24448 Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 

DEPARTMENT OF THE INTERIOR 

Minerals Management Service 

30 CFR Parts 202, 206, 210, 217, and 

218 

RIN 1010–AD32 

Geothermal Royalty Payments, Direct 

Use Fees, and Royalty Valuation 

AGENCY: Minerals Management Service 

(MMS), Interior. 

ACTION: Final rule. 

SUMMARY: The MMS is promulgating 

new regulations to implement the 

provisions of the Energy Policy Act of 

2005 (EPAct) governing the payment of 

royalty on geothermal resources 

produced from Federal leases and the 

payment of direct use fees in lieu of 

royalties. The EPAct provisions amend 

the Geothermal Steam Act of 1970 

(GSA). The new regulations amend the 

current MMS geothermal royalty 

valuation regulations and simplify the 

royalty and direct use fee calculations 

for geothermal resources for leases 

issued under the EPAct and leases 

whose terms are modified under the 

EPAct. The new regulations also amend 

various related provisions in the MMS 

rules. 

EFFECTIVE DATE: June 1, 2007. 

FOR FURTHER INFORMATION CONTACT: 

Sharron Gebhardt, Lead Regulatory 

Specialist, Minerals Revenue 

Management (MRM), MMS, telephone 

(303) 231–3211, fax (303) 231–3781, or 

e-mail sharron.gebhardt@mms.gov. The 

principal authors of this rule are Sarah 

L. Inderbitzin and Herb Black of MRM, 

MMS, Department of the Interior. 

SUPPLEMENTARY INFORMATION: 

I. Background 

A. Pre-EPAct Statutory Provisions and 

Existing Regulations 

The existing rules applicable to 

geothermal resources were promulgated 

in 1991 under the GSA (30 U.S.C. 1001 

et seq.) before its amendment by the 

EPAct (Pub. L. 109–58, 119 Stat. 594). 

The current royalty valuation methods 

for geothermal resources are grouped 

first by usage, i.e., electrical generation, 

direct use, and byproducts. Within each 

usage category, valuation methods are 

grouped by the method of disposition of 

the resources, i.e., arm’s-length 

(unaffiliated) sales, non-arm’s-length 

sales, and no sales. 

The Secretary of the Interior 

established the Royalty Policy 

Committee (RPC) on August 1, 1995, in 

accordance with Public Law 92–463, 

Federal Advisory Committee Act, dated 

October 6, 1972. The RPC convened its 

first meeting in Denver, Colorado, on 

September 12–13, 1995. 

The mission of the RPC is to provide 

policy advice representing the collective 

viewpoint of the states, Indians, mineral 

industry, and other parties to the 

Secretary of the Interior through the 

Director of the Minerals Management 

Service (MMS) and other officers of the 

Department of the Interior. This policy 

advice concerns the performance of 

discretionary functions involved in the 

Department’s management of Federal 

and Indian mineral leases and revenues. 

The RPC reviews and comments on 

royalty management and other mineralrelated policies and provides a sounding 

board to convey views representative of 

mineral lessees, operators, revenue 

payors, recipients, governmental 

agencies, and the interested public. The 

RPC may establish subcommittees or 

workgroups as it deems necessary for 

the purposes of compiling information 

or conducting research. Subcommittees 

or workgroups may not conduct 

business independent of the RPC and 

must report its recommendations to the 

full RPC for consideration. 

Subcommittees or workgroups meet as 

necessary to accomplish their 

assignments, subject to the approval of 

the RPC Chairperson. 

On October 28, 2004, the RPC formed 

the Geothermal Valuation 

Subcommittee (Subcommittee) to 

address the MMS geothermal royalty 

valuation regulations to simplify the 

regulations and reduce administrative 

costs to the geothermal industry. The 

Subcommittee was comprised of 

members from one industry association, 

several geothermal producers, two of the 

major States affected, and MMS 

employees. A representative of the 

Bureau of Land Management (BLM) 

served as technical advisor to the 

Subcommittee. The RPC requested that 

the Subcommittee work together to 

develop more efficient royalty valuation 

methods that will ensure a fair return to 

the Federal Government as well as 

encourage geothermal development. The 

Subcommittee prepared a report and 

submitted it to the RPC; and on May 26, 

2005, the RPC accepted the 

Subcommittee’s recommendations. 

B. The EPAct 

On August 8, 2005, the President 

signed into law the EPAct, Pub. L. 109– 

58, 119 Stat. 594. Sections 221 through 

237 of the EPAct, entitled the ‘‘John 

Rishel Geothermal Steam Act 

Amendments,’’ amended the GSA, 30 

U.S.C. 1001 et seq. (1970). Congress 

enacted the EPAct geothermal 

amendments to encourage geothermal 

production through regulatory 

streamlining and incentives. S. Rep. No. 

78, 109th Cong., 1st Sess. (2005). 

C. The Proposed Rule 

On July 21, 2006, MMS published a 

proposed rule in the Federal Register 

(71 FR 41516) that addressed 

implementing the EPAct provisions. It 

also incorporated most of the 

Subcommittee’s concepts, with 

modifications necessary to comply with 

the EPAct. 

For 30 CFR part 206, subpart H, we: 

(1) Explained the general royalty 

calculation and payment, direct use fee, 

and royalty valuation provisions of this 

subpart; (2) defined which leases the 

subpart applies to; (3) provided 

definitions of terms used in the subpart; 

(4) proposed some changes to conform 

to plain English writing; and (5) 

proposed changes necessary to 

implement provisions of the EPAct. 

For 30 CFR parts 202, 210, and 218, 

we proposed changes necessary to 

implement provisions of the EPAct and 

reflect the proposed amendments to 30 

CFR part 206, subpart H. 

II. Comments on the Proposed Rule 

The MMS received comments on the 

proposed rule from two States, one trade 

association, and two geothermal 

producers. These comments are 

analyzed and discussed below: 

A. 30 CFR Part 202—Royalties 

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

geothermal resources 

Public Comments: The trade 

association commented that the 

definition of ‘‘gross proceeds’’ in §

206.351 of the proposed rule should 

state that ‘‘station usage power 

(including auxiliary load) * * * are not 

included [in the gross proceeds].’’ 

MMS Response: The MMS specifically 

stated in proposed § 202.351(b)(2)(ii) 

that it ‘‘will allow free of royalty or fees 

a reasonable amount of geothermal 

energy necessary to generate electricity 

for internal power plant operations or to 

generate electricity returned to the lease 

for lease operations’’ (71 FR 41531). We 

believe that § 202.351(b)(2) would 

allow a lessee to use a reasonable 

amount of station usage power royalty 

free. Therefore, we did not include it in 

the definition of ‘‘gross proceeds’’ in §

206.351. 

However, § 202.351 has been revised 

in the final rule in several respects to 

better reflect the new basis for royalty 

for leases issued under the EPAct (and 

leases whose royalty terms are 

converted to EPAct terms under the 

BLM final rule). Under 30 U.S.C. 

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Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 24449 

1004(a)(1), a lease issued under the 

EPAct whose geothermal resource 

production is used for commercial 

production or generation of electricity 

must provide for a royalty as a specified 

percentage of the gross proceeds from 

the sale of the electricity. The royalty 

under such leases is no longer imposed 

on the volume of geothermal resources 

produced; it is imposed only on the 

proceeds derived from sale of the 

electrical energy, regardless of the 

volume used to generate the electricity. 

In paragraph (a) of § 202.351, MMS 

has modified the proposal to clarify that 

royalties on electricity produced using 

geothermal resources will be at the 

royalty rate specified in the lease. 

Similarly, in paragraph (b)(1), MMS has 

added language to clarify that royalties 

are due on all proceeds derived from the 

sale of electricity generated using the 

geothermal resources produced from a 

lease. 

We have made a number of clarifying 

changes to proposed paragraph (b)(2). 

Paragraph (b)(2) of the proposed rule 

identified certain volumes of geothermal 

resources that would be free of royalty 

or direct use fees—namely, (1) 

unavoidably lost resources and 

resources reinjected before use; (2) 

resources used to generate ‘‘electricity 

for internal power plant operations’’ 

(referred to in the final rule as ‘‘plant 

parasitic electricity,’’ which is defined 

in a revised definition in § 206.351); (3) 

resources used to generate electricity 

returned to the lease for lease operations 

(referred to in the final rule as 

‘‘electricity for Federal lease 

operations’’); and (4) commercially 

demineralized water necessary for 

power plant operations or otherwise 

used on or for the benefit of the lease. 

The relevance and consequences of 

these volume categories are different 

depending on the legal category of the 

lease involved and the use of the 

geothermal resources produced from the 

lease. The different legal categories to 

which a lease may belong are defined in 

§ 206.351 of the final rule. As more 

fully prescribed in that section, ‘‘Class 

I leases’’ are leases issued before the 

date of enactment of the EPAct (or in 

response to an application pending on 

that date) which the lessee does not 

convert to EPAct terms. ‘‘Class II leases’’ 

are leases issued after the date of 

enactment of the EPAct (except for 

leases issued in response to an 

application pending on that date which 

the lessee does not convert to EPAct 

terms). ‘‘Class III leases’’ are leases 

issued before the date of enactment of 

the EPAct that the lessee converts to 

EPAct royalty terms. Paragraph (b)(2) in 

the final rule addresses what is free of 

royalty or direct use fees first by the 

legal category of the lease and then by 

the use of the resource. 

Clause (i) of paragraph (b)(2) 

addresses Class I leases, which are 

covered by the existing rule. This 

paragraph preserves the existing rule’s 

treatment for royalty purposes of each of 

the volume categories identified 

above—i.e., that all of them are free of 

royalty. The determination of the 

reasonable amount of the resource used 

to generate plant parasitic electricity 

under a Class I lease is subject to MMS 

jurisdiction. (Commercially 

demineralized water is relevant only 

under Class I leases, and therefore is not 

mentioned in the subsequent clauses 

addressing Class II and Class III leases.) 

Clause (ii) of paragraph (b)(2) 

addresses Class II leases and Class III 

leases (leases with EPAct royalty terms) 

whose geothermal resources are used for 

the commercial production or 

generation of electricity or are sold at 

arm’s length for the commercial 

production or generation of electricity. 

For these leases, if the lessee sells 

electricity on the commercial market, 

the lease provides for royalty as a 

percentage of gross proceeds derived 

from sale of the electricity. Unavoidably 

lost or reinjected resource volumes and 

volumes associated with generating 

plant parasitic electricity or electricity 

for lease operations do not result in 

generation of any electricity that is sold. 

It follows that there are no gross 

proceeds from the sale of electricity that 

result from them. Therefore, these 

volumes have no royalty consequence. 

However, under a Class II lease or 

Class III lease, if the lessee sells the 

geothermal resource at arm’s length 

before commercial production or 

generation of electricity, under the final 

rule royalty is a function of the gross 

proceeds derived from the sale of the 

resource. To the extent that any loss of 

resources is avoidable, MMS would 

require the lessee to pay royalties on 

that volume. Thus, it is appropriate to 

clarify that only unavoidably lost or 

reinjected volumes are not royaltybearing. MMS will also allow free of 

royalty a reasonable amount of resource 

volumes used to generate electricity for 

Federal lease operations. (There is no 

plant parasitic electricity if the lessee 

sells the resource and, therefore, no 

resources are used to generate it.) 

The existing rule and the proposed 

rule refer to electricity ‘‘returned to the 

lease for lease operations.’’ In the final 

rule, the phrasing of the term has been 

clarified to ‘‘electricity for Federal lease 

operations.’’ First, it is not necessary 

that this electricity be generated off the 

lease and then ‘‘returned to the lease.’’ 

Second, MMS wishes to clarify that 

resources used to generate electricity for 

non-Federal (e.g., state or private) lease 

operations are not royalty-free. 

Approval of the amount of resources 

used to generate electricity for lease 

operations that is royalty-free is subject 

to BLM, rather than MMS, jurisdiction. 

In addition to the royalty effects 

discussed above, the rule must also 

address the question of what resources, 

if any, might be subject to direct use 

fees. Under 30 U.S.C. 1001(g), the term 

‘‘direct use’’ means ‘‘utilization of 

geothermal resources for commercial, 

residential, agricultural, public 

facilities, or other energy needs other 

than the commercial production of 

electricity.’’ The definition of the term 

‘‘direct use’’ in the final rule at 30 CFR 

206.351 is essentially identical. Section 

206.351 then defines the term 

‘‘commercial production or generation 

of electricity’’ to include the electricity 

or energy that is reasonably required 

both to produce the resource and to 

convert geothermal energy into 

electrical energy for sale. This definition 

includes the generation of both plant 

parasitic electricity and electricity for 

lease operations, as well as other uses of 

resources for lease operations. 

Therefore, where the lessee of a Class II 

lease or Class III lease sells electricity 

commercially, use of resources for these 

purposes, by definition, does not 

constitute a direct use under the final 

rule. The resources therefore are not 

subject to direct use fees. 

The text of clause (ii) covers each of 

the situations and consequences 

described above. 

Clause (iii) addresses direct use fees 

when the geothermal resources 

produced from a Class II lease or Class 

III lease are used for direct use purposes 

other than commercial production or 

generation of electricity, as those terms 

are defined in 30 CFR 206.351. It is 

appropriate to allow unavoidably lost 

and reinjected resource volumes to be 

free of direct use fees because they are 

not used and are not avoidably lost. 

However, because generating electricity 

for direct use lease operations falls 

within the definition of ‘‘direct use’’ 

under § 206.351, a direct use fee will 

be imposed on the associated volumes. 

2. 202.353 Measurement standards for 

reporting and paying royalties 

Public Comments: One State 

commented that proposed § 202.353, 

which adds a new paragraph requiring 

reporting to the ‘‘nearest whole million’’ 

for direct use leases, ‘‘could encourage 

a lessee to control its incremental 

production to avoid royalties.’’ The 

State recommended ‘‘eliminating it.’’ 

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24450 Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 

MMS Response: In the proposed rule, 

the MMS proposed to change the 

existing rule, at § 202.353(b)(2), which 

requires reporting to the ‘‘nearest 

hundred gallons’’ to require reporting to 

the ‘‘nearest million gallons.’’ The MMS 

also proposed to add a new 

subparagraph 202.353(b)(3), which 

states that lessees may report the 

quantity of direct use resources in 

‘‘millions of pounds to the nearest 

million pounds of geothermal fluid 

produced if valuation is in terms of 

mass.’’ The MMS used millions of 

gallons because that is the volume 

measurement the Royalty Policy 

Committee (RPC) Geothermal Valuation 

Subcommittee recommended for the fee 

schedule. In addition, the MMS added 

the ‘‘millions of pounds’’ and changed 

to the ‘‘millions of gallons’’ to conform 

to the fee schedule we proposed in §

206.356. Therefore, we are not 

eliminating the requirement to report to 

the ‘‘nearest whole million.’’ In addition 

to this change, we have reformatted this 

section to make it easier to use. 

B. 30 CFR Part 206—Product Valuation, 

Subpart H—Geothermal Resources 

1. 30 CFR 206.351 What definitions 

apply to this subpart? 

Definition of Class I, II, and III Leases 

MMS did not receive any comments 

on its definition of the classes of leases 

subject to this rulemaking. However, 

after consultation with BLM, MMS 

determined that its definitions did not 

accurately reflect the royalty rate or 

direct use fees terms of the BLM 

regulations for each class of leases. 

Therefore, to clarify the classes of leases 

and be consistent with BLM regulations, 

we are changing the description of the 

lease classes in this final rule. 

For Class I leases, we have eliminated 

any cross-references to ‘‘Class II’’ leases 

and clarified in part (1) that a 

conversion under 43 CFR 3212.25 

relates to converting royalty rate terms. 

Thus, in the final rule, a Class I lease 

means: 

(1) A lease that BLM issued before 

August 8, 2005, for which the lessee has 

not converted the royalty rate terms 

under 43 CFR 3212.25; or 

(2) A lease that BLM issued in 

response to an application that was 

pending on August 8, 2005, for which 

the lessee has not made an election 

under 43 CFR 3200.8(b). 

For Class II leases, in MMS’s 

proposed rule, we inadvertently omitted 

a category of leases that qualify as 

‘‘Class II.’’ The proposed rule defined 

Class II leases as only those leases BLM 

issues on or after the effective date of 

the final BLM regulation under 43 CFR 

subparts 3203, 3204, or 3205. However, 

a lease that BLM issued in response to 

an application that was pending on 

August 8, 2005, either before or after the 

date of the final BLM regulation, for 

which the lessee has made an election 

under 43 CFR 3200.8(b), is also a ‘‘Class 

II’’ lease. Therefore, we modified the 

Class II definition to capture all eligible 

leases issued after August 8, 2005. So, 

in the final rule, a Class II lease means: 

A lease that BLM issued after August 8, 

2005, except for a lease issued in response to 

an application that was pending on August 

8, 2005, for which the lessee does not make 

an election under 43 CFR 3200.8(b). 

With respect to Class III leases, in our 

proposed rule, we stated that a ‘‘Class III 

lease means a Class I lease that the 

lessee converts to a Class II lease under 

43 CFR subpart 3212.’’ (Emphasis 

added.) However, that definition 

misstated the leases to which it applied 

in two ways. First, only lessees of Class 

I leases that BLM issued before August 

8, 2005, can convert the royalty terms of 

their leases under 43 CFR 3212.25. 

Lessees of leases that BLM issued in 

response to an application that was 

pending on August 8, 2005, for which 

the lessee has not made an election 

under 43 CFR 3200.8(b), could not 

convert the royalty terms of their leases 

under 43 CFR 3212.25 even though they 

are Class I leases. Therefore, the 

definition of Class III leases in the 

proposed rule referring to all Class I 

leases was inaccurate. Second, contrary 

to the definition in the proposed rule, a 

Class III lease would not convert to a 

Class II lease. Indeed, the royalty terms 

of a Class II lease are different from 

those of a Class III lease that BLM issued 

before August 8, 2005, for which the 

lessee has converted to the royalty rate 

or direct use fee terms under 43 CFR 

3212.25. In other words, Class III leases 

have different royalty terms (including 

direct use fees in lieu of royalties) than 

Class II leases. Thus, the definition in 

the proposed rule stating that Class III 

leases were converted to Class II leases 

was incorrect. 

Accordingly, in the final rule, a Class 

III lease means: 

A lease that BLM issued before August 8, 

2005, for which the lessee has converted to 

the royalty rate or direct use fee terms under 

43 CFR 3212.25. 

The lessee of a Class III lease may also 

elect, under 43 CFR 3200.7(a)(2), to be 

subject to all of the BLM regulations for 

leases issued after August 8, 2005. 

Definition of Direct Use 

Public Comments: One commenter 

observed that both MMS and BLM have 

definitions of direct use but defined the 

term to include ‘‘generation’’ in 

‘‘slightly different ways.’’ The 

commenter suggested that MMS and 

BLM agree on one definition. 

MMS Response: In section 236 of the 

EPAct (adding 30 U.S.C. 1001(g)), 

Congress defined direct use to mean the 

‘‘utilization of geothermal resources for 

commercial, residential, agricultural, 

public facilities, or other energy needs 

other than the commercial production of 

electricity’’ (emphasis added). In the 

proposed rule, we proposed to use that 

definition, but substitute the word 

‘‘generation’’ for ‘‘production’’ because 

Congress did not define the term 

commercial production of electricity. 71 

FR 41518. As we explained in the 

preamble to the proposed rule: 

Other sections of the EPAct (see the new 

30 U.S.C. 1004(b), added by EPAct section 

223(a), and new 30 U.S.C. 1003(f), added by 

EPAct section 223(b)) use the term 

commercial generation of electricity. The two 

terms appear from the statutory context to 

have the same meaning. Therefore, 

commercial production or generation of 

electricity would mean generation of 

electricity that is sold or is subject to sale, 

including the electricity that is required to 

convert geothermal energy into electrical 

energy for sale. 

Id. However, as the result of a clerical 

error, MMS proposed to define the term 

as only ‘‘the commercial generation of 

electricity,’’ whereas BLM defined it to 

include ‘‘commercial production or 

generation of electricity’’ (43 CFR 

3200.1) (71 FR 41543). To be consistent, 

we are changing the definition in the 

final rule to conform to BLM’s 

definition and include the term 

‘‘commercial production or generation 

of electricity’’ (emphasis added). 

Definition of Gross Proceeds 

Public Comments: As discussed 

above, the trade association commented 

that the definition of gross proceeds in 

30 CFR 206.351 of the proposed rule 

should state that ‘‘station usage power 

(including auxiliary load) and wheeling 

and transmission charges * * * are not 

included [in the gross proceeds].’’ 

MMS Response: As discussed above, 

§ 202.351(b)(2) would allow the use of 

station usage power royalty-free. 

However, the definition of gross 

proceeds in our geothermal regulations 

has never included wheeling and 

transmission charges as part of gross 

proceeds. In the 1991 final rule, 

wheeling and hydrogen sulfide 

abatement were deleted from the 

definition ‘‘because these operations are 

associated with utilization of the 

geothermal resource rather than 

production; any reimbursements the 

lessee receives for these operations 

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Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 24451 

would be deducted from the lessee’s 

costs of performing them when 

calculating the transmission and 

generating cost rates under the netback 

procedure’’ (58 FR 57271). In the 

proposed rule at § 206.352(b)(1), we 

explained that lessees who are currently 

using the netback method who choose 

not to convert to the EPAct royalty 

terms will continue to be allowed to 

deduct transmission and generating 

allowances, including wheeling charges. 

However, as we explained in the 

preamble to the proposed rule, such 

charges are not excluded from the 

definition of gross proceeds because 

lessees who do convert to the EPAct 

royalty terms will have a royalty rate 

that accounts for the previous 

transmission and generating deductions 

in order to remain revenue neutral (71 

FR 41519). Therefore, MMS is not 

changing the definition of gross 

proceeds in the final rule. 

In the final rule, MMS has modified 

the definition of ‘‘commercial 

production or generation of electricity’’ 

to clarify that the term includes 

electricity or energy that is required to 

produce the resource, as well as that 

required to convert the resource into 

electrical energy for sale. This was 

MMS’s intent in the proposed rule. This 

term is important in determining 

whether geothermal resource 

production is subject to royalties or 

direct use fees, as explained more fully 

in the preamble to the final BLM rule. 

The revised definition is consistent with 

the definition in the BLM final rule. 

In the definition of ‘‘plant parasitic 

electricity’’ in the final rule, MMS has 

specified that it means electricity used 

to operate a power plant that is used for 

commercial production or generation of 

electricity. Plant parasitic electricity 

does not include electricity generated to 

power a direct use operation. (The term 

‘‘plant parasitic electricity’’ is actually 

used only in 30 CFR 202.351, the 

provision addressing which geothermal 

resources are free of royalty and direct 

use fees. It is not used in part 206. 

However, it is more efficient to define 

it in part 206, together with other 

related terms that are used in both part 

206 and part 202, and which part 202 

incorporates by reference to the part 206 

definitions.) 

2. 30 CFR 206.352 How do I calculate 

the royalty due on geothermal resources 

used for commercial production or 

generation of electricity? 

Public Comments: One State 

commented that because paragraphs 

(b)(2) and (b)(3) do not allow any 

deductions from gross proceeds, it 

creates an ambiguity because the 

definition of gross proceeds in §

206.351 does not also state there are no 

deductions from gross proceeds. The 

State also expressed concern that the 

proposed rules ‘‘appear to imply that 

royalties can be determined by the 

‘netback’ method for arm’s length 

transactions’’ and suggested that we 

clarify that the ‘‘netback method’’ only 

applies to current leases. One producer 

commented that it was unsure how to 

value geothermal production when it is 

sold directly to the ratepayers. The 

commenter believes that the only 

valuation options would be to request 

an alternative valuation methodology or 

convert the leases to direct use leases 

and pay fees in lieu of royalties. 

MMS Response: Although lessees may 

not take deductions from their gross 

proceeds under paragraphs (b)(2) and 

(b)(3) of this section, as explained 

above, in proposed § 206.352(b)(1), 

lessees who are currently using the 

netback method who chose not to 

convert to the EPAct royalty terms will 

continue to take transmission and 

generating deductions from their gross 

proceeds. Therefore, MMS is not 

changing the definition of gross 

proceeds in the final rule. 

With respect to the comment that the 

proposed rule implies that the netback 

calculation applies to royalty 

calculations for arm’s-length 

transactions, § 206.352(a) clearly states 

that for geothermal resources purchased 

‘‘at arm’s length that the purchaser uses 

to generate electricity, then the royalty 

on the geothermal resources is the gross 

proceeds accruing to you from the sale 

of the geothermal resource to the arm’slength purchaser multiplied by the 

royalty rate in your lease or that BLM 

prescribes or calculates under 43 CFR 

3211.17.’’ Therefore, MMS sees no need 

for clarification regarding the netback 

method and arm’s-length situations. 

With respect to how to value 

geothermal resources when electricity is 

sold directly to ratepayers (consumers of 

the electricity), rather than the typical 

situation where the lessee sells 

electricity under an arm’s-length 

contract to a utility, we are assuming 

that the sales to the ratepayers are also 

arm’s length. We are further assuming 

that the lessee would have contractual 

agreements with the ratepayers for the 

sales of electricity. In that instance, the 

gross proceeds would be the 

combination of the sales to multiple 

ratepayers. The same would hold true if 

a lessee sold electricity to multiple 

utilities. Therefore, the lessee would 

pay under § 206.352(b)(1). Of course, 

the commenter is correct that the lessee 

could request a value or gross proceeds 

methodology under § 206.364. 

However, the lessee could not convert to 

a direct use fee lease. The fee schedule 

is only for direct use of a geothermal 

resource that is not used for commercial 

electrical generation purposes. 

3. 30 CFR 206.353 How do I determine 

transmission deductions? and 30 CFR 

206.354 How do I determine generating 

deductions? 

Public Comments: One commenter 

objected to our proposal to amend § §

206.353 and 206.354 by deleting 

paragraph (f) of those sections. That 

paragraph provided for a one-time 

refund of royalties based on the royalty 

percentage of actual dismantlement 

costs of transmission lines and power 

plants in excess of income from salvage 

at the completion of dismantlement and 

salvage operations. The commenter 

stated that the MMS explanation that 

this provision has never been used did 

not take into account that geothermal 

power plants are relatively new and last 

many years ‘‘such that no plant or 

transmission line has ever been 

dismantled.’’ The commenter believes 

that elimination of the refunds would 

have a ‘‘potentially significant financial 

impact in the future and remove the 

incentive intended to ensure such 

actions are taken * * *.’’ 

MMS Response: With respect to 

dismantlement costs, the preamble to 

the existing rule discussed the rationale 

for allowing a refund: 

The MMS recognizes that the costs of 

dismantling, decommissioning, or 

abandoning the power plant and/or 

transmission line are indeed part of the 

lessee’s costs associated with those facilities. 

However, these are future costs that are not 

easily estimated tens of years in advance, and 

in fact may not even occur at the end of a 

given project if the facilities are converted to 

other uses. Nevertheless, it is MMS’ intent to 

recognize power plant and transmission line 

dismantlement costs when those costs 

actually occur. This will be accomplished by 

allowing the lessee a one-time refund of 

royalty equal to the royalty amount of actual 

dismantlement costs in excess of actual 

salvage income (i.e., royalty rate times the 

amount of dismantlement costs in excess of 

salvage income) * * * (56 FR 57256, 57263). 

As the commenter noted, the main 

reason this refund has not been used is 

the lack of geothermal power plant 

dismantlements. The intent of the 

proposed rule was not to change the 

existing regulations substantively so 

that lessees who stay under the existing 

regulations will continue paying 

royalties as they are now. Therefore, 

MMS is reinstating the dismantlement 

costs refund as it is in the existing 

regulations at § § 206.353(f) and 

206.354(f), rewritten in plain English. 

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In the final rule, MMS has changed a 

provision of § 206.353(b)(1) regarding 

determination of transmission line costs 

that corrects an inadvertent 

inconsistency in both the existing rule 

and the proposed rule. The existing rule 

(at § 206.353(b)(1)) and the proposed 

rule (at § 206.353(b)(1)(ii)) both provide 

that the lessee must redetermine the 

transmission line cost rate annually, 

beginning either at the same month of 

the year in which the transmission line 

was placed into service, the same month 

of the year in which the power plant 

was placed into service, or at a time 

coinciding with the beginning of the 

lessee’s annual corporate accounting 

period. Both the existing rule and the 

proposed rule then provide that the 

period selected must be the same period 

used in redetermining the generating 

cost rate under § 206.354(b)(1). 

However, § 206.354(b)(1) (in both the 

existing rule and the proposed rule) 

does not provide an option for 

redetermining the generating cost rate 

beginning at the same month of the year 

in which the transmission line was 

placed into service. It provides only for 

either the same month of the year in 

which the power plant was placed into 

service or at the beginning of the 

lessee’s annual corporate accounting 

period. Thus, it is not possible to elect 

to redetermine the transmission line 

cost rate beginning at the same month 

of the year in which the transmission 

line was placed into service, and no 

lessee attempted to do so. For these 

reasons, the final rule eliminates this 

option. 

The proposed rule, at § 206.353(h), 

provided that to compute depreciation 

for a transmission line (as part of 

calculating actual transmission line 

costs), the lessee could elect to use 

either a straight-line depreciation 

method based on the life of the 

equipment or on the life of the reserves 

that the transmission line services, or a 

return on capital investment method. 

This proposed provision would have 

changed the requirement in the existing 

rule (at § 206.353(b)(2)(iv)(A)) to 

compute depreciation using a straightline method based on the life of the 

geothermal project (usually the term of 

the electricity sales contract) or other 

depreciation period acceptable to MMS. 

There was no discussion or explanation 

of this provision in the preamble to the 

proposed rule. It is uncertain how the 

change in language arose, because MMS 

intended no change in the existing 

provision. 

Further, the proposed rule in the same 

paragraph omitted language in the 

existing rule to the effect that a change 

in ownership of a transmission line does 

not alter the depreciation schedule 

established by the original lessee-owner 

for purposes of determining 

transmission line costs. Again, MMS 

intended no change in the existing rule 

in this regard. Both of these errors are 

corrected in § 206.353(h) of the final 

rule. 

A similar unexplained change 

appeared in the depreciation provisions 

of the proposed rule for calculating 

generating deductions at § 206.354(h). 

The proposed rule would have added to 

the existing rule (at §

206.354(b)(2)(iv)(A)) an option to 

compute depreciation on a unit-ofproduction method. This does not 

appear to be appropriate in the 

geothermal context. The proposed rule 

again omitted language in the existing 

rule regarding a change in ownership of 

the power plant not altering the original 

depreciation schedule. Both of these 

errors have been corrected in the final 

rule. 

4. 30 CFR 206.356 How do I calculate 

royalty or fees due on geothermal 

resources I use for direct use purposes? 

Public Comments: Two commenters 

objected to MMS’s minor modifications 

to the fee schedule proposed by the 

Subcommittee. Specifically, a 

commenter requested that MMS 

eliminate the efficiency factor in the 

denominator of the equation for 

calculating fees, and one commenter 

objected to the increase in fees in the 

proposed schedule from the schedule 

the Subcommittee recommended. 

Another commenter stated that, under 

the proposed rule, a lessee could not 

produce electricity from a Class III lease. 

MMS Response: With respect to the 

efficiency factor, MMS used the same 

formula as the Subcommittee, which 

included the efficiency factor. The 

Subcommittee used the efficiency factor 

because: 

Valuation using coal, wood chips, or 

natural gas is based on ‘‘displaced energy,’’ 

where the binary valuation is based on 

‘‘extracted energy.’’ Displaced energy uses an 

efficiency factor to account for heat lost 

during the combustion of the alternative 

fuels. The efficiency factor typically adds 25 

percent to 33 percent to the value of those 

fuels. 

Royalty Policy Committee Geothermal 

Valuation Subcommittee Report (May 

2005), Attachment 3, page 2. 

If we eliminate the efficiency factor 

from the formula, it would erroneously 

assume that the use of geothermal 

resources for direct use purposes is 100 

percent efficient. Because the direct use 

of geothermal energy is not 100 percent 

efficient, MMS will keep the efficiency 

factor to account for heat lost during the 

direct use of geothermal resources. 

With respect to the increase in fees in 

the proposed schedule from the fees in 

the Subcommittee Report, the 

Subcommittee recommended using 

Powder River Basin coal prices to 

determine what a Btu of heating energy 

was worth. That measure was to be used 

in calculating royalty owed on 

geothermal resources used in direct use 

projects and not sold. Powder River 

Basin coal prices had been relatively 

stable for some time. However, the 

Subcommittee contemplated that MMS 

would change the fee schedule from 

time to time. In the interim between the 

Subcommittee Report and publication of 

the proposed rule, Powder River Basin 

coal prices increased. The MMS 

believes it is eminently reasonable to 

update the fee schedule to reflect 

current coal prices, rather than past 

prices. Thus, we will retain the 

proposed fee schedule. 

It is possible that a lessee of a 

geothermal lease may use the 

geothermal resource first to produce 

electricity and then either sell or use the 

still-hot water for direct use in another 

operation. (This is sometimes known as 

‘‘cascading.’’) Cascading is a process in 

which the user gains the use of the heat 

after its use by the same or a different 

party who is using the higher-grade 

geothermal resource to generate 

electricity. As we stated in the preamble 

to the final 1991 geothermal rule, ‘‘the 

issue of royalties due on geothermal 

resources utilized in cascading steps is 

straightforward: the lessee is responsible 

for paying royalty on the total thermal 

energy yielded by the resource’’ (56 FR 

57268). The MMS believes that this 

philosophy also is consistent with the 

intent of Congress in the EPAct. 

The MMS knows of two operations 

that involved ‘‘cascading’’ in the past, 

but there appears to be no current 

operation that involves a second use of 

the resource after commercial 

generation of electricity. Nevertheless, 

such a situation may arise again in the 

future, and MMS therefore has 

addressed this issue here. 

Thus, for example, assume that the 

lessee uses the geothermal resource to 

generate electricity. Also assume that 

the lessee then uses the still-hot 

geothermal resource, after it is used in 

the plant for electrical generation, in a 

direct use operation. In that instance, as 

with the existing regulations, under this 

rule, the lessee of a Class I lease would 

have to pay royalties on both the direct 

use and electrical generation. For Class 

II and Class III leases, the lessee would 

have to pay royalties on the gross 

proceeds derived from commercial 

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electrical generation and fees for the 

direct use. MMS has added language to 

§ 202.351(b)(1) to clarify this principle. 

5. 30 CFR 206.357 How do I calculate 

royalty due on byproducts? 

Public Comments: We received one 

comment that the rule is contrary to the 

EPAct because it requires that royalties 

be paid on byproducts other than those 

named under the EPAct. 

MMS Response: In the EPAct, for new 

leases, Congress changed the byproducts 

upon which royalties are due, to include 

‘‘any mineral or minerals specified in 

the Mineral Leasing Act, 30 U.S.C. 181’’ 

(30 U.S.C. 1004(a)(2)). Therefore, we 

agree that, although Congress did not 

change the definition of ‘‘byproduct,’’ in 

30 U.S.C. 1001, it did provide that 

under leases issued under the EPAct 

royalties are due only on those 

byproducts that also are minerals 

identified in § 181, i.e. phosphate, 

sodium, and potassium. We refer you to 

the BLM regulations at 43 CFR 

3211.19(a), which incorporate this 

change. 

We also revised § 206.357 in the final 

rule to separate the introductory 

language in the proposed rule into two 

paragraphs and clarify that royalty is 

due on those byproducts that are 

royalty-bearing under the lease terms of 

Class I leases and of Class III leases that 

do not elect to convert to all of the 

regulations promulgated in the final 

BLM rule for leases issued after August 

8, 2005. Conversion of a Class I lease to 

a Class III lease (conversion of the 

royalty terms) does not by itself modify 

the lease terms pertaining to 

byproducts. However, the BLM rule at 

43 CFR 3200.7(a)(2) allows a lessee who 

does convert the royalty terms of a Class 

I lease an additional option to also 

convert all other terms, which would 

include the provisions regarding 

byproducts. Thus, some Class III leases 

may retain the original lease terms 

regarding byproducts, while others will 

effectively convert to the EPAct 

byproduct terms. 

For Class II leases and those Class III 

leases that do elect to convert to all the 

terms of the BLM rule for leases issued 

after August 8, 2005, royalty is due 

under 30 U.S.C. 1004(a)(2) on those 

byproducts that are identified in 30 

U.S.C. 181. 

There is one geothermal lessee of a 

Class I lease who has paid royalty on 

sulfur as a byproduct in the past. No 

lessee has paid royalty on any 

byproducts for more than two years. 

Though theoretically possible, MMS 

believes that it is extremely unlikely 

that phosphate, sodium, or potassium 

will be produced as a byproduct of 

geothermal hot water or steam. To 

MMS’ knowledge, there are no instances 

of commercially viable production of 

such byproducts in the past. MMS 

therefore does not expect any significant 

production of any royalty-bearing 

byproducts from Class II leases or from 

Class III leases that convert all their 

terms to the new rule. 

6. 30 CFR 206.359 How do I determine 

byproduct transportation allowances? 

The proposed rule at § 206.359(h) 

provided that in computing 

depreciation, the lessee may elect to use 

either a straight-line method based on 

the life of the transportation system, the 

life of the reserves which the 

transportation system services, or a unitof-production method. This would have 

changed the option in the existing rule 

(at § 206.358(b)(2)(iv)(A)) to use either 

a straight-line method based on the life 

of equipment or the life of the 

geothermal project that the 

transportation system services. As with 

the other depreciation provisions 

discussed above, there was no 

explanation of this proposed change in 

the preamble. MMS again does not 

intend a change to the meaning of the 

existing rule. The proposed rule (as with 

the other provisions) also omitted 

language regarding a change in 

ownership of the transportation system 

not altering the depreciation schedule 

established by the original lessee-owner. 

Both of these errors have been corrected 

in § 206.359(h) of the final rule. 

MMS does not expect wide 

applicability of these provisions in view 

of the fact that no lessees currently are 

reporting royalties on byproducts or 

byproduct transportation allowances. 

Nevertheless, these provisions may 

become applicable in the future, and the 

final rule should not create unnecessary 

confusion. It is therefore appropriate to 

make the corrections described above. 

C. 30 CFR Part 217—Audits and 

Inspections, Subpart H—Geothermal 

Resources 

Although the regulatory text of part 

217 was omitted from the proposed rule, 

an opportunity for public comment was 

provided in the preamble discussion, 

including the information collection 

requirements. No comments were 

received regarding part 217, which 

contains technical, noncontroversial 

audit information. The regulatory text of 

part 217 is included in this final rule. 

D. 30 CFR Part 218—Collection of 

Royalties, Rentals, Bonuses and Other 

Monies Due the Federal Government, 

Subpart F—Geothermal Resources 

1. 30 CFR 218.303 May I credit rental 

towards royalty? 

Public Comments: We received one 

comment stating that the proposed 

rule’s requirement that the credit be 

taken ‘‘only in the year paid-goes 

beyond the law, is too strict, and will 

have the unforeseen consequence of 

imposing financial burdens when 

companies can least afford additional 

costs.’’ 

MMS Response: In section 230 of the 

EPAct, Congress added a new 30 U.S.C. 

1004(e) that authorized lessees to credit 

‘‘[a]ny annual rental under this section 

that is paid with respect to a lease 

before the first day of the year for which 

the annual rental is owed shall be 

credited to the amount of royalty that is 

required to be paid under the lease for 

that year’’ (emphasis added). We think 

it is clear from the language of the 

EPAct that lessees may credit annual 

rental paid in a particular year only to 

royalties paid ‘‘that year.’’ Thus, 

Congress, not MMS, has directed that 

credits for rentals paid be restricted to 

the year for which they are paid. Any 

other construction is contrary to the 

statute’s plain language. 

Title 30 U.S.C. 1004(e), as added by 

section 230 of the EPAct, provides that 

‘‘[a]ny annual rental under this section 

that is paid with respect to a lease 

before the first day of the year for which 

the annual rental is owed shall be 

credited to the amount of royalty that is 

required to be paid under the lease for 

that year.’’ It is apparent that Congress 

intended this provision to apply to postEPAct leases. It is only under section 

1004(a)(3), as added by the EPAct, that 

a lessee must continue to pay annual 

rental regardless of whether the lease is 

in production. Under the terms of preEPAct leases, rental ceases when the 

lease goes into production (and the lease 

is then subject to minimum royalty). 

Thus, the rental crediting provision 

will apply to Class II leases, as defined 

in 30 CFR 206.351. In addition, Class III 

leases as defined in that section may 

elect to be subject to all of the BLM 

regulations promulgated for leases 

issued after August 8, 2005, under 43 

CFR 3200.7(a)(2). That election would 

operate to convert the rental terms to 

EPAct terms. Crediting annual rental 

against royalty therefore should apply to 

those leases as well. Class III leases that 

do not elect to be subject to all of the 

regulations promulgated for post-EPAct 

leases will retain their existing rental 

terms. The crediting provision therefore 

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24454 Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 

should not apply to those Class III 

leases. MMS has revised the language of 

§ 218.303(a) in the final rule to clarify 

this principle. 

2. 30 CFR 218.304 May I credit rental 

towards direct use fees? 

Public Comments: We received three 

comments urging that lessees who pay 

fees under direct use leases should be 

allowed to credit rental towards fees 

because the commenters believe ‘‘fees’’ 

are ‘‘royalties.’’ One commenter alleged 

that payment of the fees and rental 

would increase monies paid the 

Government for direct use to ten times 

that paid for electricity. Another 

commenter stated that collecting fees 

and rentals for direct use is contrary to 

the ‘‘intent of the EPAct where the 

agency is directed to encourage direct 

use of geothermal resources.’’ 

MMS Response: In section 223 of the 

EPAct, Congress added a new 30 U.S.C. 

1004(b) that directed the Secretary to 

‘‘establish a schedule of fees, in lieu of 

royalties’’ (emphasis added). ‘‘In lieu 

of’’ means ‘‘instead of; in place of; in 

substitution of.’’ It does not mean ‘‘in 

addition to.’’ Black’s Law Dictionary 

787 (6th ed. 1990). Thus, the plain 

language of the EPAct makes it clear 

that ‘‘fees’’ are not ‘‘royalties.’’ In 30 

U.S.C. 1004(e) (added by section 230 of 

the EPAct), Congress authorized lessees 

to credit ‘‘[a]ny annual rental under this 

section that is paid with respect to a 

lease before the first day of the year for 

which the annual rental is owed will be 

credited to the amount of royalty that is 

required to be paid under the lease for 

that year’’ (emphasis added). Therefore, 

the MMS correctly concluded that 

rentals could not be credited towards 

fees because fees are not royalties. 

With respect to the concerns that 

payment of fees and rentals will 

increase direct use lease payment to ten 

times that of those for electricity and is 

contrary to the EPAct, MMS can find no 

support for that position. As we stated 

in the preamble to the proposed rule, for 

commercial generation of electricity, 

‘‘[b]ecause the EPAct mandates that the 

royalty revenues received by MMS 

should be the same as what would have 

been received under the valuation 

methods of the current regulations, 

there would be no revenue impact for 

electrical generation projects’’ (71 FR 

41523). Direct use projects are paying 

substantially less under the EPAct than 

under the old rules. As stated in the 

preamble to the proposed rule, for direct 

use projects: 

Current direct use lessees who do not sell 

the geothermal resources would have the 

option to convert their leases to the new fee 

schedule, which would result in a reduction 

of $60,000 per year from the current level of 

royalties, a 95-percent reduction. In addition, 

all new direct use lessees who do not sell the 

geothermal resources under the new 

regulations would use the same fee schedule, 

also paying about 95 percent less than they 

would have under the current regulations. 

71 FR 41524. With a 95-percent 

reduction in payments made under a 

direct use lease, it is not possible that 

payment of rentals would increase 

revenues paid on a lease to ten times the 

royalty paid on geothermal resources 

used in electrical generation plants, 

whose payments remain the same. 

For example, assume a lessee has a 

1,000-acre pre-EPAct direct use lease 

and was paying an average of $15,000 

per year in royalties. Because royalties 

would exceed the $2,000 in rentals for 

any year ($2x1,000 acres), the lessee 

would owe no rentals. Therefore, the 

lessee’s total lease payments would be 

$15,000. However, if the lessee 

converted to the EPAct’s fee terms, the 

lessee would owe only $750 in fees (a 

95% reduction) and $5,000 in rental 

($5x1,000 acres) for a combined annual 

payment of $5,750. The $5,750 is only 

38 percent of what the lessee was 

paying prior to conversion. Thus, we 

believe a 62-percent decrease in monies 

paid on a lease does encourage the 

direct use of geothermal resources and 

ensures a ‘‘fair return to the United 

States for use of the resource’’ 30 U.S.C. 

1004(b). 

3. 30 CFR 218.305 How do I pay 

advanced royalties I owe under BLM 

regulations? 

The new section 5(f) of the 

Geothermal Steam Act (30 U.S.C. 

1004(f)), added by the EPAct, provides 

that a lease will remain in force 

notwithstanding a cessation of 

production if, during the period in 

which production is ceased, ‘‘the lessee 

pays royalty in advance at the monthly 

average rate at which royalty was paid 

during the period of production.’’ We 

have added language to § 218.305 to 

clarify that you must calculate the 

average monthly royalty by including 

the amount against which you applied 

the annual rental as a credit. Under §

218.303, the annual rental may be 

credited against the advanced royalty 

due, and we have added specific 

language in § 218.303(a)(2) in the final 

rule to effect that result. Thus, both 

royalty and advanced royalty will be 

treated identically for purposes of 

crediting annual rental. 

4. 30 CFR 218.306 May I receive a credit 

against production royalties for in-kind 

deliveries of electricity I provide under 

contract to a State or county 

government? 

This provision implements the new 

30 U.S.C. 1004(d), added by EPAct 

section 224. The maximum credit for 

the value of the electricity provided to 

a State or county government is the 

share of royalty payments that the State 

or county would receive under the 

permanent indefinite appropriation 

established by 30 U.S.C. 1019, as 

amended by EPAct section 224(b). 

Under section 1004(d)(3), the electricity 

delivered will serve as the payment of 

the State’s or county’s share. The 

preamble to the proposed rule gave an 

hypothetical example of the operation of 

this provision as follows: 

For example, assume that you have a 

geothermal lease in New Mexico and that you 

delivered 10,000 megawatt-hours of 

electricity in a month to New Mexico under 

a contract MMS approved. Furthermore, 

assume that the wholesale value of megawatthours in the area where your lease is located 

is $30.00 per megawatt-hour that month. If 

you had paid royalties in money on the basis 

of that wholesale value, and further assuming 

that you have a Class I lease with a 10- 

percent royalty rate, you would have paid 

$30,000 to MMS. The MMS then would have 

paid 50 percent of that amount ($15,000) to 

the State of New Mexico. You would be 

entitled to a credit of $15,000 against the 

amount you would otherwise owe to MMS 

when royalty is calculated on that basis. You 

would have to pay the remaining $15,000 to 

MMS in money. 

71 FR 41523. The last sentence of this 

explanation inadvertently overlooked 

explaining one further consequence of 

this provision, which we explain here 

for purposes of clarity. 

Under 30 U.S.C. 1019, the State in 

which a lease is located receives 50 

percent of the royalties paid to the 

United States, the county receives 25 

percent, and 25 percent is deposited to 

miscellaneous receipts in the Treasury. 

When the lessee delivers the electricity 

in kind and takes the credit against 

royalties of $15,000, the in-kind 

delivery serves as payment of the State’s 

50 percent share under 30 U.S.C. 1019. 

The royalty paid in money therefore is 

divided evenly between the county and 

the Treasury. 

Under the hypothetical as stated, for 

the lessee to claim the $15,000 credit 

against royalties, it would have to 

deliver $15,000 worth of electricity 

(which would equal 500 megawatthours in this example) in kind to New 

Mexico. If it did, instead of realizing 

$300,000 from the sale of all 10,000 

megawatt-hours, the lessee would 

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realize $285,000 from the sale of 9,500 

megawatt-hours and no money for the 

in-kind delivery of the 500 megawatthours. The royalty owed in money 

under this lease, before application of 

the credit, would be $28,500. 

In the hypothetical, the lessee would 

apply the $15,000 credit against 

royalties to the $28,500 it would owe in 

money, and would actually pay $13,500. 

That amount would be distributed 50 

percent to the county and 50 percent to 

the Treasury—in this case, $6,750 to 

each. In contrast, if no electricity had 

been delivered in kind and the lessee 

had paid $30,000 as royalty in money, 

the State of New Mexico would have 

received $15,000, the county in which 

the lease is located would have received 

$7,500, and the Treasury would have 

received the remaining $7,500. Thus, 

use of the in-kind credit results in a 

slight adverse monetary consequence to 

the county and the Federal government. 

This hypothetical illustrates that use of 

the in-kind credit reduces not only the 

royalty paid to the United States as a 

result of the credit but also reduces the 

lessee’s proceeds on which royalty is 

calculated. 

In the final rule, MMS has also made 

several changes from the proposed rule 

to eliminate duplicative language, 

clarify potential ambiguities, and 

express provisions in plainer English. 

None of those changes effects any 

change in substantive meaning. 

III. Procedural Matters 

1. Effective Date 

This rule becomes effective 30 days 

following publication, rather than 60 

days, because the Department and the 

geothermal industry are interested in 

having competitive geothermal lease 

sales as soon as possible. Lease sales 

cannot be held until both the BLM and 

MMS final rules become effective 

because it is these rules that prescribe 

key terms and conditions of new leases. 

The Department intends for both the 

BLM and MMS rules to become effective 

simultaneously. 

2. Summary Cost and Royalty Impact 

Data 

Of the changes to the geothermal 

valuation regulations outlined above, 

only a few will have a royalty impact on 

industry, States, or the Federal 

Government. This section addresses 

those changes and discusses the extent 

of their impacts. There are no ‘‘Costs 

and Benefits,’’ under the meaning 

identified by the Office of Management 

and Budget (OMB), as a result of this 

rule. However, there are certain 

estimated royalty effects of this rule to 

all potentially affected groups: industry, 

States and local governments, and the 

Federal Government. These are 

summarized below. There are no 

significant associated costs to industry 

of administering this rule. The Federal 

government will incur some minimal 

costs associated with systems changes. 

Of the changes that have royalty cost 

impacts, three will result in royalty 

decreases for industry, States, and 

MMS. One will result in an increase to 

the counties with producing Federal 

geothermal leases. The net impact of the 

six changes will result in an expected 

overall royalty revenue decrease of 

$4,101,583 to the Federal Government, 

a corresponding increase to counties of 

$4,071,583, and a decrease of $30,000 in 

royalties to the States. 

We have evaluated potential effects 

on federally recognized Indian tribes 

and have determined that the changes in 

this rule for Federal leases would not 

apply to and currently would not have 

an impact on Indian leases. In addition, 

this rule does not have tribal 

implications that impose substantial 

direct compliance costs on Indian tribal 

governments. 

A. Industry 

(1) Royalty Impacts 

(a) No Change in Royalties—Electrical 

Generation 

Because the EPAct mandates that the 

level of royalty revenues received by 

MMS should be the same over a 10-year 

period as what would have been 

received under the valuation methods of 

the existing regulations, there are no 

significant overall revenue impacts for 

electrical generation projects. Electrical 

generation lessees that remain under the 

existing regulations will pay royalties 

on the same basis as they did before this 

final rule. And, while electrical 

generation lessees that modify their 

leases to the new regulations will 

change to the percentage of gross 

proceeds method, the level of royalties 

they pay will not differ significantly 

from the royalties paid under the 

existing regulations. New lessees’ 

royalty rates are determined by BLM, 

which may cause some difference in 

royalty payments by individual lessees, 

but which should result in the same 

overall level of royalties for 10 years 

under this final rule as they would have 

paid under the existing regulations. 

(b) Net Decrease in Royalties—Direct 

Use—Estimated at $60,000 

Current direct use lessees who do not 

sell the geothermal resources have the 

option to convert their leases to the new 

fee schedule, which MMS anticipates 

will result in a reduction of $60,000 per 

year from the current level of royalties, 

a 95-percent reduction. In addition, all 

new direct use lessees who do not sell 

the geothermal resources under the new 

regulations use the same fee schedule, 

also paying about 95 percent less than 

they would have under the existing 

regulations. 

(2) Administrative Costs 

The MMS has determined that there 

are no significant expected 

administrative cost changes. 

B. State and Local Governments 

(1) Royalty Impacts—State Governments 

(a) Net Decrease in Royalties—Direct 

Use—Estimated at $30,000 

The MMS estimates that States 

impacted by this rule will receive the 

same royalties as they currently receive 

for electrical generation leases without 

significant variation. However, because 

of the 95-percent decrease in revenue 

collected from direct use leases, States 

that receive a share of that revenue 

under 30 U.S.C. 191 will be impacted by 

the revenue decrease. It is unknown 

how this will affect the counties because 

the States distribute royalty revenues to 

their counties directly without MMS 

involvement. The new fee schedule will 

result in approximately a 95-percent 

reduction in royalties paid to States 

from direct use projects. The MMS 

estimates the reduction to be $30,000 

per year. This amount is based on the 

difference between the average of direct 

use royalties paid for fiscal years 2001 

through 2005 and the revenues to be 

collected using the new fee schedule. 

(2) Administrative Costs—State 

Governments 

The MMS has determined that there 

are no expected administrative cost 

changes for State governments. 

(3) Royalty Impacts—Local 

Governments 

(a) Net Increase in Royalties—Estimated 

at $4,071,583 

The EPAct (30 U.S.C. 1019, as 

amended by section 224(b) of the EPAct) 

mandates a new distribution of 25 

percent of royalties, rentals, bonuses, 

and other revenues to the counties. This 

25 percent cuts the Federal share in half 

from 50 percent to 25 percent and leaves 

the States’ share as 50 percent. The 

counties will receive a new 25-percent 

distribution of total geothermal royalty 

revenue under the EPAct, which 

increases their revenues by an estimated 

$4,071,583 per year (25 percent of the 

average total geothermal royalties of 

$16,286,334 paid for fiscal years 2001 

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through 2005) from the Federal 

Government. 

Prior to the EPAct, MMS distributed 

50 percent of the geothermal royalties to 

the States and retained 50 percent for 

the Federal Government. The EPAct 

now mandates that MMS directly 

distribute 25 percent of geothermal 

royalties to the counties that contain 

producing geothermal Federal leases. 

This 25-percent county share is taken 

from the Federal share, cutting it in half, 

to 25 percent of the total geothermal 

royalties. The State distribution of 50 

percent remains unchanged under the 

EPAct. 

(4) Administrative Costs—Local 

Governments 

This rule does not impose any 

additional burden on local governments. 

The counties where geothermal facilities 

are located on Federal leases will 

receive a new distribution of 25 percent 

of the total geothermal royalties for the 

first time directly from the Federal 

Government, whereas in the past it was 

left up to the States to distribute 

geothermal royalty revenues to the 

counties should the respective States 

choose to do so. It is not known exactly 

how much geothermal royalty revenue 

is distributed to counties by the States, 

as it is up to each State to do this 

distribution and is not currently under 

MMS control. 

C. Federal Government 

The total combined estimated royalty 

impact on the Federal Government will 

be a decrease of $4,101,583 ($4,071,583 

(25 percent of the average total 

geothermal royalties of $16,286,334 paid 

for fiscal years 2001 through 2005) for 

electrical generation and $30,000 for 

direct use). 

(1) Royalty Impacts 

(a) Net Decrease in Royalties—Electrical 

Generation—Estimated at $4,071,583 

The Federal Government will be 

impacted by a net overall decrease in 

royalties as a result of the changes to the 

regulations governing the new 

distribution of 25 percent of total 

royalties to the counties and the new 

direct use fee schedule. The net impact 

on the Federal Government will be a 

decrease of approximately $4,071,583 

for electrical generation. 

(b) Net Decrease in Royalties—Direct 

Use—Estimated at $30,000 

The Federal Government will also be 

impacted by the 95-percent decrease in 

revenues from direct use leases due to 

the direct use fee schedule. The MMS 

estimates the reduction to be $30,000 

per year. This amount is based on the 

difference between the average of direct 

use royalties paid for fiscal years 2001 

through 2005 and the revenues to be 

collected using the new fee schedule. 

(2) Administrative Costs—Federal 

Government 

The MMS does not expect any 

administrative cost changes for the 

Federal Government. 

D. Summary of Costs and Royalty 

Impacts to Industry, State and Local 

Governments, and the Federal 

Government 

In the table below, a negative number 

means a reduction in payment or receipt 

of royalties or a reduction in costs. A 

positive number means an increase in 

payment or receipt of royalties or an 

increase in costs. The net expected 

change in royalty impact is the sum of 

the royalty increases and decreases. If 

no costs are represented for 

administrative or royalty impacts, then 

the increase, decrease, and net values 

impacts are all zero. 

SUMMARY OF EXPECTED COSTS AND ROYALTY IMPACTS

Description 

Costs and royalty increases or 

royalty decreases 

First year Subsequent 

years 

A. Industry 

Royalty Decrease from Direct Use Fee Schedule .................................................................................................. -$60,000 -60,000 

Net Expected Change in Royalty (direct use fee) Payments from Industry ........................................................... -60,000 -60,000 

B. State and Local Governments 

State: 

Royalty Decrease to State Governments ......................................................................................................... -30,000 -30,000 

Local Governments (counties): 

Royalty Increase to counties ............................................................................................................................ +4,071,583 +4,071,583 

Net Expected Change in Royalty Payments to State and Local Governments ..................................................... +4,041,583 +4,041,583 

C. Federal Government 

Royalty Decrease from 25 percent Royalty Disbursement to Counties ................................................................. -4,071,583 -4,071,583 

Royalty Decrease from New Direct Use Fee Schedule Implementation ................................................................ -30,000 -30,000 

Net Expected Change in Royalty Payments to Federal Government .................................................................... -4,101,583 -4,101,583 

3. Regulatory Planning and Review, 

Executive Order 12866 

In accordance with Executive Order 

12866, the OMB has determined that 

this rule is not a significant regulatory 

action. 

a. This rule will not have an annual 

effect of $100 million or adversely affect 

an economic sector, productivity, jobs, 

the environment, or other units of 

Government. 

b. This rule will not create 

inconsistencies with other agencies’ 

actions. 

c. This rule will not materially affect 

entitlements, grants, user fees, loan 

programs, or the rights and obligations 

of their recipients. 

d. This rule will not raise novel legal 

or policy issues. 

4. Regulatory Flexibility Act 

The Department of the Interior 

certifies that this rule will not have a 

significant economic effect on a 

substantial number of small entities as 

defined under the Regulatory Flexibility 

Act (5 U.S.C. 601 et seq.). An initial 

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Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 24457 

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 Fairness Act (SBREFA) 

This rule is not a major rule under 5 

U.S.C. 804(2), the Small Business 

Regulatory Enforcement Fairness Act. 

This rule: 

a. Does not have an annual effect on 

the economy of $100 million or more. 

b. Will not cause a major increase in 

costs or prices for consumers, 

individual industries, Federal, State, or 

local government agencies, or 

geographic regions. 

c. Does not have significant adverse 

effects on competition, employment, 

investment, productivity, innovation, or 

the ability of U.S.-based enterprises to 

compete with foreign-based enterprises. 

6. Unfunded Mandates Reform Act 

In accordance with the Unfunded 

Mandates Reform Act (2 U.S.C. 1501 et 

seq.): 

a. This rule will not ‘‘significantly or 

uniquely’’ affect small governments. 

Therefore, a Small Government Agency 

Plan is not required. 

b. This rule will not produce a 

Federal mandate of $100 million or 

greater in any year, i.e., it will not be a 

‘‘significant regulatory action’’ under 

the Unfunded Mandates Reform Act. 

The analysis prepared for Executive 

Order 12866 and found earlier in this 

preamble explains that the economic 

impact of this rule will be well below 

$100 million per year. 

7. Governmental Actions and 

Interference With Constitutionally 

Protected Property Rights (Takings), 

Executive Order 12630 

In accordance with Executive Order 

12630, this rule does not have 

significant takings implications. A 

takings implication assessment is not 

required. 

8. Federalism, Executive Order 13132 

In accordance with Executive Order 

13132, this rule does not have 

federalism implications; hence, a 

federalism assessment is not required. It 

will not substantially and directly affect 

the relationship between the Federal 

and State governments. The 

management of Federal leases is the 

responsibility of the Secretary of the 

Interior. Royalties collected from 

Federal geothermal leases are shared 

with State and county governments on 

a percentage basis as prescribed by law. 

This rule does not alter any lease 

management responsibilities. It pertains 

to royalty and fees computation only. 

This rule will not impose costs on States 

or localities. 

9. Civil Justice Reform, Executive Order 

12988 

In accordance with Executive Order 

12988, the Office of the Solicitor has 

determined that this rule will not 

unduly burden the judicial system and 

meets the requirements of sections 3(a) 

and 3(b)(2) of the Order. 

10. Paperwork Reduction Act of 1995 

(PRA) 

The OMB has approved a new 

collection of information contained in 

this rule. The title of the new 

information collection request (ICR) is 

‘‘30 CFR Parts 202, 206, 210, 217, and 

218—Valuation of Geothermal 

Resources.’’ The total hour burden is 

174 hours, which is approved under 

OMB Control Number 1010–0169 

(expires August 31, 2009). The 

information is collected on Form MMS– 

2014, Report of Sales and Royalty 

Remittance, which is approved under 

OMB Control Number 1010–0140 

(expires November 30, 2009). 

We received comments from industry 

on the rule, but there were no changes 

in the information collection from the 

proposed rule to the final rule. We will 

use the information collected to ensure 

that proper royalty is paid on all 

geothermal resources produced from 

Federal leases. 

Submit written comments on the 

accuracy of this burden estimate or 

suggestions on reducing the burden to 

Sharron L. Gebhardt, Lead Regulatory 

Specialist, Minerals Management 

Service, Minerals Revenue Management, 

P.O. Box 25165, MS 302B2, Denver, 

Colorado 80225. If you use an overnight 

courier service, our courier address is 

Building 85, Room A–614, Denver 

Federal Center, W. 6th Ave. and Kipling 

Blvd., Denver, Colorado 80225. You 

may also e-mail your comments to us at 

mrm.comments@mms.gov. Include the 

title of the information collection and 

the OMB control number in the 

‘‘Attention’’ line of your comment. Also 

include your name and return address. 

If you do not receive a confirmation that 

we have received your e-mail, contact 

Sharron Gebhardt at (303) 231–3211. An 

agency may not conduct or sponsor, and 

a person is not required to respond to, 

a collection of information unless it 

displays a currently valid OMB control 

number. 

11. National Environmental Policy Act 

(NEPA) 

This rule deals with financial matters 

and will have no direct effect on MMS 

decisions on environmental activities. 

Pursuant to 516 DM 2.3A (2), Section 

1.10 of 516 DM 2, Appendix 1, excludes 

from documentation in an 

environmental assessment or impact 

statement ‘‘policies, directives, 

regulations and guidelines of an 

administrative, financial, legal, 

technical or procedural nature; or the 

environmental effects of which are too 

broad, speculative, or conjectural to 

lend themselves to meaningful analysis 

and will be subject later to the NEPA 

process, either collectively or case-bycase.’’ Section 1.3 of the same appendix 

clarifies that royalties and audits are 

considered to be routine financial 

transactions that are subject to 

categorical exclusion from the NEPA 

process. No exception to the categorical 

exclusion applies. 

12. Government-to-Government 

Relationship With Tribes 

In accordance with the President’s 

memorandum of April 29, 1994, 

‘‘Government-to-Government Relations 

with Native American Tribal 

Governments’’ (59 FR 22951) and 

Department Manual 512 DM 2, we have 

evaluated potential effects on federally 

recognized Indian tribes. This rule does 

not apply to Indian leases. 

13. Effects on the Nation’s Energy 

Supply, Executive Order 13211 

In accordance with Executive Order 

13211, this regulation does not have a 

significant adverse effect on the Nation’s 

energy supply, distribution, or use. The 

changes primarily involve royalty 

valuation of geothermal production to 

simplify royalty valuation, hence, any 

impact to the way industry does 

business should be positive, and, as the 

EPAct directs, should encourage energy 

development and marketing. This rule 

does not otherwise impact energy 

supply, distribution, or use. 

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24458 Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 

14. Consultation and Coordination With 

Indian Tribal Governments, Executive 

Order 13175 

In accordance with Executive Order 

13175, we have evaluated this rule and 

determined that it has no potential 

effects on federally recognized Indian 

tribes. This rule does not have tribal 

implications that impose substantial 

direct compliance costs on Indian tribal 

governments. 

List of Subjects in 30 CFR Parts 202, 

206, 210, 217, and 218 

Geothermal, valuation, royalty, 

Energy Policy Act of 2005, direct use, 

arm’s length. 

Dated: April 19, 2007. 

Mike Olsen, 

Deputy Assistant Secretary for Land and 

Minerals Management. 

■ For the reasons stated in the preamble, 

the Minerals Management Service is 

amending 30 CFR parts 202, 206, 210, 

217, and 218 as set forth below: 

PART 202—ROYALTIES 

■ 1. The authority for part 202 

continues to read as follows: 

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. 

Subpart H-Geothermal Resources 

■ 2. Revise § 202.351 to read as follows: 

§ 202.351 Royalties on geothermal 

resources. 

(a)(1) Royalties on geothermal 

resources, including byproducts, or on 

electricity produced using geothermal 

resources, will be at the royalty rate(s) 

specified in the lease, unless the 

Secretary of the Interior temporarily 

waives, suspends, or reduces that 

rate(s). Royalties are determined under 

30 CFR part 206, subpart H. 

(2) Fees in lieu of royalties on 

geothermal resources are prescribed in 

30 CFR part 206, subpart H. 

(3) Except for the amount credited 

against royalties for in-kind deliveries of 

electricity to a State or county under §

218.306, you must pay royalties and 

direct use fees in money. 

(b)(1) Except as specified in paragraph 

(b)(2) of this section, royalties or fees are 

due on— 

(i) All geothermal resources produced 

from a lease and that are sold or used 

by the lessee or are reasonably 

susceptible to sale or use by the lessee, 

or 

(ii) All proceeds derived from the sale 

of electricity produced using geothermal 

resources produced from a lease. 

(2) For purposes of this subparagraph, 

the terms ‘‘Class I lease,’’ ‘‘Class II 

lease,’’ and ‘‘Class III lease’’ have the 

same meanings prescribed in 30 CFR 

206.351. 

(i) For Class I leases, MMS will allow 

free of royalty— 

(A) Geothermal resources that are 

unavoidably lost or reinjected before use 

on or off the lease, as determined by the 

Bureau of Land Management (BLM), or 

that are reasonably necessary to generate 

plant parasitic electricity or electricity 

for Federal lease operations; and 

(B) A reasonable amount of 

commercially demineralized water 

necessary for power plant operations or 

otherwise used on or for the benefit of 

the lease. 

(ii) For Class II and Class III leases 

where the lessee uses geothermal 

resources for commercial production or 

generation of electricity, or where 

geothermal resources are sold at arm’s 

length for the commercial production or 

generation of electricity, MMS will 

allow free of royalty or direct use fees 

geothermal resources that are: 

(A) Unavoidably lost or reinjected 

before use on or off the lease, as 

determined by BLM; 

(B) Reasonably necessary for the 

lessee to generate plant parasitic 

electricity or electricity for Federal lease 

operations, as approved by BLM; or 

(C) Otherwise used for Federal lease 

operations related to commercial 

production or generation of electricity, 

as approved by BLM. 

(iii) For Class II and Class III leases 

where the lessee uses the geothermal 

resources for a direct use or in a direct 

use facility, as defined in 30 CFR 

206.351, resources that are used to 

generate electricity for Federal lease 

operations or that are otherwise used for 

Federal lease operations are subject to 

direct use fees, except for geothermal 

resources that are unavoidably lost or 

reinjected before use on or off the lease, 

as determined by BLM. 

(3) Royalties on byproducts are due at 

the time the recovered byproduct is 

used, sold, or otherwise finally disposed 

of. Byproducts produced and added to 

stockpiles or inventory do not require 

payment of royalty until the byproducts 

are sold, utilized, or otherwise finally 

disposed of. The MMS may ask BLM to 

increase the lease bond to protect the 

lessor’s interest when BLM determines 

that stockpiles or inventories become 

excessive. 

(c) If BLM determines that geothermal 

resources (including byproducts) were 

avoidably lost or wasted from the lease, 

or that geothermal resources (including 

byproducts) were drained from the lease 

for which compensatory royalty (or 

compensatory fees in lieu of 

compensatory royalty) are due, the 

value of those geothermal resources, or 

the royalty or fees owed, will be 

determined under 30 CFR part 206, 

subpart H. 

(d) If a lessee receives insurance or 

other compensation for unavoidably lost 

geothermal resources (including 

byproducts), royalties at the rates 

specified in the lease (or fees in lieu of 

royalties) are due on the amount of, or 

as a result of, that compensation. This 

paragraph will not apply to 

compensation through self-insurance. 

■ 3. Revise § 202.353 to read as follows: 

§ 202.353 Measurement standards for 

reporting and paying royalties and direct 

use fees. 

(a) For geothermal resources used to 

generate electricity, you must report the 

quantity on which royalty is due on 

Form MMS–2014 (Report of Sales and 

Royalty Remittance) as follows: 

(1) For geothermal resources for 

which royalty is calculated under §

206.352(a), you must report quantities 

in: 

(i) Thousands of pounds to the nearest 

whole thousand pounds if the contract 

for the geothermal resources specifies 

delivery in terms of weight; or 

(ii) Millions of Btu to the nearest 

whole million Btu if the sales contract 

for the geothermal resources specifies 

delivery in terms of heat or thermal 

energy. 

(2) For geothermal resources for 

which royalty is calculated under §

206.352(b), you must report the 

quantities in kilowatt-hours to the 

nearest whole kilowatt-hour. 

(b) For geothermal resources used in 

direct use processes, you must report 

the quantity on which a royalty or direct 

use fee is due on Form MMS–2014 in: 

(1) Millions of Btu to the nearest 

whole million Btu if valuation is in 

terms of heat or thermal energy used or 

displaced; 

(2) Millions of gallons to the nearest 

million gallons of geothermal fluid 

produced if valuation or fee calculation 

is in terms of volume; 

(3) Millions of pounds to the nearest 

million pounds of geothermal fluid 

produced if valuation or fee calculation 

is in terms of mass; or 

(4) Any other measurement unit MMS 

approves for valuation and reporting 

purposes. 

(c) For byproducts, you must report 

the quantity on which royalty is due on 

Form MMS–2014 consistent with MMSestablished reporting standards. 

(d) For commercially demineralized 

water, you must report the quantity on 

which royalty is due on Form MMS– 

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Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 24459 

2014 in hundreds of gallons to the 

nearest hundred gallons. 

(e) You need not report the quality of 

geothermal resources, including 

byproducts, to MMS. However, you 

must maintain quality measurements for 

audit purposes. Quality measurements 

include, but are not limited to: 

(1) Temperatures and chemical 

analyses for fluid geothermal resources; 

and 

(2) Chemical analyses, weight percent, 

or other purity measurements for 

byproducts. 

PART 206—PRODUCT VALUATION 

■ 4. The authority for part 206 

continues to read as follows: 

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. 

■ 5. Revise subpart H to read as follows: 

Subpart H—Geothermal Resources 

Sec. 

206.350 What is the purpose of this subpart? 

206.351 What definitions apply to this 

subpart? 

206.352 How do I calculate the royalty due 

on geothermal resources used for 

commercial production or generation of 

electricity? 

206.353 How do I determine transmission 

deductions? 

206.354 How do I determine generating 

deductions? 

206.355 How do I calculate royalty due on 

geothermal resources I sell at arm’s 

length to a purchaser for direct use? 

206.356 How do I calculate royalty due on 

geothermal resources I use for direct use 

purposes? 

206.357 How do I calculate royalty due on 

byproducts? 

206.358 What are byproduct transportation 

allowances? 

206.359 How do I determine byproduct 

transportation allowances? 

206.360 What records must I keep to support 

my calculations of royalty or fees under 

this subpart? 

206.361 How will MMS determine whether 

my royalty or direct use fee payments are 

correct? 

206.362 What are my responsibilities to place 

production into marketable condition 

and to market production? 

206.363 When is an MMS audit, review, 

reconciliation, monitoring, or other like 

process considered final? 

206.364 How do I request a value or gross 

proceeds determination? 

206.365 Does MMS protect information I 

provide? 

206.366 What is the nominal fee that a State, 

tribal, or local government lessee must 

pay for the use of geothermal resources? 

Subpart H—Geothermal Resources 

§ 206.350 What is the purpose of this 

subpart? 

(a) This subpart applies to all 

geothermal resources produced from 

Federal geothermal leases issued 

pursuant to the Geothermal Steam Act 

of 1970 (GSA), as amended by the 

Energy Policy Act of 2005 (EPAct) (30 

U.S.C. 1001 et seq.). The purpose of this 

subpart is to prescribe how to calculate 

royalties and direct use fees for 

geothermal production. 

(b) The MMS may audit and adjust all 

royalty and fee payments. 

(c) In some cases, the regulations in 

this subpart may be inconsistent with a 

statute, settlement agreement, written 

agreement, or lease provision. If this 

happens, the statute, settlement 

agreement, written agreement, or lease 

provision will govern to the extent of 

the inconsistency. For purposes of this 

paragraph, the following definitions 

apply: 

(1) ‘‘Settlement agreement’’ means a 

settlement agreement between the 

United States and a lessee resulting 

from administrative or judicial 

litigation. 

(2) ‘‘Written agreement’’ means a 

written agreement between the lessee 

and the MMS Director or Assistant 

Secretary, Land and Minerals 

Management of the Department of the 

Interior that: 

(i) Establishes a method to determine 

the royalty from any lease that MMS 

expects at least would approximate the 

value or royalty established under this 

subpart; and 

(ii) Includes a value or gross proceeds 

determination under § 206.364 of this 

subpart. 

§ 206.351 What definitions apply to this 

subpart? 

For purposes of this subpart, the 

following terms have the meanings 

indicated. 

Affiliate means a person who 

controls, is controlled by, or is under 

common control with another person. 

For purposes of this subpart: 

(1) Ownership or common ownership 

of more than 50 percent of the voting 

securities, or instruments of ownership, 

or other forms of ownership, of another 

person constitutes control. Ownership 

of less than 10 percent constitutes a 

presumption of noncontrol that MMS 

may rebut. 

(2) If there is ownership or common 

ownership of 10 through 50 percent of 

the voting securities, or instruments of 

ownership, or other forms of ownership 

of another person, MMS will consider 

the following factors in determining 

whether there is control under the 

circumstances of a particular case: 

(i) The extent to which there are 

common officers or directors; 

(ii) With respect to the voting 

securities, or instruments of ownership, 

or other forms of ownership: the 

percentage of ownership or common 

ownership, the relative percentage of 

ownership or common ownership 

compared to the percentage(s) of 

ownership by other persons, whether a 

person is the greatest single owner, or 

whether there is an opposing voting 

bloc of greater ownership; 

(iii) Operation of a lease, plant, 

pipeline, or other facility; 

(iv) The extent of participation by 

other owners in operations and day-today management of a lease, plant, 

pipeline, or other facility; and 

(v) Other evidence of power to 

exercise control over or common control 

with another person. 

(3) Regardless of any percentage of 

ownership or common ownership, 

relatives, either by blood or marriage, 

are affiliates. 

Allowance means a deduction in 

determining value for royalty purposes. 

Arm’s-length contract means a 

contract or agreement between 

independent persons who are not 

affiliates and who have opposing 

economic interests regarding that 

contract. To be considered arm’s length 

for any production month, a contract 

must satisfy this definition for that 

month, as well as when the contract was 

executed. 

Audit means a review, conducted in 

accordance with generally accepted 

accounting and auditing standards, of 

royalty or fee payment compliance 

activities of lessees or other interest 

holders who pay royalties, fees, rents, or 

bonuses on Federal geothermal leases. 

Byproducts means minerals (exclusive 

of oil, hydrocarbon gas, and helium), 

found in solution or in association with 

geothermal steam, that no person would 

extract and produce by themselves 

because they are worth less than 75 

percent of the value of the geothermal 

steam or because extraction and 

production would be too difficult. 

Byproduct recovery facility means a 

facility where byproducts are placed in 

marketable condition. 

Byproduct transportation allowance 

means an allowance for the reasonable, 

actual costs of moving byproducts to a 

point of sale or delivery off the lease, 

unit area, or communitized area, or 

away from a byproduct recovery facility. 

The byproduct transportation allowance 

does not include gathering costs. You 

must report a byproduct transportation 

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24460 Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 

allowance as a separate discrete field on 

the Form MMS–2014. 

Class I lease means: 

(1) A lease that BLM issued before 

August 8, 2005, for which the lessee has 

not converted the royalty rate terms 

under 43 CFR 3212.25; or 

(2) A lease that BLM issued in 

response to an application that was 

pending on August 8, 2005, for which 

the lessee has not made an election 

under 43 CFR 3200.8(b). 

Class II lease means: 

A lease that BLM issued after August 

8, 2005, except for a lease issued in 

response to an application that was 

pending on August 8, 2005, for which 

the lessee does not make an election 

under 43 CFR 3200.8(b). 

Class III lease means: 

A lease that BLM issued before 

August 8, 2005, for which the lessee has 

converted to the royalty rate or direct 

use fee terms under 43 CFR 3212.25. 

Commercial production or generation 

of electricity means generation of 

electricity that is sold or is subject to 

sale, including the electricity or energy 

that is reasonably required to produce 

the resource used in production of 

electricity for sale or to convert 

geothermal energy into electrical energy 

for sale. 

Contract means any oral or written 

agreement, including amendments or 

revisions thereto, between two or more 

persons and enforceable by law that 

with due consideration creates an 

obligation. 

Deduction means a subtraction the 

lessee uses to determine the value of 

geothermal resources produced from a 

Class I lease that the lessee uses to 

generate electricity. 

Delivered electricity means the 

amount of electricity in kilowatt-hours 

delivered to the purchaser. 

Direct use means the utilization of 

geothermal resources for commercial, 

residential, agricultural, public 

facilities, or other energy needs, other 

than the commercial production or 

generation of electricity. 

Direct use facility means a facility that 

uses the heat or other energy of the 

geothermal resource for direct use 

purposes. 

Electrical facility means a power plant 

or other facility that uses a geothermal 

resource to generate electricity. 

Field means the land surface 

vertically projected over a subsurface 

geothermal reservoir encompassing at 

least the outermost boundaries of all 

geothermal accumulations known to be 

within that reservoir. Geothermal fields 

are usually given names and their 

official boundaries are often designated 

by regulatory agencies in the respective 

States in which the fields are located. 

Gathering means the movement of 

lease production from the wellhead to 

the point of utilization. 

Generating deduction means a 

deduction for the lessee’s reasonable, 

actual costs of generating plant tailgate 

electricity. 

Geothermal resources means: 

(1) All products of geothermal 

processes, including indigenous steam, 

hot water, and hot brines; 

(2) Steam and other gases, hot water, 

and hot brines resulting from water, gas, 

or other fluids artificially introduced 

into geothermal formations; 

(3) Heat or other associated energy 

found in geothermal formations; and 

(4) Any byproducts. 

Gross proceeds (for royalty payment 

purposes) means the total monies and 

other consideration accruing to a 

geothermal lessee for the sale of 

electricity or geothermal resource. Gross 

proceeds includes, but is not limited to: 

(1) Payments to the lessee for certain 

services such as effluent injection, field 

operation and maintenance, drilling or 

workover of wells, or field gathering to 

the extent that the lessee is obligated to 

perform such functions at no cost to the 

Federal Government; 

(2) Reimbursements for production 

taxes and other taxes. Tax 

reimbursements are part of gross 

proceeds accruing to a lessee even 

though the Federal royalty interest may 

be exempt from taxation; and 

(3) Any monies and other 

consideration, including the forms of 

consideration identified in this 

paragraph, to which a lessee is 

contractually or legally entitled but 

which it does not seek to collect through 

reasonable efforts. 

Lease means a geothermal lease 

issued under the authority of the GSA, 

unless the context indicates otherwise. 

Lessee (you) means any person to 

whom the United States issues a 

geothermal lease, and any person who 

has been assigned an obligation to make 

royalty, fee, or other payments required 

by the lease. This includes any person 

who has an interest in a geothermal 

lease as well as an operator or payor 

who has no interest in the lease but who 

has assumed the royalty, fee, or other 

payment responsibility. This also 

includes any affiliate of the lessee that 

uses the geothermal resource to generate 

electricity, in a direct use process, or to 

recover byproducts, or any affiliate that 

sells or transports lease production. 

Marketable condition means lease 

products that are sufficiently free from 

impurities and otherwise in a condition 

that they will be accepted by a 

purchaser under a sales contract typical 

for the disposition from the field or area 

of such lease products. 

Person means any individual, firm, 

corporation, association, partnership, 

consortium, or joint venture (when 

established as a separate entity). 

Plant parasitic electricity means 

electricity used to operate a power plant 

that is used for commercial production 

or generation of electricity. 

Plant tailgate electricity means the 

amount of electricity in kilowatt-hours 

generated by a power plant exclusive of 

plant parasitic electricity, but inclusive 

of any electricity generated by the 

power plant and returned to the lease 

for lease operations. Plant tailgate 

electricity should be measured at, or 

calculated for, the high voltage side of 

the transformer in the plant switchyard. 

Point of utilization means the power 

plant or direct use facility in which the 

geothermal resource is utilized. 

Public purpose means a program 

carried out by a State, tribal, or local 

government for the purpose of providing 

facilities or services for the benefit of 

the public in connection with, but not 

limited to, public health, safety or 

welfare, other than the commercial 

generation of electricity. Use of lands or 

facilities for habitation, cultivation, 

trade or manufacturing is permissible 

only when necessary for and integral to 

(i.e., an essential part of) the public 

purpose. 

Public safety or welfare means a 

program carried out or promoted by a 

public agency for public purposes 

involving, directly or indirectly, 

protection, safety, and law enforcement 

activities, and the criminal justice 

system of a given political area. Public 

safety or welfare may include, but is not 

limited to, programs carried out by: 

(1) Public police departments; 

(2) Sheriffs’ offices; 

(3) The courts; 

(4) Penal and correctional institutions 

(including juvenile facilities); 

(5) State and local civil defense 

organizations; and 

(6) Fire departments and rescue 

squads (including volunteer fire 

departments and rescue squads 

supported in whole or in part with 

public funds). 

Reasonable alternative fuel means a 

conventional fuel (such as coal, oil, gas, 

or wood) that would normally be used 

as a source of heat in direct use 

operations. 

Secretary means the Secretary of the 

Interior or any person duly authorized 

to exercise the powers vested in that 

office. 

Transmission deduction means a 

deduction for the lessee’s reasonable 

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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. 

§ 206.352 How do I calculate the royalty 

due on geothermal resources used for 

commercial production or generation of 

electricity? 

(a) If you sold geothermal resources 

produced from a Class I, II, or III lease 

at arm’s length that the purchaser uses 

to generate electricity, then the royalty 

on the geothermal resources is the gross 

proceeds accruing to you from the sale 

of the geothermal resource to the arm’slength purchaser multiplied by either: 

(1) The royalty rate in your lease; or 

(2) The royalty rate that BLM 

prescribes or calculates under 43 CFR 

3211.17. See § 206.361 for additional 

provisions applicable to determining 

gross proceeds under arm’s-length sales. 

(b) If you use the geothermal resource 

in your own power plant for the 

generation and sale of electricity, the 

following provisions apply 

(1) For Class I leases, you must 

determine the royalty on produced 

geothermal resources in accordance 

with the first applicable of the following 

paragraphs: 

(i) The gross proceeds accruing to you 

from the arm’s-length sale of the 

electricity less applicable deductions 

determined under § 206.353 and §

206.354 of this part, multiplied by the 

royalty rate in your lease. See § 206.361 

for additional provisions applicable to 

determining gross proceeds under 

arm’s-length sales. Under no 

circumstances may the deductions 

reduce the royalty value of the 

geothermal resource to zero; or 

(ii) A royalty determined by any other 

reasonable method approved by MMS 

under § 206.364 of this subpart. 

(2) For Class II and Class III leases, the 

royalty on geothermal resources 

produced is your gross proceeds from 

the sale of electricity multiplied by the 

royalty rate BLM prescribed for your 

lease under 43 CFR 3211.17. See §

206.361 for additional provisions 

applicable to determining gross 

proceeds under arm’s-length sales. You 

may not reduce gross proceeds by any 

deductions. 

§ 206.353 How do I determine 

transmission deductions? 

(a) If you determine the value of your 

geothermal resources under §

206.352(b)(1)(i) of this subpart, you may 

subtract a transmission deduction from 

the gross proceeds you received for the 

sale of electricity to determine the plant 

tailgate value of the electricity. 

(1) The transmission deduction 

consists of either or both of two 

components: 

(i) Transmission line costs as 

determined under paragraph (b) of this 

section; and 

(ii) Wheeling costs if the electricity is 

transmitted across a third party’s 

transmission line under an arm’s-length 

wheeling agreement. 

(2) You may deduct the actual costs 

you (including your affiliate(s)) incur for 

transmitting electricity under your 

arm’s-length wheeling contract. 

(b) To determine your transmission 

line cost, you must follow the 

requirements of paragraphs (b)(1) and 

(b)(2) of this section. 

(1) Your transmission line costs are 

your actual costs associated with the 

construction and operation of a 

transmission line for the purpose of 

transmitting electricity attributable and 

allocable to your power plant utilizing 

Federal geothermal resources. 

(i) You must determine the monthly 

transmission line cost component of the 

transmission deduction by multiplying 

the annual transmission line cost rate 

(in dollars per kilowatt-hour) by the 

amount of electricity delivered for the 

reporting month. 

(ii) You must redetermine the 

transmission line cost rate annually 

either at the beginning of the same 

month of the year in which the power 

plant was placed into service or at a 

time concurrent with the beginning of 

your annual corporate accounting 

period. The period you select must 

coincide with the same period you 

chose for the generating deduction 

under § 206.354(b)(1). After you choose 

a deduction period, you may not later 

elect to use a different deduction period 

without MMS approval. 

(2) Your actual transmission line costs 

during the reporting period include: 

(i) Operating and maintenance 

expenses under paragraphs (d) and (e) of 

this section; 

(ii) Overhead under paragraph (f) of 

this section; and either 

(iii) Depreciation under paragraphs (g) 

and (h) of this section and a return on 

undepreciated capital investment under 

paragraphs (g) and (i) of this section or 

(iv) A return on the capital investment 

in the transmission line under 

paragraphs (g) and (j) of this section. 

(c)(1) Allowable capital costs under 

paragraph (b) of this section are 

generally those for depreciable fixed 

assets (including costs of delivery and 

installation of capital equipment) that 

are an integral part of the transmission 

line. 

(2)(i) You may include a return on 

capital you invested in the purchase of 

real estate for transmission facilities if: 

(A) Such purchase is necessary; and 

(B) The surface is not part of the 

Federal lease. 

(ii) The rate of return will be the same 

rate determined under paragraph (k) of 

this section. 

(d) Allowable operating expenses 

include: 

(1) Operations supervision and 

engineering; 

(2) Operations labor; 

(3) Fuel; 

(4) Utilities; 

(5) Materials; 

(6) Ad valorem property taxes; 

(7) Rent; 

(8) Supplies; and 

(9) Any other directly allocable and 

attributable operating or maintenance 

expense that you can document. 

(e) Allowable maintenance expenses 

include: 

(1) Maintenance of the transmission 

line; 

(2) Maintenance of equipment; 

(3) Maintenance labor; and 

(4) Other directly allocable and 

attributable maintenance expenses that 

you can document. 

(f) Overhead directly attributable and 

allocable to the operation and 

maintenance of the transmission line is 

an allowable expense. State and Federal 

income taxes and severance taxes and 

other fees, including royalties, are not 

allowable expenses. 

(g) To compute costs associated with 

capital investment, a lessee may use 

either depreciation with a return on 

undepreciated capital investment, or a 

return on capital investment in the 

transmission line. After a lessee has 

elected to use either method, the lessee 

may not later elect to change to the 

other alternative without MMS 

approval. 

(h)(1) To compute depreciation, you 

must use a straight-line depreciation 

method based on the life of the 

geothermal project, usually the term of 

the electricity sales contract, or other 

depreciation period acceptable to MMS. 

You may not depreciate equipment 

below a reasonable salvage value. 

(2) A change in ownership of a 

transmission line does not alter the 

depreciation schedule established by 

the original lessee-owner for purposes of 

computing transmission line costs. 

(3) With or without a change in 

ownership, you may depreciate a 

transmission line only once. 

(i) To calculate a return on 

undepreciated capital investment, 

multiply the remaining undepreciated 

capital balance as of the beginning of 

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24462 Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 

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 

multiplied by the industrial rate 

associated with Standard & Poor’s BBB 

rating. The BBB rate must be the 

monthly average rate as published in 

Standard & Poor’s Bond Guide for the 

first month for which the allowance is 

applicable. Redetermine the rate at the 

beginning of each subsequent calendar 

year. 

(l) Calculate the deduction for 

transmission costs based on your cost of 

transmitting electricity through each 

individual transmission line. 

(m)(1) For new transmission facilities 

or arrangements, base your initial 

deduction on estimates of allowable 

electricity transmission costs for the 

applicable period. Use the most recently 

available operations data for the 

transmission line or, if such data are not 

available, use estimates based on data 

for similar transmission lines. 

(2) When actual cost information is 

available, you must amend your prior 

Form MMS–2014 reports to reflect 

actual transmission costs deductions for 

each month for which you reported and 

paid based on estimated transmission 

costs. You must pay any additional 

royalties due (together with interest 

computed under § 218.302). You are 

entitled to a credit for or refund of any 

overpaid royalties. 

(n) In conducting reviews and audits, 

MMS may require you to submit arm’slength transmission contracts, 

production agreements, operating 

agreements, and related documents and 

all other data used to calculate the 

deduction. You must comply with any 

such requirements within the time MMS 

specifies. Recordkeeping requirements 

are found at part 212 of this chapter. 

(o) At the completion of transmission 

line dismantlement and salvage 

operations, you may report a credit for 

or request a refund of royalties in an 

amount equal to the royalty rate times 

the amount by which actual 

transmission line dismantlement costs 

exceed actual income attributable to 

salvage of the transmission line. 

§ 206.354 How do I determine generating 

deductions? 

(a) If you determine the value of your 

geothermal resources under §

206.352(b)(1)(i) of this subpart, you may 

deduct your reasonable actual costs 

incurred to generate electricity from the 

plant tailgate value of the electricity 

(usually the transmission-reduced value 

of the delivered electricity). You may 

deduct the actual costs you incur for 

generating electricity under your arm’slength power plant contract. 

(b)(1) You must base your generating 

costs deduction on your actual annual 

costs associated with the construction 

and operation of a geothermal power 

plant. 

(i) You must determine your monthly 

generating deduction by multiplying the 

annual generating cost rate (in dollars 

per kilowatt-hour) by the amount of 

plant tailgate electricity measured (or 

computed) for the reporting month. The 

generating cost rate is determined from 

the annual amount of your plant tailgate 

electricity. 

(ii) You must redetermine your 

generating cost rate annually either at 

the beginning of the same month of the 

year in which the power plant was 

placed into service or at a time 

concurrent with the beginning of your 

annual corporate accounting period. 

The period you select must coincide 

with the same period chosen for the 

transmission deduction under §

206.353(b)(1). After you choose a 

deduction period, you may not later 

elect to use a different deduction period 

without MMS approval. 

(2) Your generating costs are your 

actual power plant costs during the 

reporting period, including: 

(i) Operating and maintenance 

expenses under paragraphs (d) and (e) of 

this section; 

(ii) Overhead under paragraph (f) of 

this section; and either 

(iii) Depreciation under paragraphs (g) 

and (h) of this section and a return on 

undepreciated capital investment under 

paragraphs (g) and (i) of this section; or 

(iv) A return on capital investment in 

the power plant under paragraphs (g) 

and (j) of this section. 

(c)(1) Allowable capital costs under 

paragraph (b) of this section are 

generally those for depreciable fixed 

assets (including costs of delivery and 

installation of capital equipment) that 

are an integral part of the power plant 

or are required by the design 

specifications of the power conversion 

cycle. 

(2)(i) You may include a return on 

capital you invested in the purchase of 

real estate for a power plant site if: 

(A) The purchase is necessary; and, 

(B) The surface is not part of the 

Federal lease. 

(ii) The rate of return will be the same 

rate determined under paragraph (k) of 

this section. 

(3) You may not deduct the costs of 

gathering systems and other productionrelated facilities. 

(d) Allowable operating expenses 

include: 

(1) Operations supervision and 

engineering; 

(2) Operations labor; 

(3) Auxiliary fuel and/or utilities used 

to operate the power plant during down 

time; 

(4) Utilities; 

(5) Materials; 

(6) Ad valorem property taxes; 

(7) Rent; 

(8) Supplies; and 

(9) Any other directly allocable and 

attributable operating expense. 

(e) Allowable maintenance expenses 

include: 

(1) Maintenance of the power plant; 

(2) Maintenance of equipment; 

(3) Maintenance labor; and 

(4) Other directly allocable and 

attributable maintenance expenses that 

you can document. 

(f) Overhead directly attributable and 

allocable to the operation and 

maintenance of the power plant is an 

allowable expense. State and Federal 

income taxes and severance taxes and 

other fees, including royalties, are not 

allowable expenses. 

(g) To compute costs associated with 

capital investment, a lessee may use 

either depreciation with a return on 

undepreciated capital investment, or a 

return on capital investment in the 

power plant. After a lessee has elected 

to use either method, the lessee may not 

later elect to change to the other 

alternative without MMS approval. 

(h)(1) To compute depreciation, you 

must use a straight-line depreciation 

method based on the life of the 

geothermal project, usually the term of 

the electricity sales contract, or other 

depreciation period acceptable to MMS. 

You may not depreciate equipment 

below a reasonable salvage value. 

(2) A change in ownership of the 

power plant does not alter the 

depreciation schedule established by 

the original lessee-owner for purposes of 

computing generating costs. 

(3) With or without a change in 

ownership, you may depreciate a power 

plant only once. 

(i) To calculate a return on 

undepreciated capital investment, 

multiply the remaining undepreciated 

capital balance as of the beginning of 

the period for which you are calculating 

the generating deduction allowance by 

the rate of return provided in paragraph 

(k) of this section. 

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Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 24463 

(j) To compute a return on capital 

investment in the power plant, multiply 

the allowable capital investment in the 

power plant by the rate of return 

determined pursuant to paragraph (k) of 

this section. There is no allowance for 

depreciation. 

(k) The rate of return must be 2.0 

multiplied by the industrial rate 

associated with Standard & Poor’s BBB 

rating. The BBB rate must be the 

monthly average rate as published in 

Standard & Poor’s Bond Guide for the 

first month for which the allowance is 

applicable. You must redetermine the 

rate at the beginning of each subsequent 

calendar year. 

(l) Calculate the deduction for 

generating costs based on your cost of 

generating electricity through each 

individual power plant. 

(m)(1) For new power plants or 

arrangements, base your initial 

deduction on estimates of allowable 

electricity generation costs for the 

applicable period. Use the most recently 

available operations data for the power 

plant or, if such data are not available, 

use estimates based on data for similar 

power plants. 

(2) When actual cost information is 

available, you must amend your prior 

Form MMS–2014 reports to reflect 

actual generating cost deductions for 

each month for which you reported and 

paid based on estimated generating 

costs. You must pay any additional 

royalties due (together with interest 

computed under § 218.302). You are 

entitled to a credit for or refund of any 

overpaid royalties. 

(n) In conducting reviews and audits, 

MMS may require you to submit arm’slength power plant contracts, 

production agreements, operating 

agreements, related documents and all 

other data used to calculate the 

deduction. You must comply with any 

such requirements within the time MMS 

specifies. Recordkeeping requirements 

are found at part 212 of this chapter. 

(o) At the completion of power plant 

dismantlement and salvage operations, 

you may report a credit for or request a 

refund of royalty in an amount equal to 

the royalty rate times the amount by 

which actual power plant 

dismantlement costs exceed actual 

income attributable to salvage of the 

power plant. 

§ 206.355 How do I calculate royalty due 

on geothermal resources I sell at arm’s 

length to a purchaser for direct use? 

If you sell geothermal resources 

produced from Class I, II, or III leases at 

arm’s length to a purchaser for direct 

use, then the royalty on the geothermal 

resource is the gross proceeds accruing 

to you from the sale of the geothermal 

resource to the arm’s-length purchaser 

multiplied by the royalty rate in your 

lease or that BLM prescribes under 43 

CFR 3211.18. See § 206.361 for 

additional provisions applicable to 

determining gross proceeds under 

arm’s-length sales. 

§ 206.356 How do I calculate royalty or 

fees due on geothermal resources I use for 

direct use purposes? 

If you use the geothermal resource for 

direct use: 

(a) For Class I leases, you must 

determine the royalty due on 

geothermal resources in accordance 

with the first applicable of the following 

three paragraphs. 

(1) The weighted average of the gross 

proceeds established in arm’s-length 

contracts for the purchase of significant 

quantities of geothermal resources to 

operate the lessee’s same direct-use 

facility multiplied by the royalty rate in 

your lease. In evaluating the 

acceptability of arm’s-length contracts, 

the following factors will be considered: 

time of execution, duration, terms, 

volume, quality of resource, and such 

other factors as may be appropriate to 

reflect the value of the resource. 

(2) The equivalent value of the least 

expensive, reasonable alternative energy 

source (fuel) multiplied by the royalty 

rate in your lease. The equivalent value 

of the least expensive, reasonable 

alternative energy source will be based 

on the amount of thermal energy that 

would otherwise be used by the direct 

use facility in place of the geothermal 

resource. That amount of thermal energy 

(in Btu) displaced by the geothermal 

resource will be determined by the 

equation: 

ther

h densi out ty volum

m alenergy displaced = ( ) hin − ×× × 0 113681 . e

efficiency factor

Where hin is the enthalpy in Btu/lb at 

the direct use facility inlet (based on 

measured inlet temperature), hout is the 

enthalpy in Btu/lb at the facility outlet 

(based on measured outlet temperature), 

density is in lbs/cu ft based on inlet 

temperature, the factor 0.113681 (cu ft/ 

gal) converts gallons to cubic feet, and 

volume is the quantity of geothermal 

fluid in gallons produced at the 

wellhead or measured at an approved 

point. The efficiency factor of the 

alternative energy source will be 0.7 for 

coal and 0.8 for oil, natural gas, and 

other fuels derived from oil and natural 

gas, or an efficiency factor proposed by 

the lessee and approved by MMS. The 

methods of measuring resource 

parameters (temperature, volume, etc.) 

and the frequency of computing and 

accumulating the amount of thermal 

energy displaced will be determined 

and approved by BLM under 43 CFR 

3275.13–3275.17. 

(3) A royalty determined by any other 

reasonable method approved by MMS or 

the Assistant Secretary, Land and 

Minerals Management of the 

Department of the Interior, under §

206.364 of this part. 

(b) For geothermal resources 

produced from Class II and Class III 

leases, you must multiply the 

appropriate fee from the schedule in 

subparagraph (b)(1) of this section by 

the number of gallons or pounds you 

produce from the direct use lease each 

month. 

(1) You must use the following fee 

schedule to calculate fees due under 

this section: 

DIRECT USE FEE SCHEDULE

[Hot water] 

If your average monthly inlet temperature ([deg]F) is Your fees are . . . 

At least . . . But less than . 

. . 

($/million gallons) ($/million 

pounds) 

130 ............................................................................................................................................... 140 2.524 0.307 


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24464 Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 

DIRECT USE FEE SCHEDULE—Continued 

[Hot water] 

If your average monthly inlet temperature ([deg]F) is Your fees are . . . 

At least . . . But less than . 

. . 

($/million gallons) ($/million 

pounds) 

140 ............................................................................................................................................... 150 7.549 0.921 

150 ............................................................................................................................................... 160 12.543 1.536 

160 ............................................................................................................................................... 170 17.503 2.150 

170 ............................................................................................................................................... 180 22.426 2.764 

180 ............................................................................................................................................... 190 27.310 3.379 

190 ............................................................................................................................................... 200 32.153 3.993 

200 ............................................................................................................................................... 210 36.955 4.607 

210 ............................................................................................................................................... 220 41.710 5.221 

220 ............................................................................................................................................... 230 46.417 5.836 

230 ............................................................................................................................................... 240 51.075 6.450 

240 ............................................................................................................................................... 250 55.682 7.064 

250 ............................................................................................................................................... 260 60.236 7.679 

260 ............................................................................................................................................... 270 64.736 8.293 

270 ............................................................................................................................................... 280 69.176 8.907 

280 ............................................................................................................................................... 290 73.558 9.521 

290 ............................................................................................................................................... 300 77.876 10.136 

300 ............................................................................................................................................... 310 82.133 10.750 

310 ............................................................................................................................................... 320 86.328 11.364 

320 ............................................................................................................................................... 330 90.445 11.979 

330 ............................................................................................................................................... 340 94.501 12.593 

340 ............................................................................................................................................... 350 98.481 13.207 

350 ............................................................................................................................................... 360 102.387 13.821 

(i) For direct use geothermal resources 

with an average monthly inlet 

temperature of 130 [deg]F or less, you 

must pay only the lease rental. 

(ii) The MMS, in consultation with 

BLM, will develop and publish a 

revised fee schedule in the Federal 

Register, as needed. 

(iii) The MMS, in consultation with 

BLM, will calculate revised fees 

schedules using the following formulas: 

Forreporting on a volum e basis:R TT P F v i =× − ρ ( ) n out pr × × bc rr ×

= − ( ) × ×

1

e

Forreporting on a m ass basis:R TT P F m in out prbc rr ×

1

e

Where: 

RV = Royalty due as a function of produced 

volume in the fee schedule, expressed as 

dollars per million (106) gallons; 

Rm = Royalty due as a function of produced 

mass in the fee schedule, expressed as 

dollars per million (106) pounds; 

[rho][rho] = Water density at inlet 

temperature expressed as lbs per gallon; 

Tin = Measured inlet temperature in [deg]F 

(as required by BLM under 43 CFR part 

3275); 

Tout = Established assumed outlet 

temperature of 130[deg] F; 

e = Boiler Efficiency Factor for coal of 70 

percent; 

Pprbc = The 3-year historical average of 

Powder River Basin spot coal prices, as 

published by the Energy Information 

Administration, or other recognized 

authoritative reference source of coal 

prices, in dollars (per MMBtu); 

Frr = The assumed Lease Royalty Rate of 10 

percent. 

(2) The fee that you report is subject 

to monitoring, review, and audit. 

(3) The schedule of fees established 

under this paragraph will apply to any 

Class III lease with respect to any 

royalty payments previously made 

when the lease was a Class I lease that 

were due and owing, and were paid, on 

or after July 16, 2003. To use this 

provision, you must provide MMS data 

showing the amount of geothermal 

production in pounds or gallons of 

geothermal fluid to input into the fee 

schedule (see 43 CFR part 3276). 

(i) If the royalties you previously paid 

are less than the fees due under this 

section, you must pay the difference 

plus interest on that difference 

computed under § 218.302. 

(ii) If the royalties you previously 

paid are more than the fees due under 

this section, then you are entitled to a 

refund or credit from MMS of 50 

percent of the overpaid royalties. You 

are also entitled to a refund or credit of 

any interest that you paid on the 

overpaid royalties. 

(c) For geothermal resources other 

than hot water, MMS will determine 

fees on a case-by-case basis. 

§ 206.357 How do I calculate royalty due 

on byproducts? 

(a) If you sell byproducts, you must 

determine the royalty due on the 

byproducts that are royalty-bearing 

under: 

(1) Applicable lease terms of Class I 

leases and of Class III leases that do not 

elect to be subject to all of the BLM 

regulations promulgated for leases 

issued after August 8, 2005, under 43 

CFR 3200.7(a)(2), or 

(2) Applicable statutory provisions at 

30 U.S.C. 1004(a)(2) for Class II leases 

and for Class III leases that do elect to 

be subject to all of the BLM regulations 

promulgated for leases issued after 

August 8, 2005, under 43 CFR 

3200.7(a)(2). 

(b) You must determine the royalty 

due on the byproducts by multiplying 

the royalty rate in your lease or that 

BLM prescribes under 43 CFR 3211.19 

by a value of the byproducts determined 

in accordance with the first applicable 

of the following subparagraphs: 


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Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 24465 

(1) The gross proceeds accruing to you 

from the arm’s-length sale of the 

byproducts, less any applicable 

byproduct transportation allowances 

determined under § § 206.358 and 

206.359. See § 206.361 for additional 

provisions applicable to determining 

gross proceeds; 

(2) Other relevant matters including, 

but not limited to, published or publicly 

available spot-market prices, or 

information submitted by the lessee 

concerning circumstances unique to a 

particular lease operation or the 

saleability of certain byproducts; or 

(3) Any other reasonable valuation 

method approved by MMS. 

§ 206.358 What are byproduct 

transportation allowances? 

(a) When you determine the value of 

byproducts at a point off the geothermal 

lease, unit, or participating area, you are 

allowed a deduction in determining 

value, for royalty purposes, for your 

reasonable, actual costs incurred to: 

(1) Transport the byproducts from a 

Federal lease, unit, or participating area 

to a sales point or point of delivery that 

is off the lease, unit, or participating 

area; or 

(2) Transport the byproducts from a 

Federal lease, unit, or participating area, 

or from a geothermal use facility to a 

byproduct recovery facility when that 

byproduct recovery facility is off the 

lease, unit, or participating area and, if 

applicable, from the recovery facility to 

a sales point or point of delivery off the 

lease, unit, or participating area. 

(b) Costs for transporting geothermal 

fluids from the lease to the geothermal 

use facility, whether on or off the lease, 

are not includible in the byproduct 

transportation allowance. 

(c)(1) When you transport byproducts 

from a lease, unit, participating area, or 

geothermal use facility to a byproduct 

recovery facility, you are not required to 

allocate transportation costs between 

the quantity of marketable byproducts 

and the rejected waste material. The 

byproduct transportation allowance is 

authorized for the total production that 

is transported. You must express 

byproduct transportation allowances as 

a cost per unit of marketable byproducts 

transported. 

(2) For byproducts that are extracted 

on the lease, unit, participating area, or 

at the geothermal use facility, the 

byproduct transportation allowance is 

authorized for the total byproduct that 

is transported to a point of sale off the 

lease, unit, or participating area. You 

must express byproduct transportation 

allowances as a cost per unit of 

byproduct transported. 

(3) You may deduct transportation 

costs only when you sell, deliver, or 

otherwise utilize the transported 

byproduct and report and pay royalties 

on the byproduct. 

(d) Reporting requirements. (1) You 

must use a discrete field on Form MMS– 

2014 to notify MMS of a transportation 

allowance. 

(2) In conducting reviews and audits, 

MMS may require you to submit arm’slength transportation contracts, 

production agreements, operating 

agreements, and related documents. You 

must comply with any such 

requirements within the time MMS 

specifies. Recordkeeping requirements 

are found at part 212 of this chapter. 

(e) Byproduct transportation 

allowances are subject to monitoring, 

review, and audit. If, after a review or 

audit, MMS determines that you have 

improperly determined a byproduct 

transportation allowance, you must pay 

any additional royalties due (plus 

interest computed under § 218.302). 

You are entitled to a credit for or refund 

of any overpaid royalties. 

(f) If you commingled byproducts 

produced from Federal and non-Federal 

leases for transportation, you may not 

disproportionately allocate 

transportation costs to Federal lease 

production. 

§ 206.359 How do I determine byproduct 

transportation allowances? 

(a) For transportation costs you incur 

under an arm’s-length contract, the 

transportation allowance will be the 

reasonable, actual costs you incurred for 

transporting the byproducts under that 

contract. 

(1) In conducting reviews and audits, 

MMS will examine whether the contract 

reflects more than the consideration 

actually transferred either directly or 

indirectly from you to the transporter 

for the transportation. If the contract 

reflects more than the total 

consideration you paid, MMS may 

require you to determine the byproduct 

transportation allowance under 

paragraph (b) of this section. 

(2) If MMS determines that the 

consideration you paid under an arm’slength 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 dollarsper-unit basis, you must convert 

whatever consideration you paid to a 

dollar value equivalent for the purposes 

of this section. 

(b) If you transport the byproduct 

yourself or under a non-arm’s-length 

transportation arrangement, the 

byproduct transportation allowance is 

your reasonable actual costs for 

transportation during the reporting 

period, including: 

(1) Operating and maintenance 

expenses under paragraphs (d) and (e) of 

this section; 

(2) Overhead under paragraph (f) of 

this section; and either 

(3) Depreciation under paragraphs (g) 

and (h) of this section and a return on 

undepreciated capital investment under 

paragraphs (g) and (i) of this section; or 

(4) A return on capital investment in 

the transportation system under 

paragraphs (g) and (j) of this section. 

(c)(1) Allowable capital costs under 

paragraph (b) of this section are 

generally those for depreciable fixed 

assets (including costs of delivery and 

installation of capital equipment) that 

are an integral part of the transportation 

system. 

(2)(i) You may include a return on 

capital you invested in the purchase of 

real estate to locate the byproduct 

transportation facilities if: 

(A) The purchase is necessary; and 

(B) The surface is not part of a Federal 

lease. 

(ii) The rate of return will be the same 

rate determined in paragraph (k) of this 

section. 

(3) You may not deduct the costs of 

gathering systems and other productionrelated facilities. 

(d) Allowable operating expenses 

include: 

(1) Operations supervision and 

engineering; 

(2) Operations labor; 

(3) Fuel; 

(4) Utilities; 

(5) Materials; 

(6) Ad valorem property taxes; 

(7) Rent; 

(8) Supplies; and 

(9) Any other directly allocable and 

attributable operating expense that you 

can document. 

(e) Allowable maintenance expenses 

include: 

(1) Maintenance of the transportation 

system; 

(2) Maintenance of equipment; 

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24466 Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 

(3) Maintenance labor; and 

(4) Other directly allocable and 

attributable maintenance expenses that 

you can document. 

(f) Overhead directly attributable and 

allocable to the operation and 

maintenance of the transportation 

system is an allowable expense. State 

and Federal income taxes and severance 

taxes and other fees, including royalties, 

are not allowable expenses. 

(g) To compute costs associated with 

capital investment, a lessee may use 

either paragraphs (h) and (i) or 

paragraph (j) of this section. After a 

lessee has elected to use either method 

for a transportation system, the lessee 

may not later elect to change to the 

other alternative without MMS 

approval. 

(h)(1) To compute depreciation, you 

must use a straight-line depreciation 

method based on either the life of the 

equipment or the life of the geothermal 

project which the transportation system 

services. After you choose the basis for 

depreciation, you may not change that 

basis without MMS approval. You may 

not depreciate equipment below a 

reasonable salvage value. 

(2) A change in ownership of a 

transportation system does not alter the 

depreciation schedule established by 

the original lessee-owner for purposes of 

computing transportation costs. 

(3) With or without a change in 

ownership, you may depreciate a 

transportation system only once. 

(i) To calculate a return on 

undepreciated capital investment, 

multiply the remaining undepreciated 

capital balance as of the beginning of 

the period for which you are calculating 

the transportation allowance by the rate 

of return provided in paragraph (k) of 

this section. 

(j) To compute a return on capital 

investment in the transportation system, 

the allowed cost will be the amount 

equal to the allowable capital 

investment in the transportation system 

multiplied by the rate of return 

determined pursuant to paragraph (k) of 

this section. There is no allowance for 

depreciation. 

(k) The rate of return must be the 

industrial rate associated with Standard 

& Poor’s BBB rating. The BBB rate must 

be the monthly average rate as 

published in Standard & Poor’s Bond 

Guide for the first month for which the 

allowance is applicable. You must 

redetermine the rate at the beginning of 

each subsequent calendar year. 

(l)(1) For new transportation facilities 

or arrangements, base your initial 

deduction on estimates of allowable 

byproduct transportation costs for the 

applicable period. Use the most recently 

available operations data for the 

transportation system or, if such data 

are not available, use estimates based on 

data for similar transportation systems. 

(2) When actual cost information is 

available, you must amend your prior 

Form MMS–2014 reports to reflect 

actual byproduct transportation cost 

deductions for each month for which 

you reported and paid based on 

estimated byproduct transportation 

costs. You must pay any additional 

royalties due (together with interest 

computed under § 218.302). You are 

entitled to a credit for or a refund of any 

overpaid royalties. 

§ 206.360 What records must I keep to 

support my calculations of royalty or fees 

under this subpart? 

If you determine royalties or direct 

use fees for your geothermal resource 

under this subpart, you must retain all 

data relevant to the determination of the 

royalty value or the fee you paid. 

Recordkeeping requirements are found 

at part 212 of this chapter. 

(a) You must be able to show: 

(1) How you calculated the royalty 

value or fee you reported, including all 

allowable deductions; and 

(2) How you complied with this 

subpart. 

(b) Upon request, you must submit all 

data to MMS. You must comply with 

any such requirement within the time 

MMS specifies. 

§ 206.361 How will MMS determine 

whether my royalty or direct use fee 

payments are correct? 

(a)(1) The royalties or direct use fees 

that you report are subject to 

monitoring, review, and audit. The 

MMS may review and audit your data, 

and MMS will direct you to use a 

different measure of royalty value, gross 

proceeds, or fee, whichever is 

applicable, if it determines that the 

reported value, gross proceeds, or fee is 

inconsistent with the requirements of 

this subpart. 

(2) If MMS directs you to use a 

different royalty value, measure of gross 

proceeds, or fee, you must either pay 

any royalties or fees due (together with 

interest computed under § 218.302) or 

report a credit for or request a refund of 

any overpaid royalties or fees. 

(b) When the provisions in this 

subpart refer to gross proceeds either for 

the sale of electricity or the sale of a 

geothermal resource, in conducting 

reviews and audits MMS will examine 

whether your sales contract reflects the 

total consideration actually transferred, 

either directly or indirectly, from the 

buyer to you for the geothermal resource 

or electricity. If MMS determines that a 

contract does not reflect the total 

consideration, or the gross proceeds 

accruing to you under a contract do not 

reflect reasonable consideration because 

of misconduct by or between the 

contracting parties, or because you 

otherwise have breached your duty to 

the lessor to market the production for 

the mutual benefit of the lessee and the 

lessor, MMS may require you to 

increase the gross proceeds to reflect 

any additional consideration. 

Alternatively, for Class I leases, MMS 

may require you to use another 

valuation method in the regulations 

applicable to dispositions other than 

under an arm’s-length contract. The 

MMS will notify you to give you an 

opportunity to provide written 

information justifying your gross 

proceeds. 

(c) For arm’s-length sales, you have 

the burden of demonstrating that your 

contract is arm’s length. 

(d) The MMS may require you to 

certify that the provisions in your sales 

contract include all of the consideration 

the buyer paid you, either directly or 

indirectly, for the electricity or 

geothermal resource. 

(e) Notwithstanding any other 

provision of this subpart, under no 

circumstances will the value of 

production for royalty purposes under a 

Class I lease where the geothermal 

resources are sold before use be less 

than the gross proceeds accruing to you. 

(f) Gross proceeds for the sale of 

electricity or for the sale of the 

geothermal resource will be based on 

the highest price a prudent lessee can 

receive through legally enforceable 

claims under its contract. 

(1) Absent contract revision or 

amendment, if you fail to take proper or 

timely action to receive prices or 

benefits to which you are entitled, you 

must pay royalty based upon that 

obtainable price or benefit. 

(2) Contract revisions or amendments 

you make must be in writing and signed 

by all parties to the contract. 

(3) If you make timely application for 

a price increase or benefit allowed 

under your contract, but the purchaser 

refuses and you take reasonable 

measures, which are documented, to 

force purchaser compliance, you will 

owe no additional royalties unless or 

until you receive additional monies or 

consideration resulting from the price 

increase. This paragraph (f)(3) will not 

be construed to permit you to avoid 

your royalty payment obligation in 

situations where a purchaser fails to 

pay, in whole or in part or timely, for 

a quantity of geothermal resources or 

electricity. 

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Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 24467 

§ 206.362 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. 

§ 206.363 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. 

§ 206.364 How do I request a value or 

gross proceeds determination? 

(a) You may request a value 

determination from MMS regarding any 

geothermal resources produced from a 

Class I lease or for byproducts produced 

from a Class I, Class II, or Class III lease. 

You may also request a gross proceeds 

determination for a Class II or Class III 

lease. Your request must: 

(1) Be in writing; 

(2) Identify specifically all leases 

involved, all owners of interests in those 

leases, and the operator(s) for those 

leases; 

(3) Completely explain all relevant 

facts. You must inform MMS of any 

changes to relevant facts that occur 

before we respond to your request; 

(4) Include copies of all relevant 

documents; 

(5) Provide your analysis of the 

issue(s), including citations to all 

relevant precedents (including adverse 

precedents); and 

(6) Suggest your proposed gross 

proceeds calculation or valuation 

method. 

(b) In response to your request: 

(1) The Assistant Secretary, Land and 

Minerals Management, may issue a 

determination; or 

(2) The MMS may issue a 

determination; or 

(3) The MMS may inform you in 

writing that MMS will not provide a 

determination. Situations in which 

MMS typically will not provide any 

determination include, but are not 

limited to: 

(i) Requests for guidance on 

hypothetical situations; and 

(ii) Matters that are the subject of 

pending litigation or administrative 

appeals. 

(c)(1) A determination signed by the 

Assistant Secretary, Land and Minerals 

Management, is binding on both you 

and MMS until the Assistant Secretary 

modifies or rescinds it. 

(2) After the Assistant Secretary issues 

a determination, you must make any 

adjustments in royalty payments that 

follow from the determination and, if 

you owe additional royalties, pay the 

royalties owed together with late 

payment interest computed under §

218.302. 

(3) A determination signed by the 

Assistant Secretary is the final action of 

the Department and is subject to judicial 

review under 5 U.S.C. 701–706. 

(d) A determination issued by MMS is 

binding on MMS and delegated States, 

but not on you, with respect to the 

specific situation addressed in the 

determination unless the MMS (for 

MMS-issued determinations) or the 

Assistant Secretary modifies or rescinds 

it. 

(1) A determination by MMS is not an 

appealable decision or order under 30 

CFR part 290 subpart B. 

(2) If you receive an order requiring 

you to pay royalty on the same basis as 

the determination, you may appeal that 

order under 30 CFR part 290 subpart B. 

(e) In making a determination, MMS 

or the Assistant Secretary may use any 

of the applicable criteria in this subpart. 

(f) A change in an applicable statute 

or regulation on which any 

determination is based takes precedence 

over the determination after the 

effective date of the statute or 

regulation, regardless of whether the 

MMS or the Assistant Secretary 

modifies or rescinds the determination. 

(g) The MMS or the Assistant 

Secretary generally will not 

retroactively modify or rescind a 

determination issued under paragraph 

(d) of this section, unless: 

(1) There was a misstatement or 

omission of material facts; or 

(2) The facts subsequently developed 

are materially different from the facts on 

which the guidance was based. 

(h) The MMS may make requests and 

replies under this section available to 

the public, subject to the confidentiality 

requirements under § 206.365. 

§ 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. 

§ 206.366 What is the nominal fee that a 

State, tribal, or local government lessee 

must pay for the use of geothermal 

resources? 

If a State, tribal, or local government 

lessee uses a geothermal resource 

without sale and for public purposes— 

other than commercial production or 

generation of electricity—the State, 

tribal, or local government lessee must 

pay a nominal fee. A nominal fee means 

a slight or de minimis fee. The MMS 

will determine the fee on a case-by-case 

basis. 

PART 210—FORMS AND REPORTS 

■ 6. The authority for part 210 

continues to read as follows: 

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). 

Subpart H—Geothermal Resources 

§ 210.352 [Removed] and § § 210.353 

through 210.355 [Redesignated] 

■ 7. Remove § 210.352, and redesignate 

§ § 210.353 through 210.355 as § §

210.352 through 210.354, respectively. 

■ 8. Revise redesignated § 210.354 to 

read as follows: 

§ 210.354 Reporting Instructions. 

Specific guidance on how to prepare 

and submit required information 

collection reports and forms to MMS is 

contained in the publication titled 

Minerals Revenue Reporter Handbook— 

Oil, Gas, and Geothermal Resources, 

which is available from the Minerals 

Management Service, Minerals Revenue 

Management, Financial Management, 

P.O. Box 25165, Mail Stop 350B1, 

Denver, CO 80225–0165. For copies 

from the MMS Web site, go to http:// 

www.mrm.mms.gov/. Click Reporting 

Information and select the topic. 

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24468 Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 

PART 217—AUDITS AND 

INSPECTIONS 

■ 9. The authority for part 217 

continues to read as follows: 

Authority: 35 Stat. 312; 35 Stat. 781, as 

amended; secs. 32, 6, 26, 41 Stat. 450, 753, 

1248; secs. 1, 2, 3, 44 Stat. 301, as amended; 

secs. 6, 3, 44 Stat. 659, 710; secs. 1, 2, 3, 44 

Stat. 1057; 47 Stat. 1487; 49 Stat. 1482, 1250, 

1967, 2026; 52 Stat. 347; sec. 10, 53 Stat. 

1196, as amended; 56 Stat. 273; sec. 10, 61 

Stat. 915; sec. 3, 63 Stat. 683; 64 Stat. 311; 

25 U.S.C. 396, 396a–f, 30 U.S.C. 189, 271, 

281, 293, 359. Interpret or apply secs. 5, 5, 

44 Stat. 302, 1058, as amended; 58 Stat. 483– 

485; 5 U.S.C. 301; 16 U.S.C. 508b; 30 U.S.C. 

189, 192c, 271, 281, 293, 359; and 43 U.S.C. 

387, unless otherwise noted. 

■ 10. Add a new subpart G to read as 

follows: 

Subpart G—Geothermal Resources 

Sec. 

217.300 Audits or review of records. 

217.301 Lease account reconciliations. 

217.302 Definitions. 

§ 217.300 Audit or review of records. 

The Secretary, or his/her authorized 

representative, will initiate and conduct 

audits or reviews relating to the scope, 

nature, and extent of compliance by 

lessees, operators, revenue payors, and 

other persons with rental, royalty, fees, 

and other payment requirements on a 

Federal geothermal lease. Audits or 

reviews will also relate to compliance 

with applicable regulations and orders. 

All audits or reviews will be conducted 

in accordance with this part. 

§ 217.301 Lease account reconciliations. 

Specific lease account reconciliations 

will be performed with priority being 

given to reconciling those lease 

accounts specifically identified by a 

State as having significant potential for 

underpayment. 

§ 217.302 Definitions. 

Terms used in this subpart will have 

the same meaning as in 30 U.S.C. 1702. 

PART 218—COLLECTION OF 

ROYALTIES, RENTALS, BONUSES 

AND OTHER MONIES DUE THE 

FEDERAL GOVERNMENT 

■ 11. Revise the heading for part 218 to 

read as follows: 

PART 218—COLLECTION OF 

ROYALTIES, RENTALS, BONUSES, 

AND OTHER MONIES DUE THE 

FEDERAL GOVERNMENT AND 

CREDITS AND INCENTIVES DUE 

LESSEES 

■ 12. The authority for part 218 

continues to read as follows: 

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. 

■ 13. Add new § § 218.303 through 

218.307 to subpart F to read as follows: 

Subpart F—Geothermal Resources 

* * * * * 

§ 218.303 May I credit rental towards 

royalty? 

(a)(1) For Class II leases as defined in 

30 CFR 206.351, and for Class III leases 

as defined in that section that elect 

under 43 CFR 3200.7(a)(2) to be subject 

to all of the BLM regulations 

promulgated for leases issued after 

August 8, 2005 you may credit the 

annual rental that you paid before the 

first day of the year for which the 

annual rental is owed against the royalty 

due for the lease year for which the 

rental was paid. You may not apply any 

annual rental paid in excess of the 

royalty due for a particular lease year as 

a credit against any royalty due in any 

subsequent lease year. 

(2) For purposes of this section, the 

term ‘‘royalty’’ includes any advanced 

royalty payable under 30 U.S.C. 1004(f) 

for a cessation of production. 

(b) If portions of your lease are located 

both within and outside of a 

participating area, you may credit 

against royalty under paragraph (a) only 

that percentage of the rental you paid 

that corresponds to the percentage of the 

lease within the participating area on a 

per-acre basis. 

§ 218.304 May I credit rental towards 

direct use fees? 

You may not credit annual rental 

toward direct use fees you are required 

to pay that year under § 206.356(b). You 

must pay the direct use fees in addition 

to the annual rental due. 

§ 218.305 How do I pay advanced 

royalties I owe under BLM regulations? 

If you pay advanced royalties under 

43 CFR 3212.15(a)(1) to retain your 

lease: 

(a) You must pay an advanced royalty 

monthly equal to the average monthly 

royalty you paid under 30 CFR part 206, 

subpart H (including the amount against 

which you applied the annual rental as 

a credit) for the last 3 years the lease 

was producing. If your lease has been 

producing for less than 3 years, then use 

the average monthly royalty payment for 

the entire period your lease has been 

producing continuously; 

(b) The MMS must receive your 

advanced royalty payment before the 

end of each full calendar month in 

which no production occurs; 

(c) You may credit any advanced 

royalty you pay against production 

royalties you owe after your lease 

resumes production. You may not 

reduce the amount of any production 

royalty paid for any year below zero. 

§ 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? 

(a) You may receive a credit against 

royalties for in-kind deliveries of 

electricity you provide under contract to 

a State or county government if: 

(1) The State or county to which you 

provide electricity would receive a 

portion of the royalties you paid in 

money for the lease under 30 U.S.C. 191 

or 30 U.S.C. 1019, except as otherwise 

provided under the Mineral Leasing Act 

for Acquired Lands, 30 U.S.C. 355, 

because your lease is located in that 

State or county. If your lease is located 

in more than one State or county, the 

revenues are paid to the respective 

States or counties based on their 

proportionate shares of the total acres in 

the lease; 

(2) The MMS approves in advance 

your contract with the State or county 

to which you are providing in-kind 

electricity; and 

(3) Your contract provides that you 

will use the wholesale value of the 

electricity for the area where your lease 

is located to establish the specific 

methodology to determine the amount 

of the credit; and 

(b) The maximum credit you may take 

under this section is equal to the portion 

of the royalty revenue that MMS would 

have paid to the State or county that is 

a party to the contract had you paid 

royalty in money on all of the electricity 

you delivered to the State or county 

based on the wholesale value of the 

electricity. You must pay in money any 

royalty amount that is not offset by the 

credit allowed under this section, 

calculated based on the wholesale value 

of the electricity. 

(c) The electricity the State or county 

government receives from you satisfies 

the Secretary’s payment obligation to 

the State or county under 30 U.S.C. 191 

or 30 U.S.C. 1019. 

§ 218.307 How do I pay royalties due for 

my existing leases that qualify for near-term 

production incentives under BLM 

regulations? 

If you qualify for a production 

incentive under BLM regulations at 43 

CFR subpart 3212, your royalty due on 

the production BLM determines to be 

qualified for a production incentive 

under 43 CFR 3212.23 and 3212.24 is 50 

percent of the amount of the total 

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Federal Register / Vol. 72, No. 84 / Wednesday May 2, 2007 / Rules and Regulations 24469 

royalty that would otherwise be due 

under 30 CFR part 206, subpart H. 

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

BILLING CODE 4310–MR–P 

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