[Federal Register: May 2, 2007 (Volume 72, Number 84)]
[Rules and Regulations]
[Page 24447-24469]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr02my07-9]
[[Page 24447]]
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Part III
Department of the Interior
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Minerals Management Service
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30 CFR Parts 202, 206, 210, 217 and 218
Geothermal Royalty Payments, Direct Use Fees, and Royalty Valuation;
Final Rule
[[Page 24448]]
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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.
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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 mineral-related policies and
provides a sounding board to convey views representative of mineral
lessees, operators, revenue payors, recipients, governmental agencies,
and the interested public. The RPC may establish subcommittees or
workgroups as it deems necessary for the purposes of compiling
information or conducting research. Subcommittees or workgroups may not
conduct business independent of the RPC and must report its
recommendations to the full RPC for consideration. Subcommittees or
workgroups meet as necessary to accomplish their assignments, subject
to the approval of the RPC Chairperson.
On October 28, 2004, the RPC formed the Geothermal Valuation
Subcommittee (Subcommittee) to address the MMS geothermal royalty
valuation regulations to simplify the regulations and reduce
administrative costs to the geothermal industry. The Subcommittee was
comprised of members from one industry association, several geothermal
producers, two of the major States affected, and MMS employees. A
representative of the Bureau of Land Management (BLM) served as
technical advisor to the Subcommittee. The RPC requested that the
Subcommittee work together to develop more efficient royalty valuation
methods that will ensure a fair return to the Federal Government as
well as encourage geothermal development. The Subcommittee prepared a
report and submitted it to the RPC; and on May 26, 2005, the RPC
accepted the Subcommittee's recommendations.
B. The EPAct
On August 8, 2005, the President signed into law the EPAct, Pub. L.
109-58, 119 Stat. 594. Sections 221 through 237 of the EPAct, entitled
the ``John Rishel Geothermal Steam Act Amendments,'' amended the GSA,
30 U.S.C. 1001 et seq. (1970). Congress enacted the EPAct geothermal
amendments to encourage geothermal production through regulatory
streamlining and incentives. S. Rep. No. 78, 109th Cong., 1st Sess.
(2005).
C. The Proposed Rule
On July 21, 2006, MMS published a proposed rule in the Federal
Register (71 FR 41516) that addressed implementing the EPAct
provisions. It also incorporated most of the Subcommittee's concepts,
with modifications necessary to comply with the EPAct.
For 30 CFR part 206, subpart H, we: (1) Explained the general
royalty calculation and payment, direct use fee, and royalty valuation
provisions of this subpart; (2) defined which leases the subpart
applies to; (3) provided definitions of terms used in the subpart; (4)
proposed some changes to conform to plain English writing; and (5)
proposed changes necessary to implement provisions of the EPAct.
For 30 CFR parts 202, 210, and 218, we proposed changes necessary
to implement provisions of the EPAct and reflect the proposed
amendments to 30 CFR part 206, subpart H.
II. Comments on the Proposed Rule
The MMS received comments on the proposed rule from two States, one
trade association, and two geothermal producers. These comments are
analyzed and discussed below:
A. 30 CFR Part 202--Royalties
1. 202.351(a)(2)(ii) Royalties on geothermal resources
Public Comments: The trade association commented that the
definition of ``gross proceeds'' in Sec. 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 Sec.
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 Sec. 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 Sec.
206.351.
However, Sec. 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.
[[Page 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 Sec. 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 Sec. 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 Sec.
206.351 of the final rule. As more fully prescribed in that section,
``Class I leases'' are leases issued before the date of enactment of
the EPAct (or in response to an application pending on that date) which
the lessee does not convert to EPAct terms. ``Class II leases'' are
leases issued after the date of enactment of the EPAct (except for
leases issued in response to an application pending on that date which
the lessee does not convert to EPAct terms). ``Class III leases'' are
leases issued before the date of enactment of the EPAct that the lessee
converts to EPAct royalty terms. Paragraph (b)(2) in the final rule
addresses what is free of royalty or direct use fees first by the legal
category of the lease and then by the use of the resource.
Clause (i) of paragraph (b)(2) addresses Class I leases, which are
covered by the existing rule. This paragraph preserves the existing
rule's treatment for royalty purposes of each of the volume categories
identified above--i.e., that all of them are free of royalty. The
determination of the reasonable amount of the resource used to generate
plant parasitic electricity under a Class I lease is subject to MMS
jurisdiction. (Commercially demineralized water is relevant only under
Class I leases, and therefore is not mentioned in the subsequent
clauses addressing Class II and Class III leases.)
Clause (ii) of paragraph (b)(2) addresses Class II leases and Class
III leases (leases with EPAct royalty terms) whose geothermal resources
are used for the commercial production or generation of electricity or
are sold at arm's length for the commercial production or generation of
electricity. For these leases, if the lessee sells electricity on the
commercial market, the lease provides for royalty as a percentage of
gross proceeds derived from sale of the electricity. Unavoidably lost
or reinjected resource volumes and volumes associated with generating
plant parasitic electricity or electricity for lease operations do not
result in generation of any electricity that is sold. It follows that
there are no gross proceeds from the sale of electricity that result
from them. Therefore, these volumes have no royalty consequence.
However, under a Class II lease or Class III lease, if the lessee
sells the geothermal resource at arm's length before commercial
production or generation of electricity, under the final rule royalty
is a function of the gross proceeds derived from the sale of the
resource. To the extent that any loss of resources is avoidable, MMS
would require the lessee to pay royalties on that volume. Thus, it is
appropriate to clarify that only unavoidably lost or reinjected volumes
are not royalty-bearing. MMS will also allow free of royalty a
reasonable amount of resource volumes used to generate electricity for
Federal lease operations. (There is no plant parasitic electricity if
the lessee sells the resource and, therefore, no resources are used to
generate it.)
The existing rule and the proposed rule refer to electricity
``returned to the lease for lease operations.'' In the final rule, the
phrasing of the term has been clarified to ``electricity for Federal
lease operations.'' First, it is not necessary that this electricity be
generated off the lease and then ``returned to the lease.'' Second, MMS
wishes to clarify that resources used to generate electricity for non-
Federal (e.g., state or private) lease operations are not royalty-free.
Approval of the amount of resources used to generate electricity for
lease operations that is royalty-free is subject to BLM, rather than
MMS, jurisdiction.
In addition to the royalty effects discussed above, the rule must
also address the question of what resources, if any, might be subject
to direct use fees. Under 30 U.S.C. 1001(g), the term ``direct use''
means ``utilization of geothermal resources for commercial,
residential, agricultural, public facilities, or other energy needs
other than the commercial production of electricity.'' The definition
of the term ``direct use'' in the final rule at 30 CFR 206.351 is
essentially identical. Section 206.351 then defines the term
``commercial production or generation of electricity'' to include the
electricity or energy that is reasonably required both to produce the
resource and to convert geothermal energy into electrical energy for
sale. This definition includes the generation of both plant parasitic
electricity and electricity for lease operations, as well as other uses
of resources for lease operations. Therefore, where the lessee of a
Class II lease or Class III lease sells electricity commercially, use
of resources for these purposes, by definition, does not constitute a
direct use under the final rule. The resources therefore are not
subject to direct use fees.
The text of clause (ii) covers each of the situations and
consequences described above.
Clause (iii) addresses direct use fees when the geothermal
resources produced from a Class II lease or Class III lease are used
for direct use purposes other than commercial production or generation
of electricity, as those terms are defined in 30 CFR 206.351. It is
appropriate to allow unavoidably lost and reinjected resource volumes
to be free of direct use fees because they are not used and are not
avoidably lost. However, because generating electricity for direct use
lease operations falls within the definition of ``direct use'' under
Sec. 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 Sec. 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.''
[[Page 24450]]
MMS Response: In the proposed rule, the MMS proposed to change the
existing rule, at Sec. 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 Sec. 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, Sec. 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
[[Page 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 Sec.
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 Sec. 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 Sec. 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, Sec. 206.352(a) clearly states that for geothermal
resources purchased ``at arm's length that the purchaser uses to
generate electricity, then the royalty on the geothermal resources is
the gross proceeds accruing to you from the sale of the geothermal
resource to the arm's-length purchaser multiplied by the royalty rate
in your lease or that BLM prescribes or calculates under 43 CFR
3211.17.'' Therefore, MMS sees no need for clarification regarding the
netback method and arm's-length situations.
With respect to how to value geothermal resources when electricity
is sold directly to ratepayers (consumers of the electricity), rather
than the typical situation where the lessee sells electricity under an
arm's-length contract to a utility, we are assuming that the sales to
the ratepayers are also arm's length. We are further assuming that the
lessee would have contractual agreements with the ratepayers for the
sales of electricity. In that instance, the gross proceeds would be the
combination of the sales to multiple ratepayers. The same would hold
true if a lessee sold electricity to multiple utilities. Therefore, the
lessee would pay under Sec. 206.352(b)(1). Of course, the commenter is
correct that the lessee could request a value or gross proceeds
methodology under Sec. 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
Sec. Sec. 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 Sec. Sec. 206.353(f) and 206.354(f), rewritten in plain
English.
[[Page 24452]]
In the final rule, MMS has changed a provision of Sec.
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 Sec. 206.353(b)(1)) and the
proposed rule (at Sec. 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 Sec. 206.354(b)(1).
However, Sec. 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 Sec. 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 Sec.
206.353(b)(2)(iv)(A)) to compute depreciation using a straight-line
method based on the life of the geothermal project (usually the term of
the electricity sales contract) or other depreciation period acceptable
to MMS. There was no discussion or explanation of this provision in the
preamble to the proposed rule. It is uncertain how the change in
language arose, because MMS intended no change in the existing
provision.
Further, the proposed rule in the same paragraph omitted language
in the existing rule to the effect that a change in ownership of a
transmission line does not alter the depreciation schedule established
by the original lessee-owner for purposes of determining transmission
line costs. Again, MMS intended no change in the existing rule in this
regard. Both of these errors are corrected in Sec. 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 Sec. 206.354(h). The proposed rule would have added to the existing
rule (at Sec. 206.354(b)(2)(iv)(A)) an option to compute depreciation
on a unit-of-production method. This does not appear to be appropriate
in the geothermal context. The proposed rule again omitted language in
the existing rule regarding a change in ownership of the power plant
not altering the original depreciation schedule. Both of these errors
have been corrected in the final rule.
4. 30 CFR 206.356 How do I calculate royalty or fees due on geothermal
resources I use for direct use purposes?
Public Comments: Two commenters objected to MMS's minor
modifications to the fee schedule proposed by the Subcommittee.
Specifically, a commenter requested that MMS eliminate the efficiency
factor in the denominator of the equation for calculating fees, and one
commenter objected to the increase in fees in the proposed schedule
from the schedule the Subcommittee recommended. Another commenter
stated that, under the proposed rule, a lessee could not produce
electricity from a Class III lease.
MMS Response: With respect to the efficiency factor, MMS used the
same formula as the Subcommittee, which included the efficiency factor.
The Subcommittee used the efficiency factor because:
Valuation using coal, wood chips, or natural gas is based on
``displaced energy,'' where the binary valuation is based on
``extracted energy.'' Displaced energy uses an efficiency factor to
account for heat lost during the combustion of the alternative
fuels. The efficiency factor typically adds 25 percent to 33 percent
to the value of those fuels.
Royalty Policy Committee Geothermal Valuation Subcommittee Report (May
2005), Attachment 3, page 2.
If we eliminate the efficiency factor from the formula, it would
erroneously assume that the use of geothermal resources for direct use
purposes is 100 percent efficient. Because the direct use of geothermal
energy is not 100 percent efficient, MMS will keep the efficiency
factor to account for heat lost during the direct use of geothermal
resources.
With respect to the increase in fees in the proposed schedule from
the fees in the Subcommittee Report, the Subcommittee recommended using
Powder River Basin coal prices to determine what a Btu of heating
energy was worth. That measure was to be used in calculating royalty
owed on geothermal resources used in direct use projects and not sold.
Powder River Basin coal prices had been relatively stable for some
time. However, the Subcommittee contemplated that MMS would change the
fee schedule from time to time. In the interim between the Subcommittee
Report and publication of the proposed rule, Powder River Basin coal
prices increased. The MMS believes it is eminently reasonable to update
the fee schedule to reflect current coal prices, rather than past
prices. Thus, we will retain the proposed fee schedule.
It is possible that a lessee of a geothermal lease may use the
geothermal resource first to produce electricity and then either sell
or use the still-hot water for direct use in another operation. (This
is sometimes known as ``cascading.'') Cascading is a process in which
the user gains the use of the heat after its use by the same or a
different party who is using the higher-grade geothermal resource to
generate electricity. As we stated in the preamble to the final 1991
geothermal rule, ``the issue of royalties due on geothermal resources
utilized in cascading steps is straightforward: the lessee is
responsible for paying royalty on the total thermal energy yielded by
the resource'' (56 FR 57268). The MMS believes that this philosophy
also is consistent with the intent of Congress in the EPAct.
The MMS knows of two operations that involved ``cascading'' in the
past, but there appears to be no current operation that involves a
second use of the resource after commercial generation of electricity.
Nevertheless, such a situation may arise again in the future, and MMS
therefore has addressed this issue here.
Thus, for example, assume that the lessee uses the geothermal
resource to generate electricity. Also assume that the lessee then uses
the still-hot geothermal resource, after it is used in the plant for
electrical generation, in a direct use operation. In that instance, as
with the existing regulations, under this rule, the lessee of a Class I
lease would have to pay royalties on both the direct use and electrical
generation. For Class II and Class III leases, the lessee would have to
pay royalties on the gross proceeds derived from commercial
[[Page 24453]]
electrical generation and fees for the direct use. MMS has added
language to Sec. 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 Sec. 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 Sec. 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 Sec. 206.359(h) provided that in computing
depreciation, the lessee may elect to use either a straight-line method
based on the life of the transportation system, the life of the
reserves which the transportation system services, or a unit-of-
production method. This would have changed the option in the existing
rule (at Sec. 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 Sec. 206.359(h) of the final rule.
MMS does not expect wide applicability of these provisions in view
of the fact that no lessees currently are reporting royalties on
byproducts or byproduct transportation allowances. Nevertheless, these
provisions may become applicable in the future, and the final rule
should not create unnecessary confusion. It is therefore appropriate to
make the corrections described above.
C. 30 CFR Part 217--Audits and Inspections, Subpart H--Geothermal
Resources
Although the regulatory text of part 217 was omitted from the
proposed rule, an opportunity for public comment was provided in the
preamble discussion, including the information collection requirements.
No comments were received regarding part 217, which contains technical,
noncontroversial audit information. The regulatory text of part 217 is
included in this final rule.
D. 30 CFR Part 218--Collection of Royalties, Rentals, Bonuses and Other
Monies Due the Federal Government, Subpart F--Geothermal Resources
1. 30 CFR 218.303 May I credit rental towards royalty?
Public Comments: We received one comment stating that the proposed
rule's requirement that the credit be taken ``only in the year paid-
goes beyond the law, is too strict, and will have the unforeseen
consequence of imposing financial burdens when companies can least
afford additional costs.''
MMS Response: In section 230 of the EPAct, Congress added a new 30
U.S.C. 1004(e) that authorized lessees to credit ``[a]ny annual rental
under this section that is paid with respect to a lease before the
first day of the year for which the annual rental is owed shall be
credited to the amount of royalty that is required to be paid under the
lease for that year'' (emphasis added). We think it is clear from the
language of the EPAct that lessees may credit annual rental paid in a
particular year only to royalties paid ``that year.'' Thus, Congress,
not MMS, has directed that credits for rentals paid be restricted to
the year for which they are paid. Any other construction is contrary to
the statute's plain language.
Title 30 U.S.C. 1004(e), as added by section 230 of the EPAct,
provides that ``[a]ny annual rental under this section that is paid
with respect to a lease before the first day of the year for which the
annual rental is owed shall be credited to the amount of royalty that
is required to be paid under the lease for that year.'' It is apparent
that Congress intended this provision to apply to post-EPAct leases. It
is only under section 1004(a)(3), as added by the EPAct, that a lessee
must continue to pay annual rental regardless of whether the lease is
in production. Under the terms of pre-EPAct leases, rental ceases when
the lease goes into production (and the lease is then subject to
minimum royalty).
Thus, the rental crediting provision will apply to Class II leases,
as defined in 30 CFR 206.351. In addition, Class III leases as defined
in that section may elect to be subject to all of the BLM regulations
promulgated for leases issued after August 8, 2005, under 43 CFR
3200.7(a)(2). That election would operate to convert the rental terms
to EPAct terms. Crediting annual rental against royalty therefore
should apply to those leases as well. Class III leases that do not
elect to be subject to all of the regulations promulgated for post-
EPAct leases will retain their existing rental terms. The crediting
provision therefore
[[Page 24454]]
should not apply to those Class III leases. MMS has revised the
language of Sec. 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 Sec. 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 Sec.
218.303, the annual rental may be credited against the advanced royalty
due, and we have added specific language in Sec. 218.303(a)(2) in the
final rule to effect that result. Thus, both royalty and advanced
royalty will be treated identically for purposes of crediting annual
rental.
4. 30 CFR 218.306 May I receive a credit against production royalties
for in-kind deliveries of electricity I provide under contract to a
State or county government?
This provision implements the new 30 U.S.C. 1004(d), added by EPAct
section 224. The maximum credit for the value of the electricity
provided to a State or county government is the share of royalty
payments that the State or county would receive under the permanent
indefinite appropriation established by 30 U.S.C. 1019, as amended by
EPAct section 224(b). Under section 1004(d)(3), the electricity
delivered will serve as the payment of the State's or county's share.
The preamble to the proposed rule gave an hypothetical example of the
operation of this provision as follows:
For example, assume that you have a geothermal lease in New
Mexico and that you delivered 10,000 megawatt-hours of electricity
in a month to New Mexico under a contract MMS approved. Furthermore,
assume that the wholesale value of megawatt-hours in the area where
your lease is located is $30.00 per megawatt-hour that month. If you
had paid royalties in money on the basis of that wholesale value,
and further assuming that you have a Class I lease with a 10-percent
royalty rate, you would have paid $30,000 to MMS. The MMS then would
have paid 50 percent of that amount ($15,000) to the State of New
Mexico. You would be entitled to a credit of $15,000 against the
amount you would otherwise owe to MMS when royalty is calculated on
that basis. You would have to pay the remaining $15,000 to MMS in
money.
71 FR 41523. The last sentence of this explanation inadvertently
overlooked explaining one further consequence of this provision, which
we explain here for purposes of clarity.
Under 30 U.S.C. 1019, the State in which a lease is located
receives 50 percent of the royalties paid to the United States, the
county receives 25 percent, and 25 percent is deposited to
miscellaneous receipts in the Treasury. When the lessee delivers the
electricity in kind and takes the credit against royalties of $15,000,
the in-kind delivery serves as payment of the State's 50 percent share
under 30 U.S.C. 1019. The royalty paid in money therefore is divided
evenly between the county and the Treasury.
Under the hypothetical as stated, for the lessee to claim the
$15,000 credit against royalties, it would have to deliver $15,000
worth of electricity (which would equal 500 megawatt-hours in this
example) in kind to New Mexico. If it did, instead of realizing
$300,000 from the sale of all 10,000 megawatt-hours, the lessee would
[[Page 24455]]
realize $285,000 from the sale of 9,500 megawatt-hours and no money for
the in-kind delivery of the 500 megawatt-hours. The royalty owed in
money under this lease, before application of the credit, would be
$28,500.
In the hypothetical, the lessee would apply the $15,000 credit
against royalties to the $28,500 it would owe in money, and would
actually pay $13,500. That amount would be distributed 50 percent to
the county and 50 percent to the Treasury--in this case, $6,750 to
each. In contrast, if no electricity had been delivered in kind and the
lessee had paid $30,000 as royalty in money, the State of New Mexico
would have received $15,000, the county in which the lease is located
would have received $7,500, and the Treasury would have received the
remaining $7,500. Thus, use of the in-kind credit results in a slight
adverse monetary consequence to the county and the Federal government.
This hypothetical illustrates that use of the in-kind credit reduces
not only the royalty paid to the United States as a result of the
credit but also reduces the lessee's proceeds on which royalty is
calculated.
In the final rule, MMS has also made several changes from the
proposed rule to eliminate duplicative language, clarify potential
ambiguities, and express provisions in plainer English. None of those
changes effects any change in substantive meaning.
III. Procedural Matters
1. Effective Date
This rule becomes effective 30 days following publication, rather
than 60 days, because the Department and the geothermal industry are
interested in having competitive geothermal lease sales as soon as
possible. Lease sales cannot be held until both the BLM and MMS final
rules become effective because it is these rules that prescribe key
terms and conditions of new leases. The Department intends for both the
BLM and MMS rules to become effective simultaneously.
2. Summary Cost and Royalty Impact Data
Of the changes to the geothermal valuation regulations outlined
above, only a few will have a royalty impact on industry, States, or
the Federal Government. This section addresses those changes and
discusses the extent of their impacts. There are no ``Costs and
Benefits,'' under the meaning identified by the Office of Management
and Budget (OMB), as a result of this rule. However, there are certain
estimated royalty effects of this rule to all potentially affected
groups: industry, States and local governments, and the Federal
Government. These are summarized below. There are no significant
associated costs to industry of administering this rule. The Federal
government will incur some minimal costs associated with systems
changes.
Of the changes that have royalty cost impacts, three will result in
royalty decreases for industry, States, and MMS. One will result in an
increase to the counties with producing Federal geothermal leases. The
net impact of the six changes will result in an expected overall
royalty revenue decrease of $4,101,583 to the Federal Government, a
corresponding increase to counties of $4,071,583, and a decrease of
$30,000 in royalties to the States.
We have evaluated potential effects on federally recognized Indian
tribes and have determined that the changes in this rule for Federal
leases would not apply to and currently would not have an impact on
Indian leases. In addition, this rule does not have tribal implications
that impose substantial direct compliance costs on Indian tribal
governments.
A. Industry
(1) Royalty Impacts
(a) No Change in Royalties--Electrical Generation
Because the EPAct mandates that the level of royalty revenues
received by MMS should be the same over a 10-year period as what would
have been received under the valuation methods of the existing
regulations, there are no significant overall revenue impacts for
electrical generation projects. Electrical generation lessees that
remain under the existing regulations will pay royalties on the same
basis as they did before this final rule. And, while electrical
generation lessees that modify their leases to the new regulations will
change to the percentage of gross proceeds method, the level of
royalties they pay will not differ significantly from the royalties
paid under the existing regulations. New lessees' royalty rates are
determined by BLM, which may cause some difference in royalty payments
by individual lessees, but which should result in the same overall
level of royalties for 10 years under this final rule as they would
have paid under the existing regulations.
(b) Net Decrease in Royalties--Direct Use--Estimated at $60,000
Current direct use lessees who do not sell the geothermal resources
have the option to convert their leases to the new fee schedule, which
MMS anticipates will result in a reduction of $60,000 per year from the
current level of royalties, a 95-percent reduction. In addition, all
new direct use lessees who do not sell the geothermal resources under
the new regulations use the same fee schedule, also paying about 95
percent less than they would have under the existing regulations.
(2) Administrative Costs
The MMS has determined that there are no significant expected
administrative cost changes.
B. State and Local Governments
(1) Royalty Impacts--State Governments
(a) Net Decrease in Royalties--Direct Use--Estimated at $30,000
The MMS estimates that States impacted by this rule will receive
the same royalties as they currently receive for electrical generation
leases without significant variation. However, because of the 95-
percent decrease in revenue collected from direct use leases, States
that receive a share of that revenue under 30 U.S.C. 191 will be
impacted by the revenue decrease. It is unknown how this will affect
the counties because the States distribute royalty revenues to their
counties directly without MMS involvement. The new fee schedule will
result in approximately a 95-percent reduction in royalties paid to
States from direct use projects. The MMS estimates the reduction to be
$30,000 per year. This amount is based on the difference between the
average of direct use royalties paid for fiscal years 2001 through 2005
and the revenues to be collected using the new fee schedule.
(2) Administrative Costs--State Governments
The MMS has determined that there are no expected administrative
cost changes for State governments.
(3) Royalty Impacts--Local Governments
(a) Net Increase in Royalties--Estimated at $4,071,583
The EPAct (30 U.S.C. 1019, as amended by section 224(b) of the
EPAct) mandates a new distribution of 25 percent of royalties, rentals,
bonuses, and other revenues to the counties. This 25 percent cuts the
Federal share in half from 50 percent to 25 percent and leaves the
States' share as 50 percent. The counties will receive a new 25-percent
distribution of total geothermal royalty revenue under the EPAct, which
increases their revenues by an estimated $4,071,583 per year (25
percent of the average total geothermal royalties of $16,286,334 paid
for fiscal years 2001
[[Page 24456]]
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
------------------------------------------------------------------------
Costs and royalty increases or
royalty decreases
Description -------------------------------
Subsequent
First year years
------------------------------------------------------------------------
A. Industry
------------------------------------------------------------------------
Royalty Decrease from Direct Use Fee -$60,000 -60,000
Schedule...............................
Net Expected Change in Royalty (direct -60,000 -60,000
use fee) Payments from Industry........
------------------------------------------------------------------------
B. State and Local Governments
------------------------------------------------------------------------
State:
Royalty Decrease to State -30,000 -30,000
Governments........................
Local Governments (counties):
Royalty Increase to counties........ +4,071,583 +4,071,583
Net Expected Change in Royalty Payments +4,041,583 +4,041,583
to State and Local Governments.........
------------------------------------------------------------------------
C. Federal Government
------------------------------------------------------------------------
Royalty Decrease from 25 percent Royalty -4,071,583 -4,071,583
Disbursement to Counties...............
Royalty Decrease from New Direct Use Fee -30,000 -30,000
Schedule Implementation................
Net Expected Change in Royalty Payments -4,101,583 -4,101,583
to Federal Government..................
------------------------------------------------------------------------
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
[[Page 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-by-
case.'' Section 1.3 of the same appendix clarifies that royalties and
audits are considered to be routine financial transactions that are
subject to categorical exclusion from the NEPA process. No exception to
the categorical exclusion applies.
12. Government-to-Government Relationship With Tribes
In accordance with the President's memorandum of April 29, 1994,
``Government-to-Government Relations with Native American Tribal
Governments'' (59 FR 22951) and Department Manual 512 DM 2, we have
evaluated potential effects on federally recognized Indian tribes. This
rule does not apply to Indian leases.
13. Effects on the Nation's Energy Supply, Executive Order 13211
In accordance with Executive Order 13211, this regulation does not
have a significant adverse effect on the Nation's energy supply,
distribution, or use. The changes primarily involve royalty valuation
of geothermal production to simplify royalty valuation, hence, any
impact to the way industry does business should be positive, and, as
the EPAct directs, should encourage energy development and marketing.
This rule does not otherwise impact energy supply, distribution, or
use.
[[Page 24458]]
14. Consultation and Coordination With Indian Tribal Governments,
Executive Order 13175
In accordance with Executive Order 13175, we have evaluated this
rule and determined that it has no potential effects on federally
recognized Indian tribes. This rule does not have tribal implications
that impose substantial direct compliance costs on Indian tribal
governments.
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.
0
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
0
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
0
2. Revise Sec. 202.351 to read as follows:
Sec. 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 Sec. 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.
0
3. Revise Sec. 202.353 to read as follows:
Sec. 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
Sec. 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
Sec. 206.352(b), you must report the quantities in kilowatt-hours to
the nearest whole kilowatt-hour.
(b) For geothermal resources used in direct use processes, you must
report the quantity on which a royalty or direct use fee is due on Form
MMS-2014 in:
(1) Millions of Btu to the nearest whole million Btu if valuation
is in terms of heat or thermal energy used or displaced;
(2) Millions of gallons to the nearest million gallons of
geothermal fluid produced if valuation or fee calculation is in terms
of volume;
(3) Millions of pounds to the nearest million pounds of geothermal
fluid produced if valuation or fee calculation is in terms of mass; or
(4) Any other measurement unit MMS approves for valuation and
reporting purposes.
(c) For byproducts, you must report the quantity on which royalty
is due on Form MMS-2014 consistent with MMS-established reporting
standards.
(d) For commercially demineralized water, you must report the
quantity on which royalty is due on Form MMS-
[[Page 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
0
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.
0
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
Sec. 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 Sec.
206.364 of this subpart.
Sec. 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-to-day management of a lease, plant, pipeline, or other facility;
and
(v) Other evidence of power to exercise control over or common
control with another person.
(3) Regardless of any percentage of ownership or common ownership,
relatives, either by blood or marriage, are affiliates.
Allowance means a deduction in determining value for royalty
purposes.
Arm's-length contract means a contract or agreement between
independent persons who are not affiliates and who have opposing
economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this
definition for that month, as well as when the contract was executed.
Audit means a review, conducted in accordance with generally
accepted accounting and auditing standards, of royalty or fee payment
compliance activities of lessees or other interest holders who pay
royalties, fees, rents, or bonuses on Federal geothermal leases.
Byproducts means minerals (exclusive of oil, hydrocarbon gas, and
helium), found in solution or in association with geothermal steam,
that no person would extract and produce by themselves because they are
worth less than 75 percent of the value of the geothermal steam or
because extraction and production would be too difficult.
Byproduct recovery facility means a facility where byproducts are
placed in marketable condition.
Byproduct transportation allowance means an allowance for the
reasonable, actual costs of moving byproducts to a point of sale or
delivery off the lease, unit area, or communitized area, or away from a
byproduct recovery facility. The byproduct transportation allowance
does not include gathering costs. You must report a byproduct
transportation
[[Page 24460]]
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
[[Page 24461]]
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.
Sec. 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's-length purchaser multiplied by either:
(1) The royalty rate in your lease; or
(2) The royalty rate that BLM prescribes or calculates under 43 CFR
3211.17. See Sec. 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 Sec.
206.353 and Sec. 206.354 of this part, multiplied by the royalty rate
in your lease. See Sec. 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 Sec. 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 Sec. 206.361 for additional provisions applicable to
determining gross proceeds under arm's-length sales. You may not reduce
gross proceeds by any deductions.
Sec. 206.353 How do I determine transmission deductions?
(a) If you determine the value of your geothermal resources under
Sec. 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 Sec. 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
[[Page 24462]]
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 Sec. 218.302). You are entitled
to a credit for or refund of any overpaid royalties.
(n) In conducting reviews and audits, MMS may require you to submit
arm's-length transmission contracts, production agreements, operating
agreements, and related documents and all other data used to calculate
the deduction. You must comply with any such requirements within the
time MMS specifies. Recordkeeping requirements are found at part 212 of
this chapter.
(o) At the completion of transmission line dismantlement and
salvage operations, you may report a credit for or request a refund of
royalties in an amount equal to the royalty rate times the amount by
which actual transmission line dismantlement costs exceed actual income
attributable to salvage of the transmission line.
Sec. 206.354 How do I determine generating deductions?
(a) If you determine the value of your geothermal resources under
Sec. 206.352(b)(1)(i) of this subpart, you may deduct your reasonable
actual costs incurred to generate electricity from the plant tailgate
value of the electricity (usually the transmission-reduced value of the
delivered electricity). You may deduct the actual costs you incur for
generating electricity under your arm's-length power plant contract.
(b)(1) You must base your generating costs deduction on your actual
annual costs associated with the construction and operation of a
geothermal power plant.
(i) You must determine your monthly generating deduction by
multiplying the annual generating cost rate (in dollars per kilowatt-
hour) by the amount of plant tailgate electricity measured (or
computed) for the reporting month. The generating cost rate is
determined from the annual amount of your plant tailgate electricity.
(ii) You must redetermine your generating cost rate annually either
at the beginning of the same month of the year in which the power plant
was placed into service or at a time concurrent with the beginning of
your annual corporate accounting period. The period you select must
coincide with the same period chosen for the transmission deduction
under Sec. 206.353(b)(1). After you choose a deduction period, you may
not later elect to use a different deduction period without MMS
approval.
(2) Your generating costs are your actual power plant costs during
the reporting period, including:
(i) Operating and maintenance expenses under paragraphs (d) and (e)
of this section;
(ii) Overhead under paragraph (f) of this section; and either
(iii) Depreciation under paragraphs (g) and (h) of this section and
a return on undepreciated capital investment under paragraphs (g) and
(i) of this section; or
(iv) A return on capital investment in the power plant under
paragraphs (g) and (j) of this section.
(c)(1) Allowable capital costs under paragraph (b) of this section
are generally those for depreciable fixed assets (including costs of
delivery and installation of capital equipment) that are an integral
part of the power plant or are required by the design specifications of
the power conversion cycle.
(2)(i) You may include a return on capital you invested in the
purchase of real estate for a power plant site if:
(A) The purchase is necessary; and,
(B) The surface is not part of the Federal lease.
(ii) The rate of return will be the same rate determined under
paragraph (k) of this section.
(3) You may not deduct the costs of gathering systems and other
production-related facilities.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Auxiliary fuel and/or utilities used to operate the power plant
during down time;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating
expense.
(e) Allowable maintenance expenses include:
(1) Maintenance of the power plant;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses
that you can document.
(f) Overhead directly attributable and allocable to the operation
and maintenance of the power plant is an allowable expense. State and
Federal income taxes and severance taxes and other fees, including
royalties, are not allowable expenses.
(g) To compute costs associated with capital investment, a lessee
may use either depreciation with a return on undepreciated capital
investment, or a return on capital investment in the power plant. After
a lessee has elected to use either method, the lessee may not later
elect to change to the other alternative without MMS approval.
(h)(1) To compute depreciation, you must use a straight-line
depreciation method based on the life of the geothermal project,
usually the term of the electricity sales contract, or other
depreciation period acceptable to MMS. You may not depreciate equipment
below a reasonable salvage value.
(2) A change in ownership of the power plant does not alter the
depreciation schedule established by the original lessee-owner for
purposes of computing generating costs.
(3) With or without a change in ownership, you may depreciate a
power plant only once.
(i) To calculate a return on undepreciated capital investment,
multiply the remaining undepreciated capital balance as of the
beginning of the period for which you are calculating the generating
deduction allowance by the rate of return provided in paragraph (k) of
this section.
[[Page 24463]]
(j) To compute a return on capital investment in the power plant,
multiply the allowable capital investment in the power plant by the
rate of return determined pursuant to paragraph (k) of this section.
There is no allowance for depreciation.
(k) The rate of return must be 2.0 multiplied by the industrial
rate associated with Standard & Poor's BBB rating. The BBB rate must be
the monthly average rate as published in Standard & Poor's Bond Guide
for the first month for which the allowance is applicable. You must
redetermine the rate at the beginning of each subsequent calendar year.
(l) Calculate the deduction for generating costs based on your cost
of generating electricity through each individual power plant.
(m)(1) For new power plants or arrangements, base your initial
deduction on estimates of allowable electricity generation costs for
the applicable period. Use the most recently available operations data
for the power plant or, if such data are not available, use estimates
based on data for similar power plants.
(2) When actual cost information is available, you must amend your
prior Form MMS-2014 reports to reflect actual generating cost
deductions for each month for which you reported and paid based on
estimated generating costs. You must pay any additional royalties due
(together with interest computed under Sec. 218.302). You are entitled
to a credit for or refund of any overpaid royalties.
(n) In conducting reviews and audits, MMS may require you to submit
arm's-length power plant contracts, production agreements, operating
agreements, related documents and all other data used to calculate the
deduction. You must comply with any such requirements within the time
MMS specifies. Recordkeeping requirements are found at part 212 of this
chapter.
(o) At the completion of power plant dismantlement and salvage
operations, you may report a credit for or request a refund of royalty
in an amount equal to the royalty rate times the amount by which actual
power plant dismantlement costs exceed actual income attributable to
salvage of the power plant.
Sec. 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 Sec. 206.361 for additional provisions
applicable to determining gross proceeds under arm's-length sales.
Sec. 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:
[GRAPHIC] [TIFF OMITTED] TR02MY07.003
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 Sec. 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 . . .
----------------------------------------------------------------------------------------------------------------
But less than ($/million ($/million
At least . . . . . . gallons) pounds)
----------------------------------------------------------------------------------------------------------------
130............................................................. 140 2.524 0.307
[[Page 24464]]
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:
[GRAPHIC] [TIFF OMITTED] TR02MY07.004
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 Sec. 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.
Sec. 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) f 