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Proposed Rule

Geothermal Valuation

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AGENCY:

Minerals Management Service (MMS), Interior.

ACTION:

Proposed rule.

SUMMARY:

The MMS is proposing new regulations implementing 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 would amend the current MMS geothermal royalty valuation regulations and simplify the royalty calculations for geothermal resources for leases issued under the EPAct and leases whose terms are modified under the EPAct. The new regulations would also amend various related provisions in the MMS rules.

DATES:

Comments must be submitted on or before September 19, 2006.

ADDRESSES:

You may submit comments on the rulemaking by any of the following methods listed below. Please use the Regulation Identifier Number (RIN) 1010-AD32 in your message. See also Public Comment Procedure under Procedural Matters:

  • Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions on the Web site for submitting comments.
  • E-mail: mrm.comments@mms.gov. Please include “Attn: RIN 1010-AD32” and your name and return address in your Internet message. If you do not receive a confirmation that we have received your Internet message, call the contact person listed below.
  • Regular U.S. Mail: Minerals Management Service, Minerals Revenue Management, Chief of Staff Office—Denver, P.O. Box 25165, MS 302B2, Denver, Colorado 80225-0165.
  • Overnight mail, courier, or hand-delivery: Minerals Management Service, Minerals Revenue Management, Building 85, Room A-614, West 6th Ave. and Kipling Blvd., Denver Federal Center, Denver, Colorado 80225.

Information Collection Request (ICR) Comments: Submit written comments by either fax (202) 395-6566 or e-mail (OIRA_Docket@omb.eop.gov) directly to the Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), Attention: Desk Officer for the Department of the Interior [OMB Control Number ICR 1010-NEW) as it relates to the proposed geothermal valuation rule].

Please also send a copy of your comments to MMS via e-mail 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.

You may also mail a copy of your comments to Sharron 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 or wish to hand-deliver your comments, our courier address is Building 85, Room A-614, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

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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 of the Office of the Solicitor and Herb Black of MRM, MMS, Department of the Interior.

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SUPPLEMENTARY INFORMATION:

I. Background

A. Pre-EPAct Statutory Provisions and Current Regulations

Under the GSA (30 U.S.C. 1001 et seq.) before its amendment by the EPAct (Pub. L. No. 109-58, 119 Stat. 594), geothermal leases were issued with a reserved royalty of not less than 10 percent and not more than 15 percent “of the amount or value of steam, or any other form of heat or energy derived from production under the lease and sold or utilized by the lessee * * *.” 30 U.S.C. 1004(a) (emphasis added). The leases further provide for a royalty of not less than 5 percent “of the value of any byproduct derived from production under the lease * * *.” 30 U.S.C. 1004(b). The GSA further grants the Secretary broad rulemaking authority. 30 U.S.C. 1023. The lease instruments also reserved to the Secretary the authority to establish the value of geothermal production or byproducts for royalty purposes. Under these provisions, the current rules for valuing geothermal resources for royalty purposes at 30 CFR 206.350-206.358 were promulgated in 1991.

Currently, there are 50 producing Federal geothermal leases in Utah, New Mexico, California, and Nevada. These leases comprise 15 electrical generation projects and 2 direct use projects (an onion drying plant and a project that uses geothermal heat to preheat boiler water). Royalty revenues from Federal geothermal leases totaled approximately $11,000,000 in 2004. Fifty percent of those revenues go to the states in which the leases are located (30 U.S.C. 191(a)).

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.

In an earlier effort to streamline the MMS geothermal regulations, on October 28, 2004, MMS's Royalty Policy Committee (RPC) formed the Geothermal Valuation Subcommittee (Subcommittee) to address the MMS geothermal royalty valuation regulations in an effort 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. 595. 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).

This proposed rule would implement the EPAct provisions. It also would incorporate most of the Subcommittee's concepts, with modifications necessary to comply with the EPAct. This proposed rule: Start Printed Page 41517

  • For 30 CFR part 206, subpart H: (1) Explains the general royalty calculation and payment, direct use fee, and royalty valuation provisions of this subpart; (2) defines which leases the subpart applies to; (3) provides definitions of terms used in the subpart; (4) proposes some changes to conform to plain English writing; and (5) proposes changes necessary to implement provisions of the EPAct.
  • For 30 CFR parts 202, 210, 217, and 218: (1) Proposes changes necessary to implement provisions of the EPAct; and (2) reflect the proposed amendments to 30 CFR part 206, subpart H.

II. Explanation of Proposed Amendments

Before reading the additional explanatory information below, please turn to the proposed rule language that we would codify in the Code of Federal Regulations (CFR) if this rule is finalized as written. The rule language immediately follows the “List of Subjects in 30 CFR parts 202, 206, 210, 217, and 218.”

When you have read the rule thoroughly, please return to the preamble discussion below. The preamble contains additional information about the proposed rule, such as why we defined a term in a certain manner, why we chose a certain procedure, and how we interpret the law this rule implements.

A. Section-by-Section Analysis of 30 CFR Part 202—Royalties, Subpart H—Geothermal Resources

The MMS proposes to amend 30 CFR 202.351 and 202.353 in several respects. First, we rewrote those sections in plain English, added the term “fees” where applicable to reflect the fees in lieu of royalties that proposed 30 CFR 206.356(b) would prescribe. We also have referred to 30 CFR part 206, subpart H, where appropriate.

Second, paragraph 202.351(a) currently states that all royalties must be paid “in-value.” In this context, the term “in-value” refers to payment in money, not to royalty valuation. Because the EPAct now allows lessees a credit against royalties owed on geothermal resources for delivery of electricity “in-kind” to states and counties that would receive a portion of royalty revenues, and to avoid confusion in situations where MMS will not be determining royalty value, we would revise the provision in paragraph (a) to read: “Except for the amount credited against royalties for in-kind deliveries of electricity to a state or county under 30 CFR 218.306, you must pay royalties and direct use fees in money.”

Finally, we would 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.” Like the other quantity reporting requirements in this section, “to the nearest whole” means that if you produce 1,500,000.00 pounds of the geothermal resource, you would report the quantity as 2 million (2,000,000.00) pounds. Likewise, if you produce 1,499,000.00 pounds, you would report 1 million (1,000,000.00) pounds.

B. Section-by-Section Analysis of 30 CFR Part 206—Product Valuation, Subpart H—Geothermal Resources

What is the purpose of this subpart? (Proposed § 206.350)

Paragraph (a) of this section would explain what leases are subject to this subpart. This subpart would be applicable to all geothermal resources produced from Federal geothermal leases issued under the GSA, as amended by the EPAct. It also would explain that the purpose of this subpart is to prescribe how to calculate royalties and fees on geothermal production.

Paragraph (b) would explain that MMS may audit and adjust all royalty and fee payments.

Paragraph (c) would ensure that if the regulations in this subpart are inconsistent with a statute, settlement agreement, written agreement, or lease provision, then that provision, not the regulation, will govern to the extent of the inconsistency. This is particularly important in this proposed rulemaking to ensure that the provisions of the negotiated valuation agreements MMS and lessees entered into prior to this rulemaking remain unaffected by this rulemaking.

What definitions apply to this subpart? (Proposed § 206.351)

This section would explain the definitions applicable to this subpart. For purposes of discussion, this preamble will discuss only new or modified definitions, except modifications to existing language to use plain English that do not make substantive changes.

The MMS proposes to add a definition of the term affiliate and revise the definition of the term arm's-length contract to be identical to the June 2000 Federal crude oil valuation rule published March 15, 2000 (65 FR 14022), and the March 2005 Federal gas valuation rule published March 10, 2005 (70 FR 11869) (collectively “Federal oil and gas valuation rules”), and to conform the geothermal valuation rule with the D.C. Circuit's holding in National Mining Association v. Department of the Interior, 177 F.3d 1 (D.C. Cir. 1999). As in the Federal oil and gas valuation rules, MMS is proposing to define the term affiliate separately from the term arm's length-contract. We believe this clarifies and simplifies the definitions and should promote better understanding of both arm's-length contract and affiliate. For a full explanation of the reasons for this proposed change to the definitions, see the discussion in the preamble to the June 2000 final crude oil valuation rule at 65 FR 14039-14040.

The MMS also proposes to add definitions of allowance and byproduct transportation allowance to this subpart.

In the EPAct, Congress added a provision regarding the royalty rate applicable to those byproducts that are minerals specified in the Mineral Leasing Act of 1920, 30 U.S.C. 181. The EPAct provision was silent regarding other byproducts, which therefore are not affected. The proposed definition of byproducts includes both those that are minerals identified in 30 U.S.C. 181 and those that are not.

The proposed rule also would define three classes of leases, because the royalty calculation method a lessee must use depends on the type of lease. A Class I lease would mean (1) a lease BLM issued under the GSA before August 8, 2005, which the lessee does not elect to convert to a Class II lease (defined below) under BLM's proposed rule at 43 CFR 3212.25, or (2) a lease BLM issued in response to a lease application that was pending on August 8, 2005, which the lessee does not elect to convert to a Class II lease under BLM's proposed regulations at 43 CFR 3200.8. A Class II lease would mean a geothermal lease BLM issued on or after the effective date of the final BLM regulation under 43 CFR parts 3203, 3204, or 3205, except for a lease issued in response to an application that was pending on August 8, 2005, which the lessee elects not to convert to a Class II lease under 43 CFR 3200.8. A Class III lease would mean a Class I lease that the lessee converts to a Class II lease under 43 CFR 3212.25.

In the EPAct, Congress enacted the new definition of direct use discussed below. Part of that definition included the term commercial production of electricity, but did not define that term. Other sections of the EPAct (see the new 30 U.S.C. 1004(b), added by EPAct Start Printed Page 41518§ 223(a), and new 30 U.S.C. 1003(f), added by EPAct § 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.

As a technical amendment, § 236(g) of the EPAct defined direct use to mean the use of geothermal resources from Class I, II, or III leases “for commercial, residential, agricultural, public facilities, or other energy needs, other than the commercial production of electricity.” Thus, we are proposing to use that definition, but substituting the word “generation” for “production” for consistency and accuracy.

We propose to change direct utilization facility in the current rule to direct use facility to conform to the new definition of direct use.

The definition of lease would remain the same as in the existing rule.

Lessee (you) would mean 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 would include 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.

The term lessee also would include 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. We added the lessee's affiliate to the definition to eliminate the need to have separate regulations for non-arm's-length sales or use of geothermal resources without sale.

We changed the definition of marketable condition to more closely conform to the definition contained in other subparts of part 206. Thus, marketable condition would mean 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 of such lease products produced from the field or area.

Plant parasitic electricity would be defined to mean the amount of electricity used to run a power plant. This term has always been in the definition of plant tailgate electricity. Therefore, for clarity, we propose to define it in this rulemaking.

Public purpose would mean 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. This is the same definition the Department has already promulgated under 43 CFR 2740.0-5. As discussed further in our comments to new § 206.366 below, in the EPAct § 223(a), Congress authorized the Secretary to charge nominal fees for a state, tribal, or local government lessee's use of geothermal resources without sale for “public purposes.” We added this definition because Congress did not define public purpose.

The Department did not define public safety or welfare in 43 CFR part 2740. Therefore, we propose to use the definition already used by the Federal Government in its Federal Property Management Regulations found at 41 CFR part 102-37, Appendix C. Those regulations state that 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 programs may include, but are not limited to, those 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).

How do I calculate the royalty due on geothermal resources used for commercial generation of electricity? (Proposed § 206.352)

This section would explain how you must calculate the royalty due on geothermal resources used to generate electricity.

Paragraph (a) would apply to Class I, II, and III leases where the lessee sold the geothermal resources at arm's length and the purchaser uses the resource to generate electricity. (The MMS presently knows of no such current situations, but we anticipate the possibility that some lessees may enter into such arrangements in the future.) The RPC recommended that in such instances, the lessee should pay a royalty based on a royalty rate in the lease multiplied by the gross proceeds the lessee derives from the sale of geothermal resources. The RPC recommended no change in royalty valuation under the current rules or in royalty rates for new or existing leases. The EPAct is silent regarding the situation where the lessee sells the resource to an unaffiliated purchaser that produces electricity, rather than producing the electricity itself. Therefore, we are proposing to accept the RPC recommendations to base royalties for existing (Class I), new (Class II), and converted or pending application (Class III) leases, on the gross proceeds from the sale of the geothermal resource to the arm's-length purchaser.

For non-arm's length-sales of geothermal resources used for electrical generation, the RPC recommended that MMS negotiate with each lessee to determine the value of the geothermal resources sold under non-arm's-length or no sales situations. Although lessees may still request such a methodology under § 206.364 of this subpart, we believe it is much simpler, and more consistent with the EPAct and the Federal oil and gas valuation rules, to base royalties on the gross proceeds from the affiliate's sale of the geothermal resource. As explained above, the gross proceeds accruing to the lessee would include the lessee's affiliate's arm's-length sale of the geothermal resource. This eliminates the necessity of examining “comparable arm's-length contracts” when the lessee transfers to its affiliate, and the affiliate then sells the resource at arm's length. It also eliminates the need for a geothermal netback procedure wherein the lessee would have the burden of determining the value of the geothermal resource based on the sales of electricity by an unrelated purchaser.

Paragraph (b) would explain how to value a geothermal resource for each class of lease in “no sales” situations, i.e, where you or your affiliate use the geothermal resource in your own power plant for the generation and sale of electricity. The RPC did not address this situation, so we kept the current rule language for Class I leases, with some modifications discussed below, and followed the EPAct for Class II and III leases.

Thus, under subparagraph (b)(1), for Class I leases, the royalty on geothermal resources produced would be Start Printed Page 41519determined in accordance with the first applicable of the following paragraphs:

(1) The gross proceeds accruing from the arm's-length sale of the electricity less applicable deductions determined under §§ 206.353 and 206.354 times the royalty rate in the lease. This is essentially the old geothermal netback procedure. However, it is less burdensome because a lessee who generates and sells electricity will have all of the necessary information. Furthermore, as explained above, because an affiliate's arm's-length sale of electricity is the lessee's gross proceeds, there is no need to distinguish between arm's-length and non-arm's-length sales. Finally, this subparagraph also would explain that under no circumstances shall the deductions reduce the royalty value of the geothermal resource to zero; or

(2) A royalty determined by any other valuation method approved by MMS under § 206.364.

Subparagraph (2) would apply to Class II leases. In EPAct § 224(a)(1), Congress prescribed a royalty on electricity produced using geothermal resources, other than direct use of geothermal resources of:

(1) Not less than 1 percent and not more than 2.5 percent of the gross proceeds from the sale of electricity produced from such geothermal resources during the first 10 years of production under the lease; and

(2) Not less than 2 and not more than 5 percent of the gross proceeds from the sale of electricity produced from such geothermal resources during each year after such 10-year period.

Congress also specified that any regulation implementing EPAct § 224(a)(1) should seek:

(1) To provide lessees a simplified administrative system;

(2) to encourage new development; and

(3) to achieve the same level of royalty revenues over a 10-year period as the regulation in effect on the date of enactment of this subsection.

Therefore, for Class II leases, MMS is proposing a simple methodology where the royalty on geothermal resources produced would be your gross proceeds from the sale of electricity for the production month multiplied by the royalty rate BLM prescribed for your lease under proposed 43 CFR 3211.17, its regulation implementing § 224(a)(1) of the EPAct. Because the royalty rate BLM prescribes will take into account achieving the same level of royalty revenues over a 10-year period as the regulation in effect on the date of enactment of the EPAct, it will have taken into account any possible deductions that would have been available under the current regulations and should achieve the same level of royalty revenues over the next 10 years as the current regulations. Accordingly, this paragraph of the proposed regulation would not allow any deductions. In addition, because this proposal greatly simplifies the valuation methodology, it should encourage new development.

Subparagraph (3) would apply to Class III leases. For Class III leases, in EPAct § 224(e)(1)(b), Congress prescribed that royalties be computed on a percentage of the gross proceeds from the sale of electricity, at a royalty rate that is expected to yield total royalty payments equivalent to payments that would have been received for comparable production under the royalty rate in effect for the lease before the date of enactment of this subsection. Thus, we are proposing to require you to calculate the royalty on geothermal resources produced as your gross proceeds from the sale of electricity for the production month multiplied by the royalty rate BLM calculated for your lease under proposed 43 CFR 3211.17. The royalty rate BLM calculates will be expected to yield total royalty payments equivalent to payments that would have been received for comparable production under the royalty rate in effect for the lease before the date of enactment of the EPAct. Accordingly, that royalty rate will take into account any deductions you were taking prior to the EPAct's enactment. As a result, you would not be allowed to reduce your gross proceeds by any deductions under this subparagraph.

How do I determine transmission deductions? (Proposed § 206.353)

This section would explain how to determine your transmission deductions. We have streamlined and rewritten the current rule in plain English.

The MMS also proposes to amend § 206.353 in two other respects. First, just as we did in the Federal oil and gas valuation rules, we propose to eliminate the requirement that the lessee report its transmission deduction using a separate line entry on the Form MMS-2014. That requirement is no longer relevant because the Form MMS-2014 has been revised. While you still would report the transmission deduction in a discrete field, it would not be strictly on a separate line from associated sales transaction data. The proposal would revise the regulation accordingly.

Second, we also would delete the final paragraph (f) of § 206.353. That paragraph provided for a one-time refund of royalties based on the royalty value of actual dismantlement costs of a transmission line in excess of income value from salvage at the completion of dismantlement and salvage operations. This provision has never been used and is complicated administratively. Therefore, we propose to delete it. This would result in renumbering the section with the corresponding new paragraph (f).

How do I determine generating deductions? (Proposed § 206.354)

This section would explain that if you determine the value of your geothermal resource 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). We propose to rewrite the current rule in plain English form.

We also would delete the final paragraph (f) of § 206.354(f). That paragraph provided for a one-time refund of royalties based on the royalty value of actual dismantlement costs of a power plant in excess of income value from salvage at the completion of dismantlement and salvage operations. This provision has never been used and is complicated administratively. Therefore, we propose to delete it.

How do I calculate royalty due on geothermal resources I sell arm's length to a purchaser for direct use? (Proposed § 206.355)

This section would explain how to calculate royalty on geothermal resources if you sell geothermal resources produced from Class I, II, or III leases at arm's length to a purchaser for direct use. The EPAct did not address such transactions. Therefore, we are proposing that in such instances, the royalty on the geothermal resource would be the gross proceeds accruing to you from the sale of the geothermal resource to the arm's-length purchaser times the royalty rate in your lease or that BLM prescribes under proposed 43 CFR 3211.18.

We believe this valuation methodology would best meet Congress' goals that any regulation implementing EPAct § 224(a)(1) should: (1) provide lessees a simplified administrative system; (2) encourage new development; and (3) achieve the same level of royalty revenues over a 10-year period as the regulation in effect on the date of enactment of this subsection. Start Printed Page 41520

How do I calculate royalty due on geothermal resources I use for direct use purposes? (Proposed § 206.356).

This section would explain how a lessee must calculate royalty on a geothermal resource it uses itself for direct use purposes, i.e., that it does not sell. The Subcommittee recommended that for existing leases, MMS, in consultation with BLM, should develop and publish a royalty schedule every 3 years for lessees to use to determine the royalties due on direct use operations. The Subcommittee also recommended that the royalty schedule be based on the wellhead (inlet) temperature and an “assumed” fixed outlet temperature of 130 °F. In addition, the Subcommittee recommended that the lessee would meter wellhead (inlet) temperature and monthly production and use the published royalty schedule to determine monthly royalties due.

The Subcommittee used the following equation to develop a royalty schedule for determining royalty due as a function of temperature of the geothermal resource used for direct use: where:

RTin = royalty due as a function of inlet temperature, $/106 gallons

ρ = water density at inlet temperature, lbms/gallon

Tin = measured inlet temperature, °F

Tout = established proxy outlet temperature 130 °F

e = boiler efficiency factor for coal (75 percent)

Pprbc = 3-year historical average of Powder River Basin coal ($/MMBtu)

Frr = lease royalty rate.

However, in the EPAct, Congress did not change the royalty provisions for existing leases. Therefore, for Class I leases, we are proposing to keep the existing regulations with minor plain English modifications.

In § 223(a) of the EPAct, for Class II leases, and § 224(e), for Class III leases, Congress did direct the Secretary to:

Establish a schedule of fees, in lieu of royalties for geothermal resources, that a lessee or its affiliate—

(A) Uses for a purpose other than the commercial generation of electricity; and

(B) Does not sell.

Congress also stated that the schedule of fees:

(A) May be based on the quantity or thermal content, or both, of geothermal resources used;

(B) Shall ensure a fair return to the United States for use of the resource; and

(C) Shall encourage development of the resource.

Thus, in paragraph (b), for Class II and Class III leases, we are proposing that lessees calculate the fee for geothermal resources they use for direct use by multiplying the appropriate fee from the following schedule in subparagraph (b)(1) of this section by the number of gallons or pounds they produce from the direct use lease each month.

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
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

Under subparagraph (b)(1)(i), for direct use lease geothermal resources with an average monthly inlet temperature of 130 °F or less, you would have to pay only the lease rental.

This proposed fee schedule uses the methodology the Subcommittee recommended to develop the schedule of fees, but updated the schedule to reflect current Powder River Basin coal prices. The MMS, in consultation with BLM, also made two modifications to the formula the Subcommittee recommended. First, we expressed royalty due in dollars ($) per million (106) gallons and dollars ($) per million (106) pounds to correspond with BLM geothermal resource measurement requirements in 43 CFR part 3275. We also changed the boiler efficiency factor from 75 percent to 70 percent to correspond to MMS regulations at 30 CFR 206.355(c)(1)(ii). In addition, rather than updating the schedule every 3 years, MMS is retaining the flexibility to, in consultation with BLM, develop and publish a revised fee schedule in the Federal Register as needed.

In addition, as the Subcommittee report stated, BLM did a further study Start Printed Page 41521of actual outlet temperatures at direct use facilities and found that 130 °F was more representative than the initial RPC estimate of 120 °F. Therefore, we are changing the assumed outlet temperature in the fee schedule to 130 °F.

We believe this proposal meets Congress' directives because it is based on the quantity and thermal content of the geothermal resource. In addition, we believe it will encourage development of geothermal resources because of the simplified valuation methodology and resultant administrative savings.

We also believe that it will ensure a “fair return” to the United States for the use of the resource. “A fair return is one which, under prudent and economical management, is just and reasonable to both the public and the utility.” Mississippi Power & Light Co. v. Mississippi Ex Rel. Moore, 487 U.S. 354, 366 (1988) (quoting Southern Bell Tel. & Tel. Co. v. Mississippi Public Service Comm'n, 237 Miss. 157, 241, 113 So. 2d 622, 656 (1959); Mississippi Public Service Comm'n v. Mississippi Power Co., 429 So. 2d 883 (Miss. 1983). In this instance, to determine fair value, the BLM representative of the Subcommittee performed an analysis to determine the feasibility of using binary electrical generation values as a basis for valuing direct use of Federal geothermal resources. The Subcommittee was attempting to find a fair royalty value for direct use facilities. Direct use facilities use lower temperature geothermal resources than most geothermal power plants. However, binary power plants use the lowest temperature geothermal resources of any geothermal power plants. Therefore, binary power plants value was selected to be the most comparable to direct use facilities' geothermal value.

The results of the Subcommittee's analysis concluded that the bottom of the binary value range was the lowest value when compared to various direct use valuation methods. In addition, the study showed that the binary valuation (approximately $0.28/MMBtu—$0.77/MMBtu) was comparable to alternative fuel valuation using Powder River Basin coal spot prices published by Energy Information Administration of the Department of Energy (approximately $0.30/MMBtu).

The Subcommittee then compared the value of Powder River coal spot prices to wood chips and natural gas prices for sample months from years 1997 through 2002. After further deliberations, the Subcommittee recommended that MMS use the 3-year historical average of published Powder River Basin coal spot prices to develop the fee schedule for direct use basically because of its continuity of value and public availability.

We welcome comments on the methodology used to develop the fee schedule and the use of published Powder River Basin coal spot prices to derive a “fair return” for the resource.

Paragraph (b)(3) would implement § 223(c) of the EPAct to allow retroactive application of the fee schedule to any existing (Class I) lease that converts to an EPAct (Class III) lease. This paragraph would explain that the schedule of fees established under paragraph (b)(1) will apply to any Class III lease with respect to any royalty payments previously paid, when the lease was a Class I lease, that were due and owing, and were paid, on or after July 16, 2003. If you use this provision and owe additional monies based on the fee schedule, you would have to pay the difference plus interest on that difference computed under 30 CFR 218.302. If you use this provision and overpaid royalties based on the fee schedule, you would be entitled to a refund or credit from MMS of 50 percent of the overpaid royalties. You would be restricted to a refund of 50 percent of the royalties because, under § 223(c) of the EPAct, MMS may not refund royalties paid to a state under 30 U.S.C. 1019 before the date of enactment of the EPAct. However, § 223(c) did not exempt states from refunds of late payment interest previously paid on overpaid royalties under 30 U.S.C. 191a. Therefore, you would be entitled to a refund or credit of any late payment interest that you previously paid on overpaid royalties.

How do I calculate royalty due on byproducts? (Proposed § 206.357)

Neither the Subcommittee nor the EPAct addressed valuation of byproducts. Therefore, MMS is retaining the current valuation methodology and applying it to byproducts produced from Class I, II, or III leases. The MMS made some modifications for plain English purposes. Also, in paragraph (a), like the gross proceeds provisions discussed above, the gross proceeds accruing to affiliate would be the gross proceeds accruing to the lessee where the affiliate makes the first arm's-length sale of the byproducts, less any applicable byproduct transportation allowances determined under §§ 206.358 and 206.359 of this subpart. The MMS is proposing to renumber the current byproduct transportation allowance regulations at 30 CFR 206.357 and 206.358 to new §§ 206.358 and 206.359.

What records must I keep to support my calculations of royalty or fees under this subpart? (Proposed § 206.360)

How will MMS determine whether my royalty value, gross proceeds, or fees are correct? (Proposed § 206.361)

What are my responsibilities to place production into marketable condition and to market production? (Proposed § 206.362)

When is an MMS audit, review, reconciliation, monitoring, or other like process considered final? (Proposed § 206.363)

Does MMS protect information I provide? (Proposed § 206.365)

The MMS is proposing amendments to the text of its recordkeeping, gross proceeds, marketable condition and marketing, audit, and confidentiality requirements and procedures to apply principles in the context of geothermal royalties and fees that are consistent with the Federal oil and gas royalty regulations. In addition, like those rules, rather than repeat the requirements or procedures in each applicable section of this rule, MMS is proposing to have these sections apply to this entire subpart. However, the substantive requirements remain unchanged.

How do I request a value or gross proceeds determination? (Proposed § 206.364)

To be consistent with the Federal oil and gas valuation rules, MMS is proposing to provide a procedure for valuation or gross proceeds determinations regarding geothermal resources produced from Class I leases and for byproducts produced from Class I, II, or III leases that is more than simply nonbinding guidance. The proposed rule would provide that you may request a value or gross proceeds determination from MMS. (Your request would have to identify all leases involved, the record title or operating rights owners, and the operators or payors for those leases, and explain all relevant facts.) The MMS could either:

(1) Issue a determination signed by the Assistant Secretary, Land and Minerals Management; or

(2) Issue a determination by MMS; or

(3) Decline to provide a determination.

A determination signed by the Assistant Secretary, Land and Minerals Management, would be binding on both you and MMS until the Assistant Secretary modifies or rescinds it. It also would be the final action of the Department and subject to judicial review under the Administrative Procedure Act, 5 U.S.C. 701-706. Start Printed Page 41522

In contrast, a determination MMS issued would be binding on MMS and delegated states, but not on you, with respect to the specific situation addressed in the determination, unless the MMS or the Assistant Secretary modifies or rescinds it.

A determination by MMS would not be an appealable decision or order under 30 CFR part 290, subpart B. However, if you received an order requiring you to pay royalty on the same basis as the determination, you could appeal that order under 30 CFR part 290, subpart B.

Further discussion of determinations can be found in the 2000 Federal oil valuation regulation published March 15, 2000 (65 FR 14022).

What is the nominal fee that a state, tribal, or local government lessee must pay for the use of geothermal resources? (Proposed § 206.366)

Section 223(a) of the EPAct directs the Secretary to charge “nominal fees” if a state, tribal, or local government lessee uses a geothermal resource without sale and for public purposes other than commercial generation of electricity. This section implements that provision and explains that a “nominal fee” means a slight or de minimis fee. The MMS is not publishing a schedule of fees for this section so that it has the flexibility to calculate appropriate nominal fees on a case-by-case basis.

C. Section-by-Section Analysis of 30 CFR Part 210—Forms and Reports, Subpart H—Geothermal Resources

We propose to delete § 210.352 because MMS no longer requires payor information forms.

D. Section-by-Section Analysis of 30 CFR Part 217—Audits and Inspections, Subpart H-Geothermal Resources

This subpart is currently reserved. Therefore, as part of this rulemaking, to be consistent with requirements for other mineral leases, MMS proposes to add new §§ 217.300 through 217.302.

Audit or Review of Records. (Proposed § 217.300)

This section would provide that the Secretary, or his/her authorized representative, shall 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 would also relate to compliance with applicable regulations and orders. All audits or reviews would be conducted in accordance with this notice and other requirements of 30 U.S.C. 1717.

Lease Account Reconciliations (Proposed § 217.301)

This section would provide that specific lease account reconciliations shall be performed with priority being given to reconciling those lease accounts specifically identified by a state as having significant potential for underpayment.

Definitions (Proposed § 217.302)

This section would provide that terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.

E. Section-by-Section Analysis of 30 CFR Part 218—Collection of Royalties, Rentals, Bonuses and Other Monies Due the Federal Government and Credits and Incentives Due Lessees, Subpart F—Geothermal Resources

In § 230 of the EPAct, Congress authorized lessees to credit annual rentals paid against royalties. To implement EPAct § 230, MMS proposes to add new sections 218.303 through 218.307 to this subpart.

May I credit rental towards royalty? (Proposed § 218.303)

Proposed section 218.303 would provide that if you pay your annual rental for your lease before the first day of the year for which the annual rental is owed and the annual rental you paid is less than or equal to the royalty you owe that year, then you could credit the annual rental that you paid toward the royalty due for that lease year at any time during that lease year. For example, if you paid $1,000 in rental for the 7th lease year and during that year you owe $50,000 in production royalty, then you could deduct the rental ($1,000) from the monthly royalty due for any month during the 7th lease year, resulting in a net production royalty payment of $49,000 for that year.

On the other hand, if the annual rental you paid is more than the royalty you owe that year, then you would not pay royalty during that lease year. For example, if you paid $1,000 in rental for the 7th lease year and during that year you owe $500 in production royalty, then you would not owe any production royalty. However, the rule would also provide that you may not apply any annual rental paid in excess of the royalty due for a particular lease year as a credit against royalties due for production in a future year.

May I credit rental towards direct use fees? (Proposed § 218.304)

This section would provide that you may not credit annual rental towards direct use fees you are required to pay that year under 30 CFR 206.356(b). Congress did not authorize crediting rentals against fees in the EPAct. Therefore, you would have to pay the direct use fees in addition to the annual rental due.

How do I pay advanced royalties I owe under 43 CFR 3212.15(a)? (Proposed § 218.305)

In § 232 of the EPAct, Congress mandated that if a lessee ceases production for any reason, the lessee must pay advanced royalties in lieu of production royalties to maintain the lease. Therefore, proposed section 218.305 would explain that if you must pay advanced royalties to retain your lease under BLM regulations at 43 CFR 3212.[MRM1] 15(a), then you would have to pay an advanced royalty monthly equal to the average monthly royalty you paid under 30 CFR part 206, subpart H, for the last 3 years the lease was producing. If your lease has been producing for less than 3 years, then you would use the average monthly royalty payment for the entire period your lease has been producing continuously.

You would have to ensure that MMS receives your advanced royalty payment before the first day of each month for which production has ceased. You could credit any advanced royalty you pay against your future production royalties recouped after your lease resumes production. You could not reduce the amount of any production royalty paid for any year below zero.

For example, assume that you paid $12,000 in production royalties annually in 2004, 2005, and 2006, and you plan to cease production on January 1, 2007. Your advanced royalty would be $1,000 (($12,000 × 3) / 36) and would be due before January 1, 2007. Also, assume that you paid $12,000 ($1,000 × 12) in advanced royalty from January 1, 2007, through December 31, 2007, and resumed production January 1, 2008. Furthermore, assume that in January 2008, your production royalties due were $1,500. You could recoup $1,500 of the $12,000 as payment for the $1,500 in production royalties due. You also could continue to recoup the $10,500 balance of advanced royalties paid ($12,000 − $1,500) against future production royalties paid. Start Printed Page 41523

May I receive a credit against production royalties for in-kind deliveries of electricity I provide under contract to a state or county government? (Proposed § 218.306)

Section 224(a) of the EPAct authorizes MMS to provide lessees with credits against part of the royalty due for in-kind deliveries of electricity that lessees provide to states or counties under contracts the Secretary approves. Therefore, proposed § 218.306 in paragraph (a) would explain if you both deliver electricity in kind to a state or county and pay production royalties, then you may receive a credit against production royalties for electricity that you deliver in kind under contract to a state or county government. It also would explain that you may receive a credit only if three conditions are met. First, the state or county to which you provide electricity is a state or county that would receive a portion of your royalties 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 each state's or county's proportionate share of the total acres in the lease. For example, assume you have a 1,000 acre lease. Also, assume that half of your lease is in Nevada and half is in California. If you provide electricity to California, you would be entitled to a credit only against the royalty in value due for the 500 acres located in California.

Second, MMS would have to approve in advance your contract with the state or county to which you are providing in-kind electricity.

Third, your contract would have to provide 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.

Paragraph (b) would provide that the maximum credit you may take 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 the electricity you delivered to the state or county based on the wholesale value of the electricity. You would have to 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. 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.

Paragraph (c) would explain that the electricity the state or county government receives from you would satisfy the Secretary's payment obligation to the state or county under 30 U.S.C. 191 or 30 U.S.C. 1019. Thus, using the same example, the 10,000 kilowatt hours you delivered to New Mexico would satisfy the Secretary's payment obligation to that state that month under 30 U.S.C. 191 and 30 U.S.C. 1019, and MMS would not pay any part of the $1,500 that you paid in money to the state.

How do I pay royalties due for my existing leases that qualify for near-term production incentives under 43 CFR part 3212? (Proposed § 218.307)

To implement § 224(c) of the EPAct, MMS proposes to add § 218.307. This section would explain that if you qualify for a production incentive under BLM regulations at 43 CFR part 3212 (§§ 3212.18 through 3212.24), then you would pay 50 percent of the amount of the total royalty that would otherwise be due under 30 CFR part 206, subpart H. For example, if you qualified for a production incentive and you owed $1,000 in royalties under 30 CFR part 206, subpart H, then you would pay $500 in royalties (50 percent of $1,000).

III. Procedural Matters

1. Public Comment Policy

Our practice is to make comments, including names and home addresses of respondents, available for public review during regular business hours and on our Web site at http://www.mrm.mms.gov/​Laws_​R_​D/​FRNotices/​FRHome.htm. Individual respondents may request that we withhold their home address from the rulemaking record, which we will honor to the extent allowable by law. There also may be circumstances in which we would withhold from the rulemaking record a respondent's identity, as allowable by law. If you wish us to withhold your name and/or address, you must state this prominently at the beginning of your comments. However, we will not consider anonymous comments. We will make all submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials of organizations or businesses, available for public inspection in their entirety.

2. Summary Cost and Royalty Impact Data

Of the proposed 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 OMB, as a result of the proposed rule. However, there are certain estimated royalty effects of the proposed rule to all potentially affected groups: industry, States and local governments, and the Federal Government. These are summarized below. There are no associated costs, to industry or to the Federal Government, of administering the proposed rule.

Of the proposed 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 we are proposing for Federal leases would not apply to and currently would not have an impact on Indian leases. In addition, this proposed 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 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. Electrical generation lessees that remain under the current regulations would pay the same Start Printed Page 41524royalties as they have been paying all along. Electrical generation lessees who modify their leases to the new regulation's percentage of gross proceeds method should pay the same level of royalties as they have paid under the current regulations. New lessees would have royalty rates determined by BLM that should result in the same level of royalties for 10 years as they would have paid under the current regulations.

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

(2) Administrative Costs. The MMS has determined that there are no 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 would receive the same royalties as they do currently for electrical generation leases. However, because of the 95-percent decrease in revenue collected from direct use leases, States who receive a share of that revenue under 30 U.S.C. 191 would be impacted by the revenue decrease. It is unknown how this would affect the counties because the States distribute royalty revenues to their counties directly without MMS involvement. The new fee schedule would result in approximately 95-percent reduction in royalties paid to States from direct use projects. The MMS estimates the reduction to be $30,000 per year.

(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 mandates a new distribution of 25 percent of royalties to the counties. This 25 percent would cut the Federal share in half from 50 percent to 25 percent, and leaves the States' share as 50 percent. The counties would receive a new 25-percent distribution of total geothermal royalty revenue under the EPAct, which would increase their revenues by $4,071,583 per year 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 would remain unchanged under the EPAct.

(4) Administrative Costs—Local Governments. This rule would not impose any additional burden on local governments. The counties where geothermal facilities are located on Federal leases would 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. 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 royalty impact on the Federal Government would be a decrease of $4,101,583 ($4,071,583 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 would be impacted by a net overall decrease in royalties as a result of the proposed 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 would 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 would also be impacted by the 95-percent decrease in revenues from direct use leases due to the proposed direct use fee schedule. The MMS estimates the reduction to be $30,000 per year.

(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):
Start Printed Page 41525
Royalty Increase to counties+4,071,5834,071,583
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 the criteria in Executive Order 12866, this proposed rule is not a significant regulatory action. The Office of Management and Budget (OMB) makes the final determination under Executive Order 12866.

a. This proposed rule would 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 proposed rule would not create inconsistencies with other agencies' actions.

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

d. This proposed rule would not raise novel legal or policy issues. Under the criteria in Executive Order 12866, this proposed rule is not an economically significant regulatory action as it does not exceed the $100 million threshold.

4. Regulatory Flexibility Act

The Department of the Interior certifies that this proposed rule would 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 Regulatory 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 Act (SBREFA)

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

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

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

c. Would 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 proposed rule would not “significantly or uniquely” affect small governments. Therefore, a Small Government Agency Plan is not required.

b. This proposed rule would not produce a Federal mandate of $100 million or greater in any year, i.e., it would not be a “significant regulatory action” under the Unfunded Mandates Reform Act. The analysis prepared for Executive Order 12866 meets the requirements of the Unfunded Mandates Reform Act.

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

In accordance with Executive Order 12630, this proposed 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 proposed rule would not have federalism implications; hence, a federalism assessment is not required. It would 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 leases are shared with state governments on a percentage basis as prescribed by law. This proposed rule would not alter any lease management or royalty value sharing provisions. It would determine the value of production for royalty value computation purposes only. This proposed rule would 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 proposed rule would not unduly burden the judicial system and meets the exception requirements of §§ 3(a) and 3(b)(2) of the Order.

10. Paperwork Reduction Act of 1995 (PRA)

This proposed rule, RIN 1010-AD32, would contain new information collection requirements. The title of the new information collection request (ICR) is “30 CFR Parts 202, 206, 210, 217, and 218—Valuation of Geothermal Resources.”

The intent of this proposed rulemaking is to change the methodology for geothermal royalty valuation and simplify these calculations for both direct use and electrical generation purposes. We have submitted an ICR to OMB for review and approval under § 3507(d) of the PRA. When this rule becomes effective, we will prepare the required OMB Forms and transfer the burden hours to Start Printed Page 41526their respective primary collections. As part of our continuing effort to reduce paperwork and respondent burden, we will invite the public and other Federal agencies to comment on any aspect of the reporting burden through the information collection process.

Submit written comments by either fax (202) 395-6566 or e-mail (OIRA_Docket@omb.eop.gov) directly to the Office of Information and Regulatory Affairs, OMB, Attention: Desk Officer for the Department of the Interior [OMB Control Number ICR 1010-New, as it relates to the proposed geothermal valuation rule].

Also submit copies of written comments 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.

The OMB has up to 60 days to approve or disapprove this collection of information but may respond after 30 days. Therefore, public comments should be submitted to OMB within 30 days in order to assure their maximum consideration. However, we will consider all comments received during the comment period for this notice of proposed rulemaking.

This ICR has a new collection of regulatory information for a total program change of 174 burden hours. The proposed rule uses Form-MMS 2014, which is covered in ICR 1010-0140 (expires October 31, 2006). See the following chart for burden hours by CFR citation:

Burden Breakdown

30 CFR Parts 202, 206, 210, 217, and 218Reporting and recordkeeping requirementHour burdenAverage number of annual responsesAnnual burden hours
Part 202—Royalties
Subpart H—Geothermal Resources
§ 202.353 Measurement standards for reporting and paying royalties.
202.353(a) For geothermal resources used to generate electricity, you must report the quantity on which royalty is due on Form MMS-2014 * * * (b) For geothermal resources used in direct use processes, you must report the quantity on which royalty or fee is due on Form MMS-2014 * * * (c) For byproducts, you must report the quantity on which royalty is due on Form MMS-2014 * * * (d) For commercially demineralized water, you must report the quantity on which royalty is due on Form MMS-2014 * * *Burden covered under OMB Control Number 1010-0140 (expires October 31, 2006).
(e) You must maintain quality measurements for audit purposes.The Office of Regulatory Affairs (ORA) determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
Part 206—Product Valuation
Subpart H—Geothermal Resources
§ 206.352 How do I calculate the royalty due on geothermal resources used for commercial generation of electricity?
206.352;(b)(1)(ii) A royalty determined by any other reasonable method approved by MMS under § 206.364 of this subpart111
§ 206.353 How do I determine transmission deductions?
206.353(c)(2)(i)(A) such purchase as necessary * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions
(d)(9) Any other directly allocable and attributable operating expense which you can document, including * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions
(e) Allowable maintenance expenses include: * * * (4) Other directly allocable and attributable maintenance expenses, which you can document.The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(g) To compute costs associated with capital investment * * * the lessee may not later elect to change to the other alternative without MMS approval.111
Start Printed Page 41527
(h) To compute depreciation you may elect * * * you may not change methods without MMS approval.111
(l) * * * In conducting reviews and audits, MMS may require you to submit arm's-length transmission contracts, production agreements, operating agreements, and related documentsThe ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(l) * * * Recordkeeping requirements are found at part 212 of this chapterBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
(n) In conducting reviews and audits, MMS may require you to submit all data used to calculate the deduction. You must comply with any such requirements within the time MMS specifiesThe ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(n) Recordkeeping requirements are found at part 212 of this chapterBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
(o)(2) You must submit corrected Forms MMS-2014 to reflect adjustments to royalty payments in accordance with MMS instructionsBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
§ 206.354 How Do I Determine Generating Deductions?
206.354(b)(1)(ii) You must redetermine your generating costs annually * * * you may not later elect to use a different deduction period without MMS approval111
(c)(2)(i)(A) The purchase is necessary * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(d)(9) Any other directly allocable and attributable operating expense which you can document, including * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(e) Allowable maintenance expenses include: * * * (4) Other directly allocable and attributable maintenance expenses, which you can documentThe ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(g) * * * After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without MMS approval111
(h) To compute depreciation, you may elect to use either 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, or a unit-of-production method. After you make an election, you may not change methods without MMS approval111
(l)(1) * * * In conducting reviews and audits MMS may require you to submit arm's-length power plant contracts * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(l)(1) * * * Recordkeeping requirements are found at part 212 of this chapterBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
(l)(3) * * * The MMS may require you to submit all data used to calculate the deductionThe ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(l)(3) * * * Recordkeeping requirements are found at part 212 of this chapterBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
(m)(2) You must submit corrected Forms-2014 to reflect adjustments to royalty payments in accordance with MMS instructionsBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
Start Printed Page 41528
§ 206.356 How do I calculate royalty due on geothermal resources I use for direct use purposes?
206.356(a)(1) The weighted average of the gross proceeds * * * In evaluating the acceptability of arm's-length contracts * * *111
(a)(2) * * * The efficiency of the alternative energy source shall be * * * or proposed by the lessee and approved MMS48296
(a)(3) A royalty determined by * * * approved by MMS * * *111
(b)(3) * * * you must provide MMS data showing the amount of geothermal production in pounds or gallons of geothermal fluid to input into the fee schedule * * *111
(c) For geothermal resources other than hot water, MMS will determine fees on a case-by-case basis111
§ 206.357 How do I calculate royalty due on byproducts?
206.357(c) A value determined by any other reasonable valuation method approved by MMS.111
§ 206.358 What are byproduct transportation allowances?
206.358(d) Reporting requirements. (1) Arm's-length contracts. (i) You must use a discrete field on Form MMS-2014 to notify MMS of a transportation allowanceBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
(d)(1)(ii) In conducting reviews and audits, MMS may require you to submit * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(d)(1)(ii) Recordkeeping requirements are found at part 212 of this chapterBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
(d)(2) Non-arm's-length or no contract. (i) You must use a discrete field on Form MMS-2014 to notify MMS of a transportation allowanceBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
(d)(2)(iii) In conducting reviews and audits, MMS may require you to submit * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(d)(2)(iii) Recordkeeping requirements are found at part 212 of this chapterBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
(e)(2) You must submit corrected Form MMS-2014 to reflect adjustments to royalty payments in accordance with MMS instructionsBurden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
(h) If MMS reviews or audits your royalty payments, you must make available to authorized MMS representatives or to other authorized persons all transportation contracts and all other information as may be necessary to support a byproduct transportation allowanceThe ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions
§ 206.359 How do I determine byproduct transportation allowances?
206.359(a)(2) * * * MMS will require you to determine the * * * MMS will notify you and give you an opportunity to provide written information justifying your transportation costsThe ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(c)(2)(i)(A) The purchase is necessary * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(d)(9) Any other directly allocable and attributable operating expense which you can document, including * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions
(e) Allowable maintenance expenses include:* * * (4) Other directly allocable and attributable maintenance expenses, which you can document.* * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions
Start Printed Page 41529
(g) To compute costs * * * the lessee may not later elect to change to the other alternative without MMS approval.* * *111
(h) To compute depreciation * * * After you make an election, you may not change methods without MMS approval.111
§ 206.360 What records must I keep to support my calculations of royalty or fees under this subpart?
206.360* * * you must retain all data relevant * * *Burden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
Recordkeeping requirements are found in part 212 of this chapter.Burden hours covered under OMB Control Number 1010-0140 (expires October 31, 2006).
You must be able to show: (1) How you calculated * * * (2) How you complied * * * (b) Upon request, you must submit all data to MMS.The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
§ 206.361 How will MMS determine whether my royalty, gross proceeds or fees are correct?
206.361(b) * * * MMS may require you to increase the gross proceeds to reflect * * * MMS may require you to use another valuation method * * * MMS will notify you to give you an opportunity to provide written information justifying your gross proceeds * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(c) For arm's-length sales, you have the burden of demonstrating * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(d) The MMS may require you to certify that the provisions in your sales contract include * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
(f)(2) Contract revisions or amendments you make must be in writing and signed by all parties to the contract.111
§ 206.364 How do I request a value or gross proceeds determination?
206.364(a) You may request a value determination from MMS. * *  Your request must: (1) Be in writing * * *32060
Part 210—Forms and Reports
Subpart H—Geothermal Resources
§ 210.352 Payor information forms.
210.352The Payor Information Form * * * (f) Abandonment of a lease. * * *The payor information form was discontinued through reengineering by 2001. This rule removes geothermal references to the form from the Code of Federal Regulations. There are no current burden hours.
Part 217—Audits and Inspections
Subpart G—Geothermal Resources
§ 217.300 Audits or review of records.
217.300The Secretary, or his/her authorized representative shall initiate and conduct audits or reviews relating * * * Audits or reviews will also relate to compliance * * * All audits or reviews will be conducted in accordance with * * *The ORA determined that the audit process is not covered by the PRA because MMS staff asks non-standard questions to resolve exceptions.
Start Printed Page 41530
PART 218—Collection of royalties, rentals, bonuses and other monies due the Federal Government and Credits and Incentives Due Lessees
Subpart F—Geothermal Resources
§ 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?
218.306(a)(2) MMS approves in advance your contract * * *414
Burden Hour Total37174

Public Comment Policy. The PRA (44 U.S.C. 3501 et seq.) provides that 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. Before submitting an ICR to OMB, PRA § 3506(c)(2)(A) requires each agency “* * * to provide notice * * * and otherwise consult with members of the public and affected agencies concerning each proposed collection of information * * *.” Agencies must specifically solicit comments to: (a) Evaluate whether the proposed collection of information is necessary for the agency to perform its duties, including whether the information is useful; (b) evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) enhance the quality, usefulness, and clarity of the information to be collected; and (d) minimize the burden on the respondents, including the use of automated collection techniques or other forms of information technology.

The PRA also requires agencies to estimate the total annual reporting “non-hour cost” burden to respondents or recordkeepers resulting from the collection of information. If you have costs to generate, maintain, and disclose this information, you should comment and provide your total capital and startup cost components or annual operation, maintenance, and purchase of service components. You should describe the methods you use to estimate major cost factors, including system and technology acquisition, expected useful life of capital equipment, discount rate(s), and the period over which you incur costs. Capital and startup costs include, among other items, computers and software you purchase to prepare for collecting information; monitoring, sampling, and testing equipment; and record storage facilities. Generally, your estimates should not include equipment or services purchased: (i) Before October 1, 1995; (ii) to comply with requirements not associated with the information collection; (iii) for reasons other than to provide information or keep records for the Government; or (iv) as part of customary and usual business or private practices.

We will summarize written responses to this proposed information collection and address them in our final rule. We will provide a copy of the ICR to you without charge upon request, and the ICR will also be posted on our Web site at www.mrm.mms.gov/​Laws_​R_​D/​FRNotices/​FRInfColl.htm.

We will post all comments in response to this proposed information collection on our Web site at www.mrm.mms.gov/​Laws_​R_​D/​InfoColl/​InfoColCom.htm. We will also make copies of the comments available for public review, including names and addresses of respondents, during regular business hours at our offices in Lakewood, Colorado. Individual respondents may request that we withhold their home address from the public record, which we will honor to the extent allowable by law. There also may be circumstances in which we would withhold from the rulemaking record a respondent's identity, as allowable by law. If you request that we withhold your name and/or address, state this prominently at the beginning of your comment. However, we will not consider anonymous comments. We will make all submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials of organizations or businesses, available for public inspection in their entirety.

11. National Environmental Policy Act (NEPA)

This proposed rule deals with financial matters and would 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.

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 and have determined that the changes we are proposing for Federal leases do not apply to and would not have an impact on Indian leases.

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

In accordance with Executive Order 13211, this regulation would not have a significant adverse effect on the Nation's energy supply, distribution, or use. The proposed changes primarily involve royalty valuation of geothermal production to simplify royalty Start Printed Page 41531valuation, hence, any impact to the way industry does business should be positive, and as the EPAct directs, should encourage energy development and marketing. The proposed rule would not otherwise impact energy supply, distribution, or use.

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

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

15. Clarity of This Regulation

Executive Order 12866 requires each agency to write regulations that are easy to understand. We invite your comments on how to make this rule easier to understand, including answers to questions such as the following: (1) Are the requirements in the rule clearly stated? (2) Does the rule contain technical language or jargon that interferes with its clarity? (3) Does the format of the rule (grouping and order of sections, use of headings, paragraphing, etc.) aid or reduce its clarity? (4) Would the rule be easier to understand if it were divided into more (but shorter) sections? (A “section” appears in bold type and is preceded by the symbol § and a numbered heading; for example, § 204.200 What is the purpose of this part?) (5) Is the description of the rule in the SUPPLEMENTARY INFORMATION section of the preamble helpful in understanding the proposed rule? What else could we do to make the rule easier to understand? Send a copy of any comments that concern how we could make this rule easier to understand to: Office of Regulatory Affairs, Department of the Interior, Room 7229, 1849 C Street, NW., Washington, DC 20240. You may also e-mail the comments to this address: Exsec@ios.doi.gov.

Start List of Subjects

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

End List of Subjects Start Signature

Dated: June 28, 2006.

R. M. “Johnnie” Burton,

Director, Minerals Management Service, Exercising the delegated authority of the Assistant Secretary of Land and Minerals Management.

End Signature

For the reasons stated in the preamble, the Minerals Management Service proposes to amend 30 CFR parts 202, 206, 210, and 218 as set forth below:

Start Part

PART 202—ROYALTIES

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

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

2. Revise § 202.351 to read as follows:

Royalties on geothermal resources.

(a)(1) Royalties on geothermal resources, including byproducts, shall be at the royalty rate(s) specified in the lease, unless the Secretary of the Interior temporarily waives, suspends, or reduces that rate(s). Royalty value is 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 30 CFR 218.306, you must pay royalties and direct use fees in money.

(b)(1) Royalties or fees are due on all geothermal resources, except those specified in paragraph (b)(2) of this section, that are produced from a lease and that are sold or used by the lessee or are reasonably susceptible to sale or use by the lessee.

(2)(i) Geothermal resources that are unavoidably lost, as determined by the Bureau of Land Management (BLM), and geothermal resources that are reinjected prior to use on or off the lease, as approved by BLM, are not subject to royalty or direct use fees.

(ii) The Minerals Management Service (MMS) 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. If a power plant uses geothermal production from more than one lease, or uses unitized or communitized production, only that proportionate share of each lease's production (actual or allocated) necessary to operate the power plant may be used royalty free.

(iii) MMS will also allow royalty-free a reasonable amount of commercially demineralized water necessary for power plant operations or otherwise used on or for the benefit of the lease.

(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, shall 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 shall not apply to compensation through self-insurance.

3. Revise § 202.353 to read as follows:

Measurement standards for reporting and paying royalties.

(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 30 CFR 206.352(a), (b)(2), and (b)(3), you must report quantities in:

(i) Kilowatt-hours to the nearest whole kilowatt-hour if the contract specifies payment in terms of generated electricity;

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

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

(2) For geothermal resources for which royalty is calculated under 30 CFR 206.352(b)(1), 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 royalty or fee is due on Form MMS-2014 in:

(1) Millions of Btu's to the nearest whole million Btu if valuation is in Start Printed Page 41532terms of thermal energy used or displaced;

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

(3) Millions of pounds to the nearest million pounds of geothermal fluid produced if valuation 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-2014 in hundreds of gallons to the nearest hundred gallon.

(e) You need not report the quality of geothermal resources, including byproducts, to MMS. 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.

End Part Start Part

PART 206—PRODUCT VALUATION

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

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

5-6. Revise subpart H to read as follows:

Subpart H—Geothermal Resources

206.350 206.351 206.352 206.353 206.354 206.355 206.356 206.357 206.358 206.359 206.360 206.361 206.362 206.363 206.364 206.365 206.366

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 purposes of this subpart are to prescribe how to calculate royalties and fees for geothermal production.

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

(c) If the regulations in this subpart are inconsistent with:

(1) A Federal statute;

(2) A settlement agreement between the United States and a lessee resulting from administrative or judicial litigation;

(3) A written agreement between the lessee and the MMS Director or Assistant Secretary, Land and Minerals Management of the Department of the Interior, establishing a method to determine the royalty from any lease that MMS expects at least would approximate the value or royalty established under this subpart, including a value or gross proceeds determination under § 206.364 of this subpart; or

(4) An express provision of a geothermal lease subject to this subpart, then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency.

What definitions apply to this subpart?

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.

Byproduct (or mineral) means products or 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. Start Printed Page 41533

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 allowance as a separate discrete field on the Form MMS-2014.

Class I lease means:

(1) A lease that BLM issued under the GSA before August 8, 2005, for which the lessee does not elect to convert to a Class II lease under 43 CFR 3212.25; or

(2) A lease issued in response to an application that was pending on August 8, 2005, for which the lessee does not elect to convert to a Class II lease under 43 CFR 3200.8.

Class II lease means a geothermal lease that BLM issued on or after [effective date of final BLM regulation] under 43 CFR subparts 3203, 3204, or 3205, except for a lease issued in response to an application that was pending on August 8, 2005, which the lessee elects not to convert to a Class II lease under 43 CFR 3200.8.

Class III lease means a Class I lease that the lessee converts to a Class II lease 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 required 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 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 efficient 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 mean:

(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 of the 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 run a power plant.

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 are not limited to, those 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 Start Printed Page 41534as a source of heat in direct-use operations.

Secretary means the Secretary of the Department 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 actual 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 generation of electricity?

(a) If you sold geothermal resources produced from Class I, II, and III leases 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 times the royalty rate in your lease or 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:

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

(i) The gross proceeds accruing to you for the arm's-length sale of the electricity less applicable deductions determined under § 206.353 and § 206.354 of this part times 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 shall the deductions reduce the royalty 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 leases, the royalty on geothermal resources produced is your gross proceeds from the sale of electricity for the production month 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.

(3) For Class III leases, the royalty on geothermal resources produced is your gross proceeds from the sale of electricity for the production month multiplied by the royalty rate BLM calculated 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) Base transmission-line costs on 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 at the beginning of 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 your option, at a time concurrent with the beginning of your annual corporate accounting period. However, 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) Base your transmission-line costs on your actual costs for transmission 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 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) which 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 shall 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 which 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, which 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) To compute depreciation, you may elect to use either a straight-line Start Printed Page 41535depreciation method based on the life of equipment or on the life of the reserves which the transmission line services, or a return on capital investment method. After you make an election, you may not change methods without MMS approval. 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 the 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 times 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. In conducting reviews and audits, MMS may require you to submit arm's-length transmission 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.

(m) 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. Paragraph (o) of this section will apply when you amend your report based on your actual costs.

(n) In conducting reviews and audits, MMS may require you to submit all 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) If your actual transmission deduction differs from your estimate under § 206.352(a)(1), you must submit corrected Forms MMS-2014 according to MMS instructions. You then must make payments or may receive a refund or credit as shown in the following table:

If your actual transmission deduction is . . .Then . . .
(1) Less than the amount you estimated and used to calculate royalties under § 206.352(a)(1) during the reporting periodyou must pay: (i) Additional royalties retroactive to the first month of the reporting period; and (ii) Interest computed under 30 CFR 218.302.
(2) Greater than the amount you estimated and used to calculate royalties under § 206.352(a)(1)you are entitled to a refund or credit without interest.

(p) Under no circumstances shall the transmission deduction plus the generating deduction reduce the royalty value of the geothermal resource to zero.

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 take a generating deduction. If you take a generating deduction, you must 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 at the beginning of the same month of the year in which the power plant was placed into service or, at your option, at a time concurrent with the beginning of your annual corporate accounting period. However, 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) Base your generating costs on 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 paragraph (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) which 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 shall 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. Start Printed Page 41536

(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.

(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) To compute depreciation, you may elect to use either 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, or a unit-of-production method. After you make an election, you may not change methods without MMS approval. You may not depreciate equipment below a reasonable salvage value. 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.

(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 times 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.

(1) In conducting reviews and audits, MMS may require you to submit arm's-length power plant 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.

(2) 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. Paragraph (m) of this section will apply when you amend your report based on your actual costs.

(3) In conducting reviews and audits, MMS may require you to submit all 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.

(m) If your actual generating deduction at the end of the annual reporting period is different from your estimated payment, you must submit corrected Forms MMS-2014 to reflect adjustments to royalty payments in accordance with MMS instructions. You then must make payments or may receive a refund or credit as shown in the following table:

If your actual generating deduction is . . .Then . . .
(1) Less than the amount you estimated and used to calculate royalties under § 206.352(a)(1) during the reporting periodyou must pay: (i) Additional royalties retroactive to the first month of the reporting period; and (ii) Interest computed under 30 CFR 218.302.
(2) Greater than the amount you estimated and used to calculate royalties under § 206.352(a)(1)you are entitled to a refund or credit without interest.

(n) Under no circumstances shall the transmission deduction plus the generating deduction reduce the royalty value of the geothermal resource to zero.

How do I calculate royalty due on geothermal resources I sell 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 times 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 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 times the royalty rate in your lease. In evaluating the acceptability of arm's-length contracts, the following factors shall 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) times the royalty rate in your lease. The equivalent value of the least expensive, reasonable alternative energy source shall 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's) displaced by the geothermal resource shall be determined by the equation:

Start Printed Page 41537

Where hin is the enthalpy in Btu's/lb at the direct use facility inlet (based on measured inlet temperature), hout is the enthalpy in Btu's/lb at the facility outlet (based on measured outlet temperature), density is in lbs/cu ft based on inlet temperature, the factor 0.133681 (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 of the alternative energy source shall 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 shall be determined and approved by BLM.

(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 hot water 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
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 only pay 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:

For reporting on a volume basis:

For reporting on a mass basis:

Where:

RV = Royalty due as a function 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 = 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%;

Pprbc = The three year historical average of Powder River Basin spot coal prices, as published by the Energy Information Administration, in dollars ($) per MMBtu;

Frr = The assumed Lease Royalty Rate of 10%

(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 Start Printed Page 41538showing 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, then you must pay the difference. You must pay interest on that difference computed under 30 CFR 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 fifty 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?

If you sell byproducts, then you must determine the royalty due on the byproducts produced from Class I, II, or III leases in accordance with the first applicable of the following paragraphs:

(a) The gross proceeds accruing to you for the arm's-length sale of the byproducts, less any applicable byproduct transportation allowances determined under §§ 206.357 and 206.358 times the royalty rate in your lease or that BLM prescribes under 43 CFR 3211.19. See § 206.361 for additional provisions applicable to determining gross proceeds;

(b) 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

(c) A value determined by 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, shall not be included 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) Transportation costs shall be authorized as allowances only when the transported byproduct is sold, delivered, or otherwise utilized by the lessee and royalties are reported and paid.

(d) Reporting requirements—(1) Arm's-length contracts. (i) You must use a discrete field on Form MMS-2014 to notify MMS of a transportation allowance.

(ii) 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.

(2) Non-arm's-length or no contract. (i) You must use a discrete field on Form MMS-2014 to notify MMS of a transportation allowance.

(ii) 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. Paragraph (e) of this section will apply when you amend your report based on your actual costs.

(iii) In conducting reviews and audits, MMS may require you to submit all 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.

(e)(1) If the actual transmission deduction you determined at the end of the annual reporting period is:

(i) Less than the amount you estimated and used to calculate royalties under § 206.356(a) during the reporting period, then you must pay additional royalties retroactive to the first month of the reporting period, plus interest computed under 30 CFR 218.302; or

(ii) Greater than the amount you estimated and used to calculate royalties under § 206.356(a) you are entitled to a refund or credit without interest.

(2) You must submit corrected Forms MMS-2014 to reflect adjustments to royalty payments in accordance with MMS instructions.

(f) Byproduct transportation allowances are subject to monitoring, review, and audit. If, after a review and/or audit, MMS determines that you have improperly determined a byproduct transportation allowance authorized by this section, then:

(1) You must pay any additional royalties plus interest determined in accordance with 30 CFR 218.302; or

(2) You are entitled to a refund or credit without interest.

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

(h) If MMS reviews or audits your royalty payments, you must make available to authorized MMS representatives or to other authorized persons all transportation contracts and all other information as may be necessary to support a byproduct transportation allowance.

How do I determine byproduct transportation allowances?

(a) For transportation costs you incur under an arm's-length contract, the transportation allowance shall be the reasonable, actual costs you incurred for transporting the byproducts under that contract, subject to monitoring, review, audit, and possible future adjustments. You may deduct costs incurred under an arm's-length transportation contract without prior MMS approval.

(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 Start Printed Page 41539consideration 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) For transportation costs you incur; i.e., where you perform transportation services for yourself, you must base the byproduct transportation allowance on your reasonable actual costs.

(1) All byproduct transportation allowances deducted under this paragraph are subject to monitoring, review, audit, and possible future adjustment. You may deduct transportation costs incurred under this paragraph without prior MMS approval.

(2) You must base the byproduct transportation allowance on your reasonable actual costs for transportation 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 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) which 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 shall 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 which you can document.

(e) Allowable maintenance expenses include:

(1) Maintenance of the transportation system;

(2) Maintenance of equipment;

(3) Maintenance labor; and

(4) Other directly allocable and attributable maintenance expenses which 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) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of the transportation system, the life of the reserves which the transmission system services, or a unit-of-production method. After you make an election, you may not change methods without MMS approval. You may not depreciate equipment below a reasonable salvage value. 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 shall 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) Other transportation cost determinations. Use this section when calculating transportation costs to establish value using a netback procedure or any other procedure that requires deduction of transportation costs.

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

If you determine royalties or 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.

How will MMS determine whether my royalty value, gross proceeds, or fees are correct?

(a)(1) The royalties or 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 under paragraph (a)(1) of this section, then the following table applies: Start Printed Page 41540

If the royalty or fee you paid . . .Then . . .
(i) Is less than the royalty or fee based upon the royalty value or fee established by MMSyou must pay the difference plus interest on that difference computed under 30 CFR 218.302.
(ii) Is more than the royalty or fee owed based upon the royalty value, gross proceeds, or fee established by MMSyou are entitled to a refund or credit without interest.

(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 shall 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 shall 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) shall not be construed to permit you to avoid its 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.

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, II, or III lease. You may also request a gross proceeds determination for a Class II or III lease. Your request must:

(1) Be in writing;

(2) Identify specifically all leases involved, the record title or operating rights owners of those leases, and the designees 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 method.

(b) The MMS will reply to requests expeditiously. MMS may either:

(1) Issue a determination signed by the Assistant Secretary, Land and Minerals Management; or

(2) Issue a determination by MMS; or

(3) 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 late payment interest under 30 CFR 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. Start Printed Page 41541

(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, 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 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. MMS will determine the fee on a case-by-case basis.

End Part Start Part

PART 210—FORMS AND REPORTS

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

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]

8. Remove § 210.352.

End Part Start Part

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

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

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

10-11. Add §§ 218.303, 218.304, 218.305, 218.306, and 218.307 to subpart F to read as follows:

May I credit rental towards royalty?

(a) If you pay your annual rental for your lease before the first day of the year for which the annual rental is owed, the provisions in the following table apply.

If the annual rental you paid is . . .Then . . .
(1) Less than or equal to the royalty you are required to pay that yearyou may credit the annual rental that you paid toward the royalty due for that lease year at any time during that lease year.
(2) More than the royalty you are required to pay that year(i) You will not pay royalty during that lease year; and (ii) You may not apply any annual rental paid in excess of the royalty due for a particular lease year as a credit against royalties due for production in a future year.

(b) If portions of your lease are located both within and outside of a participating area, you may only credit the rental you paid for the portion 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 30 CFR 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 are required to pay advanced royalties under 43 CFR 3212.15(a) 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 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) MMS must receive your advanced royalty payment prior to the first day of each month for which production has ceased;

(c) You may credit any advanced royalty you pay against your future production royalties recouped 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 production 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) 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 Start Printed Page 41542a 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 part 3212, your royalty due on the production BLM determines to be qualified for a production incentive is 50 percent of the amount of the total royalty that would otherwise be due under 30 CFR part 206, subpart H.

End Part End Supplemental Information

[FR Doc. 06-6219 Filed 7-20-06; 8:45 am]

BILLING CODE 4310-MR-P