefits,” under the meaning identified by the Office of Management and Budget (OMB), as a result of this rule. However, there are certain estimated royalty effects of this rule to all potentially affected groups: industry, States and local governments, and the Federal Government. These are summarized below. There are no significant associated costs to industry of administering this rule. The Federal government will incur some minimal costs associated with systems changes.

Of the changes that have royalty cost impacts, three will result in royalty decreases for industry, States, and MMS. One will result in an increase to the counties with producing Federal geothermal leases. The net impact of the six changes will result in an expected overall royalty revenue decrease of $4,101,583 to the Federal Government, a corresponding increase to counties of $4,071,583, and a decrease of $30,000 in royalties to the States.

We have evaluated potential effects on federally recognized Indian tribes and have determined that the changes in this rule for Federal leases would not apply to and currently would not have an impact on Indian leases. In addition, this rule does not have tribal implications that impose substantial direct compliance costs on Indian tribal governments.

A. Industry

(1) Royalty Impacts

(a) No Change in Royalties—Electrical Generation

Because the EPAct mandates that the level of royalty revenues received by MMS should be the same over a 10-year period as what would have been received under the valuation methods of the existing regulations, there are no significant overall revenue impacts for electrical generation projects. Electrical generation lessees that remain under the existing regulations will pay royalties on the same basis as they did before this final rule. And, while electrical generation lessees that modify their leases to the new regulations will change to the percentage of gross proceeds method, the level of royalties they pay will not differ significantly from the royalties paid under the existing regulations. New lessees' royalty rates are determined by BLM, which may cause some difference in royalty payments by individual lessees, but which should result in the same overall level of royalties for 10 years under this final rule as they would have paid under the existing regulations.

(b) Net Decrease in Royalties—Direct Use—Estimated at $60,000

Current direct use lessees who do not sell the geothermal resources have the option to convert their leases to the new fee schedule, which MMS anticipates will result in a reduction of $60,000 per year from the current level of royalties, a 95-percent reduction. In addition, all new direct use lessees who do not sell the geothermal resources under the new regulations use the same fee schedule, also paying about 95 percent less than they would have under the existing regulations.

(2) Administrative Costs

The MMS has determined that there are no significant expected administrative cost changes.

B. State and Local Governments

(1) Royalty Impacts—State Governments

(a) Net Decrease in Royalties—Direct Use—Estimated at $30,000

The MMS estimates that States impacted by this rule will receive the same royalties as they currently receive for electrical generation leases without significant variation. However, because of the 95-percent decrease in revenue collected from direct use leases, States that receive a share of that revenue under 30 U.S.C. 191 will be impacted by the revenue decrease. It is unknown how this will affect the counties because the States distribute royalty revenues to their counties directly without MMS involvement. The new fee schedule will result in approximately a 95-percent reduction in royalties paid to States from direct use projects. The MMS estimates the reduction to be $30,000 per year. This amount is based on the difference between the average of direct use royalties paid for fiscal years 2001 through 2005 and the revenues to be collected using the new fee schedule.

(2) Administrative Costs—State Governments

The MMS has determined that there are no expected administrative cost changes for State governments.

(3) Royalty Impacts—Local Governments

(a) Net Increase in Royalties—Estimated at $4,071,583

The EPAct (30 U.S.C. 1019, as amended by section 224(b) of the EPAct) mandates a new distribution of 25 percent of royalties, rentals, bonuses, and other revenues to the counties. This 25 percent cuts the Federal share in half from 50 percent to 25 percent and leaves the States' share as 50 percent. The counties will receive a new 25-percent distribution of total geothermal royalty revenue under the EPAct, which increases their revenues by an estimated $4,071,583 per year (25 percent of the average total geothermal royalties of $16,286,334 paid for fiscal years 2001 Start Printed Page 24456through 2005) from the Federal Government.

Prior to the EPAct, MMS distributed 50 percent of the geothermal royalties to the States and retained 50 percent for the Federal Government. The EPAct now mandates that MMS directly distribute 25 percent of geothermal royalties to the counties that contain producing geothermal Federal leases. This 25-percent county share is taken from the Federal share, cutting it in half, to 25 percent of the total geothermal royalties. The State distribution of 50 percent remains unchanged under the EPAct.

(4) Administrative Costs—Local Governments

This rule does not impose any additional burden on local governments. The counties where geothermal facilities are located on Federal leases will receive a new distribution of 25 percent of the total geothermal royalties for the first time directly from the Federal Government, whereas in the past it was left up to the States to distribute geothermal royalty revenues to the counties should the respective States choose to do so. It is not known exactly how much geothermal royalty revenue is distributed to counties by the States, as it is up to each State to do this distribution and is not currently under MMS control.

C. Federal Government

The total combined estimated royalty impact on the Federal Government will be a decrease of $4,101,583 ($4,071,583 (25 percent of the average total geothermal royalties of $16,286,334 paid for fiscal years 2001 through 2005) for electrical generation and $30,000 for direct use).

(1) Royalty Impacts

(a) Net Decrease in Royalties—Electrical Generation—Estimated at $4,071,583

The Federal Government will be impacted by a net overall decrease in royalties as a result of the changes to the regulations governing the new distribution of 25 percent of total royalties to the counties and the new direct use fee schedule. The net impact on the Federal Government will be a decrease of approximately $4,071,583 for electrical generation.

(b) Net Decrease in Royalties—Direct Use—Estimated at $30,000

The Federal Government will also be impacted by the 95-percent decrease in revenues from direct use leases due to the direct use fee schedule. The MMS estimates the reduction to be $30,000 per year. This amount is based on the difference between the average of direct use royalties paid for fiscal years 2001 through 2005 and the revenues to be collected using the new fee schedule.

(2) Administrative Costs—Federal Government

The MMS does not expect any administrative cost changes for the Federal Government.

D. Summary of Costs and Royalty Impacts to Industry, State and Local Governments, and the Federal Government

In the table below, a negative number means a reduction in payment or receipt of royalties or a reduction in costs. A positive number means an increase in payment or receipt of royalties or an increase in costs. The net expected change in royalty impact is the sum of the royalty increases and decreases. If no costs are represented for administrative or royalty impacts, then the increase, decrease, and net values impacts are all zero.

Summary of Expected Costs and Royalty Impacts

DescriptionCosts and royalty increases or royalty decreases
First yearSubsequent years
A. Industry
Royalty Decrease from Direct Use Fee Schedule−$60,000−60,000
Net Expected Change in Royalty (direct use fee) Payments from Industry−60,000−60,000
B. State and Local Governments
State:
Royalty Decrease to State Governments−30,000−30,000
Local Governments (counties):
Royalty Increase to counties+4,071,583+4,071,583
Net Expected Change in Royalty Payments to State and Local Governments+4,041,583+4,041,583
C. Federal Government
Royalty Decrease from 25 percent Royalty Disbursement to Counties−4,071,583−4,071,583
Royalty Decrease from New Direct Use Fee Schedule Implementation−30,000−30,000
Net Expected Change in Royalty Payments to Federal Government−4,101,583−4,101,583

3. Regulatory Planning and Review, Executive Order 12866

In accordance with Executive Order 12866, the OMB has determined that this rule is not a significant regulatory action.

a. This rule will not have an annual effect of $100 million or adversely affect an economic sector, productivity, jobs, the environment, or other units of Government.

b. This rule will not create inconsistencies with other agencies' actions.

c. This rule will not materially affect entitlements, grants, user fees, loan programs, or the rights and obligations of their recipients.

d. This rule will not raise novel legal or policy issues.

4. Regulatory Flexibility Act

The Department of the Interior certifies that this rule will not have a significant economic effect on a substantial number of small entities as defined under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). An initial Start Printed Page 24457Regulatory Flexibility Analysis is not required. Accordingly, a Small Entity Compliance Guide is not required.

Your comments are important. The Small Business and Agricultural Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were established to receive comments from small businesses about Federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. You may comment to the Small Business Administration without fear of retaliation. Disciplinary action for retaliation by an MMS employee may include suspension or termination from employment with the Department of the Interior.

5. Small Business Regulatory Enforcement Fairness Act (SBREFA)

This rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rule:

a. Does not have an annual effect on the economy of $100 million or more.

b. Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions.

c. Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises.

6. Unfunded Mandates Reform Act

In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.):

a. This rule will not “significantly or uniquely” affect small governments. Therefore, a Small Government Agency Plan is not required.

b. This rule will not produce a Federal mandate of $100 million or greater in any year, i.e., it will not be a “significant regulatory action” under the Unfunded Mandates Reform Act. The analysis prepared for Executive Order 12866 and found earlier in this preamble explains that the economic impact of this rule will be well below $100 million per year.

7. Governmental Actions and Interference With Constitutionally Protected Property Rights (Takings), Executive Order 12630

In accordance with Executive Order 12630, this rule does not have significant takings implications. A takings implication assessment is not required.

8. Federalism, Executive Order 13132

In accordance with Executive Order 13132, this rule does not have federalism implications; hence, a federalism assessment is not required. It will not substantially and directly affect the relationship between the Federal and State governments. The management of Federal leases is the responsibility of the Secretary of the Interior. Royalties collected from Federal geothermal leases are shared with State and county governments on a percentage basis as prescribed by law. This rule does not alter any lease management responsibilities. It pertains to royalty and fees computation only. This rule will not impose costs on States or localities.

9. Civil Justice Reform, Executive Order 12988

In accordance with Executive Order 12988, the Office of the Solicitor has determined that this rule will not unduly burden the judicial system and meets the requirements of sections 3(a) and 3(b)(2) of the Order.

10. Paperwork Reduction Act of 1995 (PRA)

The OMB has approved a new collection of information contained in this rule. The title of the new information collection request (ICR) is “30 CFR Parts 202, 206, 210, 217, and 218—Valuation of Geothermal Resources.” The total hour burden is 174 hours, which is approved under OMB Control Number 1010-0169 (expires August 31, 2009). The information is collected on Form MMS-2014, Report of Sales and Royalty Remittance, which is approved under OMB Control Number 1010-0140 (expires November 30, 2009).

We received comments from industry on the rule, but there were no changes in the information collection from the proposed rule to the final rule. We will use the information collected to ensure that proper royalty is paid on all geothermal resources produced from Federal leases.

Submit written comments on the accuracy of this burden estimate or suggestions on reducing the burden to Sharron L. Gebhardt, Lead Regulatory Specialist, Minerals Management Service, Minerals Revenue Management, P.O. Box 25165, MS 302B2, Denver, Colorado 80225. If you use an overnight courier service, our courier address is Building 85, Room A-614, Denver Federal Center, W. 6th Ave. and Kipling Blvd., Denver, Colorado 80225. You may also e-mail your comments to us at mrm.comments@mms.gov. Include the title of the information collection and the OMB control number in the “Attention” line of your comment. Also include your name and return address. If you do not receive a confirmation that we have received your e-mail, contact Sharron Gebhardt at (303) 231-3211. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.

11. National Environmental Policy Act (NEPA)

This rule deals with financial matters and will have no direct effect on MMS decisions on environmental activities. Pursuant to 516 DM 2.3A (2), Section 1.10 of 516 DM 2, Appendix 1, excludes from documentation in an environmental assessment or impact statement “policies, directives, regulations and guidelines of an administrative, financial, legal, technical or procedural nature; or the environmental effects of which are too broad, speculative, or conjectural to lend themselves to meaningful analysis and will be subject later to the NEPA process, either collectively or case-by-case.” Section 1.3 of the same appendix clarifies that royalties and audits are considered to be routine financial transactions that are subject to categorical exclusion from the NEPA process. No exception to the categorical exclusion applies.

12. Government-to-Government Relationship With Tribes

In accordance with the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951) and Department Manual 512 DM 2, we have evaluated potential effects on federally recognized Indian tribes. This rule does not apply to Indian leases.

13. Effects on the Nation's Energy Supply, Executive Order 13211

In accordance with Executive Order 13211, this regulation does not have a significant adverse effect on the Nation's energy supply, distribution, or use. The changes primarily involve royalty valuation of geothermal production to simplify royalty valuation, hence, any impact to the way industry does business should be positive, and, as the EPAct directs, should encourage energy development and marketing. This rule does not otherwise impact energy supply, distribution, or use. Start Printed Page 24458

14. Consultation and Coordination With Indian Tribal Governments, Executive Order 13175

In accordance with Executive Order 13175, we have evaluated this rule and determined that it has no potential effects on federally recognized Indian tribes. This rule does not have tribal implications that impose substantial direct compliance costs on Indian tribal governments.

Start List of Subjects

List of Subjects in 30 CFR Parts 202, 206, 210, 217, and 218

End List of Subjects Start Signature

Dated: April 19, 2007.

Mike Olsen,

Deputy Assistant Secretary for Land and Minerals Management.

End Signature Start Amendment Part

For the reasons stated in the preamble, the Minerals Management Service is amending

End Amendment Part Start Part

PART 202—ROYALTIES

End Part Start Amendment Part

1. The authority for part 202 continues to read as follows:

End Amendment Part Start Authority

Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq.; 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.; 1331 et seq., 1801 et seq.

End Authority

Subpart H-Geothermal Resources

Start Amendment Part

2. Revise § 202.351 to read as follows:

End Amendment Part
Royalties on geothermal resources.

(a)(1) Royalties on geothermal resources, including byproducts, or on electricity produced using geothermal resources, will be at the royalty rate(s) specified in the lease, unless the Secretary of the Interior temporarily waives, suspends, or reduces that rate(s). Royalties are determined under 30 CFR part 206, subpart H.

(2) Fees in lieu of royalties on geothermal resources are prescribed in 30 CFR part 206, subpart H.

(3) Except for the amount credited against royalties for in-kind deliveries of electricity to a State or county under § 218.306, you must pay royalties and direct use fees in money.

(b)(1) Except as specified in paragraph (b)(2) of this section, royalties or fees are due on—

(i) All geothermal resources produced from a lease and that are sold or used by the lessee or are reasonably susceptible to sale or use by the lessee, or

(ii) All proceeds derived from the sale of electricity produced using geothermal resources produced from a lease.

(2) For purposes of this subparagraph, the terms “Class I lease,” “Class II lease,” and “Class III lease” have the same meanings prescribed in 30 CFR 206.351.

(i) For Class I leases, MMS will allow free of royalty—

(A) Geothermal resources that are unavoidably lost or reinjected before use on or off the lease, as determined by the Bureau of Land Management (BLM), or that are reasonably necessary to generate plant parasitic electricity or electricity for Federal lease operations; and

(B) A reasonable amount of commercially demineralized water necessary for power plant operations or otherwise used on or for the benefit of the lease.

(ii) For Class II and Class III leases where the lessee uses geothermal resources for commercial production or generation of electricity, or where geothermal resources are sold at arm's length for the commercial production or generation of electricity, MMS will allow free of royalty or direct use fees geothermal resources that are:

(A) Unavoidably lost or reinjected before use on or off the lease, as determined by BLM;

(B) Reasonably necessary for the lessee to generate plant parasitic electricity or electricity for Federal lease operations, as approved by BLM; or

(C) Otherwise used for Federal lease operations related to commercial production or generation of electricity, as approved by BLM.

(iii) For Class II and Class III leases where the lessee uses the geothermal resources for a direct use or in a direct use facility, as defined in 30 CFR 206.351, resources that are used to generate electricity for Federal lease operations or that are otherwise used for Federal lease operations are subject to direct use fees, except for geothermal resources that are unavoidably lost or reinjected before use on or off the lease, as determined by BLM.

(3) Royalties on byproducts are due at the time the recovered byproduct is used, sold, or otherwise finally disposed of. Byproducts produced and added to stockpiles or inventory do not require payment of royalty until the byproducts are sold, utilized, or otherwise finally disposed of. The MMS may ask BLM to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventories become excessive.

(c) If BLM determines that geothermal resources (including byproducts) were avoidably lost or wasted from the lease, or that geothermal resources (including byproducts) were drained from the lease for which compensatory royalty (or compensatory fees in lieu of compensatory royalty) are due, the value of those geothermal resources, or the royalty or fees owed, will be determined under 30 CFR part 206, subpart H.

(d) If a lessee receives insurance or other compensation for unavoidably lost geothermal resources (including byproducts), royalties at the rates specified in the lease (or fees in lieu of royalties) are due on the amount of, or as a result of, that compensation. This paragraph will not apply to compensation through self-insurance.

Start Amendment Part

3. Revise § 202.353 to read as follows:

End Amendment Part
Measurement standards for reporting and paying royalties and direct use fees.

(a) For geothermal resources used to generate electricity, you must report the quantity on which royalty is due on Form MMS-2014 (Report of Sales and Royalty Remittance) as follows:

(1) For geothermal resources for which royalty is calculated under § 206.352(a), you must report quantities in:

(i) Thousands of pounds to the nearest whole thousand pounds if the contract for the geothermal resources specifies delivery in terms of weight; or

(ii) Millions of Btu to the nearest whole million Btu if the sales contract for the geothermal resources specifies delivery in terms of heat or thermal energy.

(2) For geothermal resources for which royalty is calculated under § 206.352(b), you must report the quantities in kilowatt-hours to the nearest whole kilowatt-hour.

(b) For geothermal resources used in direct use processes, you must report the quantity on which a royalty or direct use fee is due on Form MMS-2014 in:

(1) Millions of Btu to the nearest whole million Btu if valuation is in terms of heat or thermal energy used or displaced;

(2) Millions of gallons to the nearest million gallons of geothermal fluid produced if valuation or fee calculation is in terms of volume;

(3) Millions of pounds to the nearest million pounds of geothermal fluid produced if valuation or fee calculation is in terms of mass; or

(4) Any other measurement unit MMS approves for valuation and reporting purposes.

(c) For byproducts, you must report the quantity on which royalty is due on Form MMS-2014 consistent with MMS-established reporting standards.

(d) For commercially demineralized water, you must report the quantity on which royalty is due on Form MMS-Start Printed Page 244592014 in hundreds of gallons to the nearest hundred gallons.

(e) You need not report the quality of geothermal resources, including byproducts, to MMS. However, you must maintain quality measurements for audit purposes. Quality measurements include, but are not limited to:

(1) Temperatures and chemical analyses for fluid geothermal resources; and

(2) Chemical analyses, weight percent, or other purity measurements for byproducts.

Start Part

PART 206—PRODUCT VALUATION

End Part Start Amendment Part

4. The authority for part 206 continues to read as follows:

End Amendment Part Start Authority

Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq.; 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.; 1331 et seq., 1801 et seq.

End Authority Start Amendment Part

5. Revise subpart H to read as follows:

End Amendment Part
Subpart H—Geothermal Resources
206.350
What is the purpose of this subpart?
206.351
What definitions apply to this subpart?
206.352
How do I calculate the royalty due on geothermal resources used for commercial production or generation of electricity?
206.353
How do I determine transmission deductions?
206.354
How do I determine generating deductions?
206.355
How do I calculate royalty due on geothermal resources I sell at arm's length to a purchaser for direct use?
206.356
How do I calculate royalty due on geothermal resources I use for direct use purposes?
206.357
How do I calculate royalty due on byproducts?
206.358
What are byproduct transportation allowances?
206.359
How do I determine byproduct transportation allowances?
206.360
What records must I keep to support my calculations of royalty or fees under this subpart?
206.361
How will MMS determine whether my royalty or direct use fee payments are correct?
206.362
What are my responsibilities to place production into marketable condition and to market production?
206.363
When is an MMS audit, review, reconciliation, monitoring, or other like process considered final?
206.364
How do I request a value or gross proceeds determination?
206.365
Does MMS protect information I provide?
206.366
What is the nominal fee that a State, tribal, or local government lessee must pay for the use of geothermal resources?

Subpart H—Geothermal Resources

What is the purpose of this subpart?

(a) This subpart applies to all geothermal resources produced from Federal geothermal leases issued pursuant to the Geothermal Steam Act of 1970 (GSA), as amended by the Energy Policy Act of 2005 (EPAct) (30 U.S.C. 1001 et seq.). The purpose of this subpart is to prescribe how to calculate royalties and direct use fees for geothermal production.

(b) The MMS may audit and adjust all royalty and fee payments.

(c) In some cases, the regulations in this subpart may be inconsistent with a statute, settlement agreement, written agreement, or lease provision. If this happens, the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency. For purposes of this paragraph, the following definitions apply:

(1) “Settlement agreement” means a settlement agreement between the United States and a lessee resulting from administrative or judicial litigation.

(2) “Written agreement” means a written agreement between the lessee and the MMS Director or Assistant Secretary, Land and Minerals Management of the Department of the Interior that:

(i) Establishes a method to determine the royalty from any lease that MMS expects at least would approximate the value or royalty established under this subpart; and

(ii) Includes a value or gross proceeds determination under § 206.364 of this subpart.

What definitions apply to this subpart?

For purposes of this subpart, the following terms have the meanings indicated.

Affiliate means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:

(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.

(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities, or instruments of ownership, or other forms of ownership of another person, MMS will consider the following factors in determining whether there is control under the circumstances of a particular case:

(i) The extent to which there are common officers or directors;

(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership;

(iii) Operation of a lease, plant, pipeline, or other facility;

(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, pipeline, or other facility; and

(v) Other evidence of power to exercise control over or common control with another person.

(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.

Allowance means a deduction in determining value for royalty purposes.

Arm's-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.

Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty or fee payment compliance activities of lessees or other interest holders who pay royalties, fees, rents, or bonuses on Federal geothermal leases.

Byproducts means minerals (exclusive of oil, hydrocarbon gas, and helium), found in solution or in association with geothermal steam, that no person would extract and produce by themselves because they are worth less than 75 percent of the value of the geothermal steam or because extraction and production would be too difficult.

Byproduct recovery facility means a facility where byproducts are placed in marketable condition.

Byproduct transportation allowance means an allowance for the reasonable, actual costs of moving byproducts to a point of sale or delivery off the lease, unit area, or communitized area, or away from a byproduct recovery facility. The byproduct transportation allowance does not include gathering costs. You must report a byproduct transportation Start Printed Page 24460allowance as a separate discrete field on the Form MMS-2014.

Class I lease means:

(1) A lease that BLM issued before August 8, 2005, for which the lessee has not converted the royalty rate terms under 43 CFR 3212.25; or

(2) A lease that BLM issued in response to an application that was pending on August 8, 2005, for which the lessee has not made an election under 43 CFR 3200.8(b).

Class II lease means:

A lease that BLM issued after August 8, 2005, except for a lease issued in response to an application that was pending on August 8, 2005, for which the lessee does not make an election under 43 CFR 3200.8(b).

Class III lease means:

A lease that BLM issued before August 8, 2005, for which the lessee has converted to the royalty rate or direct use fee terms under 43 CFR 3212.25.

Commercial production or generation of electricity means generation of electricity that is sold or is subject to sale, including the electricity or energy that is reasonably required to produce the resource used in production of electricity for sale or to convert geothermal energy into electrical energy for sale.

Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.

Deduction means a subtraction the lessee uses to determine the value of geothermal resources produced from a Class I lease that the lessee uses to generate electricity.

Delivered electricity means the amount of electricity in kilowatt-hours delivered to the purchaser.

Direct use means the utilization of geothermal resources for commercial, residential, agricultural, public facilities, or other energy needs, other than the commercial production or generation of electricity.

Direct use facility means a facility that uses the heat or other energy of the geothermal resource for direct use purposes.

Electrical facility means a power plant or other facility that uses a geothermal resource to generate electricity.

Field means the land surface vertically projected over a subsurface geothermal reservoir encompassing at least the outermost boundaries of all geothermal accumulations known to be within that reservoir. Geothermal fields are usually given names and their official boundaries are often designated by regulatory agencies in the respective States in which the fields are located.

Gathering means the movement of lease production from the wellhead to the point of utilization.

Generating deduction means a deduction for the lessee's reasonable, actual costs of generating plant tailgate electricity.

Geothermal resources means:

(1) All products of geothermal processes, including indigenous steam, hot water, and hot brines;

(2) Steam and other gases, hot water, and hot brines resulting from water, gas, or other fluids artificially introduced into geothermal formations;

(3) Heat or other associated energy found in geothermal formations; and

(4) Any byproducts.

Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to a geothermal lessee for the sale of electricity or geothermal resource. Gross proceeds includes, but is not limited to:

(1) Payments to the lessee for certain services such as effluent injection, field operation and maintenance, drilling or workover of wells, or field gathering to the extent that the lessee is obligated to perform such functions at no cost to the Federal Government;

(2) Reimbursements for production taxes and other taxes. Tax reimbursements are part of gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation; and

(3) Any monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts.

Lease means a geothermal lease issued under the authority of the GSA, unless the context indicates otherwise.

Lessee (you) means any person to whom the United States issues a geothermal lease, and any person who has been assigned an obligation to make royalty, fee, or other payments required by the lease. This includes any person who has an interest in a geothermal lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty, fee, or other payment responsibility. This also includes any affiliate of the lessee that uses the geothermal resource to generate electricity, in a direct use process, or to recover byproducts, or any affiliate that sells or transports lease production.

Marketable condition means lease products that are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the disposition from the field or area of such lease products.

Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).

Plant parasitic electricity means electricity used to operate a power plant that is used for commercial production or generation of electricity.

Plant tailgate electricity means the amount of electricity in kilowatt-hours generated by a power plant exclusive of plant parasitic electricity, but inclusive of any electricity generated by the power plant and returned to the lease for lease operations. Plant tailgate electricity should be measured at, or calculated for, the high voltage side of the transformer in the plant switchyard.

Point of utilization means the power plant or direct use facility in which the geothermal resource is utilized.

Public purpose means a program carried out by a State, tribal, or local government for the purpose of providing facilities or services for the benefit of the public in connection with, but not limited to, public health, safety or welfare, other than the commercial generation of electricity. Use of lands or facilities for habitation, cultivation, trade or manufacturing is permissible only when necessary for and integral to (i.e., an essential part of) the public purpose.

Public safety or welfare means a program carried out or promoted by a public agency for public purposes involving, directly or indirectly, protection, safety, and law enforcement activities, and the criminal justice system of a given political area. Public safety or welfare may include, but is not limited to, programs carried out by:

(1) Public police departments;

(2) Sheriffs' offices;

(3) The courts;

(4) Penal and correctional institutions (including juvenile facilities);

(5) State and local civil defense organizations; and

(6) Fire departments and rescue squads (including volunteer fire departments and rescue squads supported in whole or in part with public funds).

Reasonable alternative fuel means a conventional fuel (such as coal, oil, gas, or wood) that would normally be used as a source of heat in direct use operations.

Secretary means the Secretary of the Interior or any person duly authorized to exercise the powers vested in that office.

Transmission deduction means a deduction for the lessee's reasonable Start Printed Page 24461actual costs incurred to wheel or transmit the electricity from the lessee's power plant to the purchaser's delivery point.

Wheeling means the transmission of electricity from a power plant to the point of delivery.

How do I calculate the royalty due on geothermal resources used for commercial production or generation of electricity?

(a) If you sold geothermal resources produced from a Class I, II, or III lease at arm's length that the purchaser uses to generate electricity, then the royalty on the geothermal resources is the gross proceeds accruing to you from the sale of the geothermal resource to the arm's-length purchaser multiplied by either:

(1) The royalty rate in your lease; or

(2) The royalty rate that BLM prescribes or calculates under 43 CFR 3211.17. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales.

(b) If you use the geothermal resource in your own power plant for the generation and sale of electricity, the following provisions apply

(1) For Class I leases, you must determine the royalty on produced geothermal resources in accordance with the first applicable of the following paragraphs:

(i) The gross proceeds accruing to you from the arm's-length sale of the electricity less applicable deductions determined under § 206.353 and § 206.354 of this part, multiplied by the royalty rate in your lease. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales. Under no circumstances may the deductions reduce the royalty value of the geothermal resource to zero; or

(ii) A royalty determined by any other reasonable method approved by MMS under § 206.364 of this subpart.

(2) For Class II and Class III leases, the royalty on geothermal resources produced is your gross proceeds from the sale of electricity multiplied by the royalty rate BLM prescribed for your lease under 43 CFR 3211.17. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales. You may not reduce gross proceeds by any deductions.

How do I determine transmission deductions?

(a) If you determine the value of your geothermal resources under § 206.352(b)(1)(i) of this subpart, you may subtract a transmission deduction from the gross proceeds you received for the sale of electricity to determine the plant tailgate value of the electricity.

(1) The transmission deduction consists of either or both of two components:

(i) Transmission line costs as determined under paragraph (b) of this section; and

(ii) Wheeling costs if the electricity is transmitted across a third party's transmission line under an arm's-length wheeling agreement.

(2) You may deduct the actual costs you (including your affiliate(s)) incur for transmitting electricity under your arm's-length wheeling contract.

(b) To determine your transmission line cost, you must follow the requirements of paragraphs (b)(1) and (b)(2) of this section.

(1) Your transmission line costs are your actual costs associated with the construction and operation of a transmission line for the purpose of transmitting electricity attributable and allocable to your power plant utilizing Federal geothermal resources.

(i) You must determine the monthly transmission line cost component of the transmission deduction by multiplying the annual transmission line cost rate (in dollars per kilowatt-hour) by the amount of electricity delivered for the reporting month.

(ii) You must redetermine the transmission line cost rate annually either at the beginning of the same month of the year in which the power plant was placed into service or at a time concurrent with the beginning of your annual corporate accounting period. The period you select must coincide with the same period you chose for the generating deduction under § 206.354(b)(1). After you choose a deduction period, you may not later elect to use a different deduction period without MMS approval.

(2) Your actual transmission line costs during the reporting period include:

(i) Operating and maintenance expenses under paragraphs (d) and (e) of this section;

(ii) Overhead under paragraph (f) of this section; and either

(iii) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section or

(iv) A return on the capital investment in the transmission line under paragraphs (g) and (j) of this section.

(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transmission line.

(2)(i) You may include a return on capital you invested in the purchase of real estate for transmission facilities if:

(A) Such purchase is necessary; and

(B) The surface is not part of the Federal lease.

(ii) The rate of return will be the same rate determined under paragraph (k) of this section.

(d) Allowable operating expenses include:

(1) Operations supervision and engineering;

(2) Operations labor;

(3) Fuel;

(4) Utilities;

(5) Materials;

(6) Ad valorem property taxes;

(7) Rent;

(8) Supplies; and

(9) Any other directly allocable and attributable operating or maintenance expense that you can document.

(e) Allowable maintenance expenses include:

(1) Maintenance of the transmission line;

(2) Maintenance of equipment;

(3) Maintenance labor; and

(4) Other directly allocable and attributable maintenance expenses that you can document.

(f) Overhead directly attributable and allocable to the operation and maintenance of the transmission line is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(g) To compute costs associated with capital investment, a lessee may use either depreciation with a return on undepreciated capital investment, or a return on capital investment in the transmission line. After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without MMS approval.

(h)(1) To compute depreciation, you must use a straight-line depreciation method based on the life of the geothermal project, usually the term of the electricity sales contract, or other depreciation period acceptable to MMS. You may not depreciate equipment below a reasonable salvage value.

(2) A change in ownership of a transmission line does not alter the depreciation schedule established by the original lessee-owner for purposes of computing transmission line costs.

(3) With or without a change in ownership, you may depreciate a transmission line only once.

(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of Start Printed Page 24462the period for which you are calculating the transmission deduction by the rate of return provided in paragraph (k) of this section.

(j) To compute a return on capital investment in the transmission line, multiply the allowable capital investment in the transmission line by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.

(k) The rate of return must be 2.0 multiplied by the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. Redetermine the rate at the beginning of each subsequent calendar year.

(l) Calculate the deduction for transmission costs based on your cost of transmitting electricity through each individual transmission line.

(m)(1) For new transmission facilities or arrangements, base your initial deduction on estimates of allowable electricity transmission costs for the applicable period. Use the most recently available operations data for the transmission line or, if such data are not available, use estimates based on data for similar transmission lines.

(2) When actual cost information is available, you must amend your prior Form MMS-2014 reports to reflect actual transmission costs deductions for each month for which you reported and paid based on estimated transmission costs. You must pay any additional royalties due (together with interest computed under § 218.302). You are entitled to a credit for or refund of any overpaid royalties.

(n) In conducting reviews and audits, MMS may require you to submit arm's-length transmission contracts, production agreements, operating agreements, and related documents and all other data used to calculate the deduction. You must comply with any such requirements within the time MMS specifies. Recordkeeping requirements are found at part 212 of this chapter.

(o) At the completion of transmission line dismantlement and salvage operations, you may report a credit for or request a refund of royalties in an amount equal to the royalty rate times the amount by which actual transmission line dismantlement costs exceed actual income attributable to salvage of the transmission line.

How do I determine generating deductions?

(a) If you determine the value of your geothermal resources under § 206.352(b)(1)(i) of this subpart, you may deduct your reasonable actual costs incurred to generate electricity from the plant tailgate value of the electricity (usually the transmission-reduced value of the delivered electricity). You may deduct the actual costs you incur for generating electricity under your arm's-length power plant contract.

(b)(1) You must base your generating costs deduction on your actual annual costs associated with the construction and operation of a geothermal power plant.

(i) You must determine your monthly generating deduction by multiplying the annual generating cost rate (in dollars per kilowatt-hour) by the amount of plant tailgate electricity measured (or computed) for the reporting month. The generating cost rate is determined from the annual amount of your plant tailgate electricity.

(ii) You must redetermine your generating cost rate annually either at the beginning of the same month of the year in which the power plant was placed into service or at a time concurrent with the beginning of your annual corporate accounting period. The period you select must coincide with the same period chosen for the transmission deduction under § 206.353(b)(1). After you choose a deduction period, you may not later elect to use a different deduction period without MMS approval.

(2) Your generating costs are your actual power plant costs during the reporting period, including:

(i) Operating and maintenance expenses under paragraphs (d) and (e) of this section;

(ii) Overhead under paragraph (f) of this section; and either

(iii) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section; or

(iv) A return on capital investment in the power plant under paragraphs (g) and (j) of this section.

(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the power plant or are required by the design specifications of the power conversion cycle.

(2)(i) You may include a return on capital you invested in the purchase of real estate for a power plant site if:

(A) The purchase is necessary; and,

(B) The surface is not part of the Federal lease.

(ii) The rate of return will be the same rate determined under paragraph (k) of this section.

(3) You may not deduct the costs of gathering systems and other production-related facilities.

(d) Allowable operating expenses include:

(1) Operations supervision and engineering;

(2) Operations labor;

(3) Auxiliary fuel and/or utilities used to operate the power plant during down time;

(4) Utilities;

(5) Materials;

(6) Ad valorem property taxes;

(7) Rent;

(8) Supplies; and

(9) Any other directly allocable and attributable operating expense.

(e) Allowable maintenance expenses include:

(1) Maintenance of the power plant;

(2) Maintenance of equipment;

(3) Maintenance labor; and

(4) Other directly allocable and attributable maintenance expenses that you can document.

(f) Overhead directly attributable and allocable to the operation and maintenance of the power plant is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(g) To compute costs associated with capital investment, a lessee may use either depreciation with a return on undepreciated capital investment, or a return on capital investment in the power plant. After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without MMS approval.

(h)(1) To compute depreciation, you must use a straight-line depreciation method based on the life of the geothermal project, usually the term of the electricity sales contract, or other depreciation period acceptable to MMS. You may not depreciate equipment below a reasonable salvage value.

(2) A change in ownership of the power plant does not alter the depreciation schedule established by the original lessee-owner for purposes of computing generating costs.

(3) With or without a change in ownership, you may depreciate a power plant only once.

(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the generating deduction allowance by the rate of return provided in paragraph (k) of this section. Start Printed Page 24463

(j) To compute a return on capital investment in the power plant, multiply the allowable capital investment in the power plant by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.

(k) The rate of return must be 2.0 multiplied by the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. You must redetermine the rate at the beginning of each subsequent calendar year.

(l) Calculate the deduction for generating costs based on your cost of generating electricity through each individual power plant.

(m)(1) For new power plants or arrangements, base your initial deduction on estimates of allowable electricity generation costs for the applicable period. Use the most recently available operations data for the power plant or, if such data are not available, use estimates based on data for similar power plants.

(2) When actual cost information is available, you must amend your prior Form MMS-2014 reports to reflect actual generating cost deductions for each month for which you reported and paid based on estimated generating costs. You must pay any additional royalties due (together with interest computed under § 218.302). You are entitled to a credit for or refund of any overpaid royalties.

(n) In conducting reviews and audits, MMS may require you to submit arm's-length power plant contracts, production agreements, operating agreements, related documents and all other data used to calculate the deduction. You must comply with any such requirements within the time MMS specifies. Recordkeeping requirements are found at part 212 of this chapter.

(o) At the completion of power plant dismantlement and salvage operations, you may report a credit for or request a refund of royalty in an amount equal to the royalty rate times the amount by which actual power plant dismantlement costs exceed actual income attributable to salvage of the power plant.

How do I calculate royalty due on geothermal resources I sell at arm's length to a purchaser for direct use?

If you sell geothermal resources produced from Class I, II, or III leases at arm's length to a purchaser for direct use, then the royalty on the geothermal resource is the gross proceeds accruing to you from the sale of the geothermal resource to the arm's-length purchaser multiplied by the royalty rate in your lease or that BLM prescribes under 43 CFR 3211.18. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales.

How do I calculate royalty or fees due on geothermal resources I use for direct use purposes?

If you use the geothermal resource for direct use:

(a) For Class I leases, you must determine the royalty due on geothermal resources in accordance with the first applicable of the following three paragraphs.

(1) The weighted average of the gross proceeds established in arm's-length contracts for the purchase of significant quantities of geothermal resources to operate the lessee's same direct-use facility multiplied by the royalty rate in your lease. In evaluating the acceptability of arm's-length contracts, the following factors will be considered: time of execution, duration, terms, volume, quality of resource, and such other factors as may be appropriate to reflect the value of the resource.

(2) The equivalent value of the least expensive, reasonable alternative energy source (fuel) multiplied by the royalty rate in your lease. The equivalent value of the least expensive, reasonable alternative energy source will be based on the amount of thermal energy that would otherwise be used by the direct use facility in place of the geothermal resource. That amount of thermal energy (in Btu) displaced by the geothermal resource will be determined by the equation:

Where hin is the enthalpy in Btu/lb at the direct use facility inlet (based on measured inlet temperature), hout is the enthalpy in Btu/lb at the facility outlet (based on measured outlet temperature), density is in lbs/cu ft based on inlet temperature, the factor 0.113681 (cu ft/gal) converts gallons to cubic feet, and volume is the quantity of geothermal fluid in gallons produced at the wellhead or measured at an approved point. The efficiency factor of the alternative energy source will be 0.7 for coal and 0.8 for oil, natural gas, and other fuels derived from oil and natural gas, or an efficiency factor proposed by the lessee and approved by MMS. The methods of measuring resource parameters (temperature, volume, etc.) and the frequency of computing and accumulating the amount of thermal energy displaced will be determined and approved by BLM under 43 CFR 3275.13-3275.17.

(3) A royalty determined by any other reasonable method approved by MMS or the Assistant Secretary, Land and Minerals Management of the Department of the Interior, under § 206.364 of this part.

(b) For geothermal resources produced from Class II and Class III leases, you must multiply the appropriate fee from the schedule in subparagraph (b)(1) of this section by the number of gallons or pounds you produce from the direct use lease each month.

(1) You must use the following fee schedule to calculate fees due under this section:

Direct Use Fee Schedule

[Hot water]

If your average monthly inlet temperature (°F) isYour fees are . . .
At least . . .But less than . . .($/million gallons)($/million pounds)
1301402.5240.307
Start Printed Page 24464
1401507.5490.921
15016012.5431.536
16017017.5032.150
17018022.4262.764
18019027.3103.379
19020032.1533.993
20021036.9554.607
21022041.7105.221
22023046.4175.836
23024051.0756.450
24025055.6827.064
25026060.2367.679
26027064.7368.293
27028069.1768.907
28029073.5589.521
29030077.87610.136
30031082.13310.750
31032086.32811.364
32033090.44511.979
33034094.50112.593
34035098.48113.207
350360102.38713.821

(i) For direct use geothermal resources with an average monthly inlet temperature of 130 °F or less, you must pay only the lease rental.

(ii) The MMS, in consultation with BLM, will develop and publish a revised fee schedule in the Federal Register, as needed.

(iii) The MMS, in consultation with BLM, will calculate revised fees schedules using the following formulas:

Where:

RV = Royalty due as a function of produced volume in the fee schedule, expressed as dollars per million (106) gallons;

Rm = Royalty due as a function of produced mass in the fee schedule, expressed as dollars per million (106) pounds;

ρ[rho] = Water density at inlet temperature expressed as lbs per gallon;

Tin = Measured inlet temperature in °F (as required by BLM under 43 CFR part 3275);

Tout = Established assumed outlet temperature of 130° F;

e = Boiler Efficiency Factor for coal of 70 percent;

Pprbc = The 3-year historical average of Powder River Basin spot coal prices, as published by the Energy Information Administration, or other recognized authoritative reference source of coal prices, in dollars (per MMBtu);

Frr = The assumed Lease Royalty Rate of 10 percent.

(2) The fee that you report is subject to monitoring, review, and audit.

(3) The schedule of fees established under this paragraph will apply to any Class III lease with respect to any royalty payments previously made when the lease was a Class I lease that were due and owing, and were paid, on or after July 16, 2003. To use this provision, you must provide MMS data showing the amount of geothermal production in pounds or gallons of geothermal fluid to input into the fee schedule (see 43 CFR part 3276).

(i) If the royalties you previously paid are less than the fees due under this section, you must pay the difference plus interest on that difference computed under § 218.302.

(ii) If the royalties you previously paid are more than the fees due under this section, then you are entitled to a refund or credit from MMS of 50 percent of the overpaid royalties. You are also entitled to a refund or credit of any interest that you paid on the overpaid royalties.

(c) For geothermal resources other than hot water, MMS will determine fees on a case-by-case basis.

How do I calculate royalty due on byproducts?

(a) If you sell byproducts, you must determine the royalty due on the byproducts that are royalty-bearing under:

(1) Applicable lease terms of Class I leases and of Class III leases that do not elect to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005, under 43 CFR 3200.7(a)(2), or

(2) Applicable statutory provisions at 30 U.S.C. 1004(a)(2) for Class II leases and for Class III leases that do elect to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005, under 43 CFR 3200.7(a)(2).

(b) You must determine the royalty due on the byproducts by multiplying the royalty rate in your lease or that BLM prescribes under 43 CFR 3211.19 by a value of the byproducts determined in accordance with the first applicable of the following subparagraphs: Start Printed Page 24465

(1) The gross proceeds accruing to you from the arm's-length sale of the byproducts, less any applicable byproduct transportation allowances determined under §§ 206.358 and 206.359. See § 206.361 for additional provisions applicable to determining gross proceeds;

(2) Other relevant matters including, but not limited to, published or publicly available spot-market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the saleability of certain byproducts; or

(3) Any other reasonable valuation method approved by MMS.

What are byproduct transportation allowances?

(a) When you determine the value of byproducts at a point off the geothermal lease, unit, or participating area, you are allowed a deduction in determining value, for royalty purposes, for your reasonable, actual costs incurred to:

(1) Transport the byproducts from a Federal lease, unit, or participating area to a sales point or point of delivery that is off the lease, unit, or participating area; or

(2) Transport the byproducts from a Federal lease, unit, or participating area, or from a geothermal use facility to a byproduct recovery facility when that byproduct recovery facility is off the lease, unit, or participating area and, if applicable, from the recovery facility to a sales point or point of delivery off the lease, unit, or participating area.

(b) Costs for transporting geothermal fluids from the lease to the geothermal use facility, whether on or off the lease, are not includible in the byproduct transportation allowance.

(c)(1) When you transport byproducts from a lease, unit, participating area, or geothermal use facility to a byproduct recovery facility, you are not required to allocate transportation costs between the quantity of marketable byproducts and the rejected waste material. The byproduct transportation allowance is authorized for the total production that is transported. You must express byproduct transportation allowances as a cost per unit of marketable byproducts transported.

(2) For byproducts that are extracted on the lease, unit, participating area, or at the geothermal use facility, the byproduct transportation allowance is authorized for the total byproduct that is transported to a point of sale off the lease, unit, or participating area. You must express byproduct transportation allowances as a cost per unit of byproduct transported.

(3) You may deduct transportation costs only when you sell, deliver, or otherwise utilize the transported byproduct and report and pay royalties on the byproduct.

(d) Reporting requirements. (1) You must use a discrete field on Form MMS-2014 to notify MMS of a transportation allowance.

(2) In conducting reviews and audits, MMS may require you to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. You must comply with any such requirements within the time MMS specifies. Recordkeeping requirements are found at part 212 of this chapter.

(e) Byproduct transportation allowances are subject to monitoring, review, and audit. If, after a review or audit, MMS determines that you have improperly determined a byproduct transportation allowance, you must pay any additional royalties due (plus interest computed under § 218.302). You are entitled to a credit for or refund of any overpaid royalties.

(f) If you commingled byproducts produced from Federal and non-Federal leases for transportation, you may not disproportionately allocate transportation costs to Federal lease production.

How do I determine byproduct transportation allowances?

(a) For transportation costs you incur under an arm's-length contract, the transportation allowance will be the reasonable, actual costs you incurred for transporting the byproducts under that contract.

(1) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from you to the transporter for the transportation. If the contract reflects more than the total consideration you paid, MMS may require you to determine the byproduct transportation allowance under paragraph (b) of this section.

(2) If MMS determines that the consideration you paid under an arm's-length byproduct transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, MMS will require you to determine the byproduct transportation allowance under paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify you and give you an opportunity to provide written information justifying your transportation costs.

(3) Where your payments for transportation under an arm's-length contract are not established on a dollars-per-unit basis, you must convert whatever consideration you paid to a dollar value equivalent for the purposes of this section.

(b) If you transport the byproduct yourself or under a non-arm's-length transportation arrangement, the byproduct transportation allowance is your reasonable actual costs for transportation during the reporting period, including:

(1) Operating and maintenance expenses under paragraphs (d) and (e) of this section;

(2) Overhead under paragraph (f) of this section; and either

(3) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section; or

(4) A return on capital investment in the transportation system under paragraphs (g) and (j) of this section.

(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transportation system.

(2)(i) You may include a return on capital you invested in the purchase of real estate to locate the byproduct transportation facilities if:

(A) The purchase is necessary; and

(B) The surface is not part of a Federal lease.

(ii) The rate of return will be the same rate determined in paragraph (k) of this section.

(3) You may not deduct the costs of gathering systems and other production-related facilities.

(d) Allowable operating expenses include:

(1) Operations supervision and engineering;

(2) Operations labor;

(3) Fuel;

(4) Utilities;

(5) Materials;

(6) Ad valorem property taxes;

(7) Rent;

(8) Supplies; and

(9) Any other directly allocable and attributable operating expense that you can document.

(e) Allowable maintenance expenses include:

(1) Maintenance of the transportation system;

(2) Maintenance of equipment; Start Printed Page 24466

(3) Maintenance labor; and

(4) Other directly allocable and attributable maintenance expenses that you can document.

(f) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(g) To compute costs associated with capital investment, a lessee may use either paragraphs (h) and (i) or paragraph (j) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without MMS approval.

(h)(1) To compute depreciation, you must use a straight-line depreciation method based on either the life of the equipment or the life of the geothermal project which the transportation system services. After you choose the basis for depreciation, you may not change that basis without MMS approval. You may not depreciate equipment below a reasonable salvage value.

(2) A change in ownership of a transportation system does not alter the depreciation schedule established by the original lessee-owner for purposes of computing transportation costs.

(3) With or without a change in ownership, you may depreciate a transportation system only once.

(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the transportation allowance by the rate of return provided in paragraph (k) of this section.

(j) To compute a return on capital investment in the transportation system, the allowed cost will be the amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.

(k) The rate of return must be the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. You must redetermine the rate at the beginning of each subsequent calendar year.

(l)(1) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable byproduct transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems.

(2) When actual cost information is available, you must amend your prior Form MMS-2014 reports to reflect actual byproduct transportation cost deductions for each month for which you reported and paid based on estimated byproduct transportation costs. You must pay any additional royalties due (together with interest computed under § 218.302). You are entitled to a credit for or a refund of any overpaid royalties.

What records must I keep to support my calculations of royalty or fees under this subpart?

If you determine royalties or direct use fees for your geothermal resource under this subpart, you must retain all data relevant to the determination of the royalty value or the fee you paid. Recordkeeping requirements are found at part 212 of this chapter.

(a) You must be able to show:

(1) How you calculated the royalty value or fee you reported, including all allowable deductions; and

(2) How you complied with this subpart.

(b) Upon request, you must submit all data to MMS. You must comply with any such requirement within the time MMS specifies.

How will MMS determine whether my royalty or direct use fee payments are correct?

(a)(1) The royalties or direct use fees that you report are subject to monitoring, review, and audit. The MMS may review and audit your data, and MMS will direct you to use a different measure of royalty value, gross proceeds, or fee, whichever is applicable, if it determines that the reported value, gross proceeds, or fee is inconsistent with the requirements of this subpart.

(2) If MMS directs you to use a different royalty value, measure of gross proceeds, or fee, you must either pay any royalties or fees due (together with interest computed under § 218.302) or report a credit for or request a refund of any overpaid royalties or fees.

(b) When the provisions in this subpart refer to gross proceeds either for the sale of electricity or the sale of a geothermal resource, in conducting reviews and audits MMS will examine whether your sales contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to you for the geothermal resource or electricity. If MMS determines that a contract does not reflect the total consideration, or the gross proceeds accruing to you under a contract do not reflect reasonable consideration because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, MMS may require you to increase the gross proceeds to reflect any additional consideration. Alternatively, for Class I leases, MMS may require you to use another valuation method in the regulations applicable to dispositions other than under an arm's-length contract. The MMS will notify you to give you an opportunity to provide written information justifying your gross proceeds.

(c) For arm's-length sales, you have the burden of demonstrating that your contract is arm's length.

(d) The MMS may require you to certify that the provisions in your sales contract include all of the consideration the buyer paid you, either directly or indirectly, for the electricity or geothermal resource.

(e) Notwithstanding any other provision of this subpart, under no circumstances will the value of production for royalty purposes under a Class I lease where the geothermal resources are sold before use be less than the gross proceeds accruing to you.

(f) Gross proceeds for the sale of electricity or for the sale of the geothermal resource will be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract.

(1) Absent contract revision or amendment, if you fail to take proper or timely action to receive prices or benefits to which you are entitled, you must pay royalty based upon that obtainable price or benefit.

(2) Contract revisions or amendments you make must be in writing and signed by all parties to the contract.

(3) If you make timely application for a price increase or benefit allowed under your contract, but the purchaser refuses and you take reasonable measures, which are documented, to force purchaser compliance, you will owe no additional royalties unless or until you receive additional monies or consideration resulting from the price increase. This paragraph (f)(3) will not be construed to permit you to avoid your royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of geothermal resources or electricity.

Start Printed Page 24467
What are my responsibilities to place production into marketable condition and to market production?

You must place geothermal resources and byproducts in marketable condition and market the geothermal resources or byproducts for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. If you use gross proceeds under an arm's-length contract in determining royalty, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that the seller normally would be responsible to perform to place the geothermal resources or byproducts in marketable condition or to market the geothermal resources or byproducts.

When is an MMS audit, review, reconciliation, monitoring, or other like process considered final?

Notwithstanding any provision in these regulations to the contrary, no audit, review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of royalty or fees due under this subpart is considered final or binding as against the Federal Government or its beneficiaries until MMS formally closes the audit period in writing.

How do I request a value or gross proceeds determination?

(a) You may request a value determination from MMS regarding any geothermal resources produced from a Class I lease or for byproducts produced from a Class I, Class II, or Class III lease. You may also request a gross proceeds determination for a Class II or Class III lease. Your request must:

(1) Be in writing;

(2) Identify specifically all leases involved, all owners of interests in those leases, and the operator(s) for those leases;

(3) Completely explain all relevant facts. You must inform MMS of any changes to relevant facts that occur before we respond to your request;

(4) Include copies of all relevant documents;

(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and

(6) Suggest your proposed gross proceeds calculation or valuation method.

(b) In response to your request:

(1) The Assistant Secretary, Land and Minerals Management, may issue a determination; or

(2) The MMS may issue a determination; or

(3) The MMS may inform you in writing that MMS will not provide a determination. Situations in which MMS typically will not provide any determination include, but are not limited to:

(i) Requests for guidance on hypothetical situations; and

(ii) Matters that are the subject of pending litigation or administrative appeals.

(c)(1) A determination signed by the Assistant Secretary, Land and Minerals Management, is binding on both you and MMS until the Assistant Secretary modifies or rescinds it.

(2) After the Assistant Secretary issues a determination, you must make any adjustments in royalty payments that follow from the determination and, if you owe additional royalties, pay the royalties owed together with late payment interest computed under § 218.302.

(3) A determination signed by the Assistant Secretary is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.

(d) A determination issued by MMS is binding on MMS and delegated States, but not on you, with respect to the specific situation addressed in the determination unless the MMS (for MMS-issued determinations) or the Assistant Secretary modifies or rescinds it.

(1) A determination by MMS is not an appealable decision or order under 30 CFR part 290 subpart B.

(2) If you receive an order requiring you to pay royalty on the same basis as the determination, you may appeal that order under 30 CFR part 290 subpart B.

(e) In making a determination, MMS or the Assistant Secretary may use any of the applicable criteria in this subpart.

(f) A change in an applicable statute or regulation on which any determination is based takes precedence over the determination after the effective date of the statute or regulation, regardless of whether the MMS or the Assistant Secretary modifies or rescinds the determination.

(g) The MMS or the Assistant Secretary generally will not retroactively modify or rescind a determination issued under paragraph (d) of this section, unless:

(1) There was a misstatement or omission of material facts; or

(2) The facts subsequently developed are materially different from the facts on which the guidance was based.

(h) The MMS may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 206.365.

Does MMS protect information I provide?

Certain information you submit to MMS regarding royalties or fees on geothermal resources or byproducts, including deductions and allowances, may be exempt from disclosure. To the extent applicable laws and regulations permit, MMS will keep confidential any data you submit that is privileged, confidential, or otherwise exempt from disclosure. All requests for information must be submitted under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.

What is the nominal fee that a State, tribal, or local government lessee must pay for the use of geothermal resources?

If a State, tribal, or local government lessee uses a geothermal resource without sale and for public purposes—other than commercial production or generation of electricity—the State, tribal, or local government lessee must pay a nominal fee. A nominal fee means a slight or de minimis fee. The MMS will determine the fee on a case-by-case basis.

Start Part

PART 210—FORMS AND REPORTS

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6. The authority for part 210 continues to read as follows:

End Amendment Part Start Authority

Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396, 2107; 30 U.S.C. 189, 190, 359, 1023, 1751(a); 31 U.S.C. 3716, 9701; 43 U.S.C. 1334, 1801 et seq.; and 44 U.S.C. 3506(a).

End Authority

Subpart H—Geothermal Resources

[Removed] and §§ 210.353 through 210.355 [Redesignated]
Start Amendment Part

7. Remove § 210.352, and redesignate §§ 210.353 through 210.355 as §§ 210.352 through 210.354, respectively.

End Amendment Part Start Amendment Part

8. Revise redesignated § 210.354 to read as follows:

End Amendment Part
Reporting Instructions.

Specific guidance on how to prepare and submit required information collection reports and forms to MMS is contained in the publication titled Minerals Revenue Reporter Handbook—Oil, Gas, and Geothermal Resources, which is available from the Minerals Management Service, Minerals Revenue Management, Financial Management, P.O. Box 25165, Mail Stop 350B1, Denver, CO 80225-0165. For copies from the MMS Web site, go to http://www.mrm.mms.gov/​. Click Reporting Information and select the topic.

Start Part Start Printed Page 24468

PART 217—AUDITS AND INSPECTIONS

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9. The authority for part 217 continues to read as follows:

End Amendment Part Start Authority

Authority: 35 Stat. 312; 35 Stat. 781, as amended; secs. 32, 6, 26, 41 Stat. 450, 753, 1248; secs. 1, 2, 3, 44 Stat. 301, as amended; secs. 6, 3, 44 Stat. 659, 710; secs. 1, 2, 3, 44 Stat. 1057; 47 Stat. 1487; 49 Stat. 1482, 1250, 1967, 2026; 52 Stat. 347; sec. 10, 53 Stat. 1196, as amended; 56 Stat. 273; sec. 10, 61 Stat. 915; sec. 3, 63 Stat. 683; 64 Stat. 311; 25 U.S.C. 396, 396a-f, 30 U.S.C. 189, 271, 281, 293, 359. Interpret or apply secs. 5, 5, 44 Stat. 302, 1058, as amended; 58 Stat. 483-485; 5 U.S.C. 301; 16 U.S.C. 508b; 30 U.S.C. 189, 192c, 271, 281, 293, 359; and 43 U.S.C. 387, unless otherwise noted.

End Authority Start Amendment Part

10. Add a new subpart G to read as follows:

End Amendment Part

Subpart G—Geothermal Resources

217.300
Audits or review of records.
217.301
Lease account reconciliations.
217.302
Definitions.
Audit or review of records.

The Secretary, or his/her authorized representative, will initiate and conduct audits or reviews relating to the scope, nature, and extent of compliance by lessees, operators, revenue payors, and other persons with rental, royalty, fees, and other payment requirements on a Federal geothermal lease. Audits or reviews will also relate to compliance with applicable regulations and orders. All audits or reviews will be conducted in accordance with this part.

Lease account reconciliations.

Specific lease account reconciliations will be performed with priority being given to reconciling those lease accounts specifically identified by a State as having significant potential for underpayment.

Definitions.

Terms used in this subpart will have the same meaning as in 30 U.S.C. 1702.

Start Part

PART 218—COLLECTION OF ROYALTIES, RENTALS, BONUSES AND OTHER MONIES DUE THE FEDERAL GOVERNMENT

End Part Start Amendment Part

11. Revise the heading for part 218 to read as follows:

End Amendment Part Start Part

PART 218—COLLECTION OF ROYALTIES, RENTALS, BONUSES, AND OTHER MONIES DUE THE FEDERAL GOVERNMENT AND CREDITS AND INCENTIVES DUE LESSEES

End Part Start Amendment Part

12. The authority for part 218 continues to read as follows:

End Amendment Part Start Authority

Authority: 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq.; 1701 et seq.; 31 U.S.C. 3335; 43 U.S.C. 1301 et seq.; 1331 et seq., and 1801 et seq.

End Authority Start Amendment Part

13. Add new §§ 218.303 through 218.307 to subpart F to read as follows:

End Amendment Part

Subpart F—Geothermal Resources

* * * * *
May I credit rental towards royalty?

(a)(1) For Class II leases as defined in 30 CFR 206.351, and for Class III leases as defined in that section that elect under 43 CFR 3200.7(a)(2) to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005 you may credit the annual rental that you paid before the first day of the year for which the annual rental is owed against the royalty due for the lease year for which the rental was paid. You may not apply any annual rental paid in excess of the royalty due for a particular lease year as a credit against any royalty due in any subsequent lease year.

(2) For purposes of this section, the term “royalty” includes any advanced royalty payable under 30 U.S.C. 1004(f) for a cessation of production.

(b) If portions of your lease are located both within and outside of a participating area, you may credit against royalty under paragraph (a) only that percentage of the rental you paid that corresponds to the percentage of the lease within the participating area on a per-acre basis.

May I credit rental towards direct use fees?

You may not credit annual rental toward direct use fees you are required to pay that year under § 206.356(b). You must pay the direct use fees in addition to the annual rental due.

How do I pay advanced royalties I owe under BLM regulations?

If you pay advanced royalties under 43 CFR 3212.15(a)(1) to retain your lease:

(a) You must pay an advanced royalty monthly equal to the average monthly royalty you paid under 30 CFR part 206, subpart H (including the amount against which you applied the annual rental as a credit) for the last 3 years the lease was producing. If your lease has been producing for less than 3 years, then use the average monthly royalty payment for the entire period your lease has been producing continuously;

(b) The MMS must receive your advanced royalty payment before the end of each full calendar month in which no production occurs;

(c) You may credit any advanced royalty you pay against production royalties you owe after your lease resumes production. You may not reduce the amount of any production royalty paid for any year below zero.

May I receive a credit against production royalties for in-kind deliveries of electricity I provide under contract to a State or county government?

(a) You may receive a credit against royalties for in-kind deliveries of electricity you provide under contract to a State or county government if:

(1) The State or county to which you provide electricity would receive a portion of the royalties you paid in money for the lease under 30 U.S.C. 191 or 30 U.S.C. 1019, except as otherwise provided under the Mineral Leasing Act for Acquired Lands, 30 U.S.C. 355, because your lease is located in that State or county. If your lease is located in more than one State or county, the revenues are paid to the respective States or counties based on their proportionate shares of the total acres in the lease;

(2) The MMS approves in advance your contract with the State or county to which you are providing in-kind electricity; and

(3) Your contract provides that you will use the wholesale value of the electricity for the area where your lease is located to establish the specific methodology to determine the amount of the credit; and

(b) The maximum credit you may take under this section is equal to the portion of the royalty revenue that MMS would have paid to the State or county that is a party to the contract had you paid royalty in money on all of the electricity you delivered to the State or county based on the wholesale value of the electricity. You must pay in money any royalty amount that is not offset by the credit allowed under this section, calculated based on the wholesale value of the electricity.

(c) The electricity the State or county government receives from you satisfies the Secretary's payment obligation to the State or county under 30 U.S.C. 191 or 30 U.S.C. 1019.

How do I pay royalties due for my existing leases that qualify for near-term production incentives under BLM regulations?

If you qualify for a production incentive under BLM regulations at 43 CFR subpart 3212, your royalty due on the production BLM determines to be qualified for a production incentive under 43 CFR 3212.23 and 3212.24 is 50 percent of the amount of the total Start Printed Page 24469royalty that would otherwise be due under 30 CFR part 206, subpart H.

End Supplemental Information

[FR Doc. E7-7952 Filed 5-1-07; 8:45 am]

BILLING CODE 4310-MR-P