[Federal Register Volume 60, Number 214 (Monday, November 6, 1995)]
[Proposed Rules]
[Pages 56007-56033]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-27079]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF THE INTERIOR
Minerals Management Service
30 CFR Parts 202, 206, and 211
RIN 1010 AC02
Amendments to Gas Valuation Regulations for Federal Leases
AGENCY: Minerals Management Service, Interior.
ACTION: Notice of proposed rulemaking.
-----------------------------------------------------------------------
SUMMARY: The Minerals Management Service (MMS) is proposing amendments
to regulations governing the valuation for royalty purposes of natural
gas produced from Federal leases. These changes would add several
alternative valuation methods to the existing regulations. The proposed
rules represent the consensus decisions reached by MMS' Federal Gas
Valuation Negotiated Rulemaking Committee (Committee).
DATES: Comments must be submitted on or before January 5, 1996.
ADDRESSES: Mail written comments, suggestions, or objections regarding
the proposed amendment to: Minerals Management Service, Royalty
Management Program, Rules and Procedures Staff, P.O. Box 25165, MS
3101, Denver, Colorado, 80225-0165. MMS will publish a separate notice
in the Federal Register indicating dates and locations of public
hearings regarding this proposed rulemaking.
FOR FURTHER INFORMATION CONTACT: David S. Guzy, Chief, Rules and
Procedures Staff, Telephone (303) 231-3432, FAX (303) 231-3194.
Minerals Management Service, Royalty Management Program, Rules and
Procedures Staff, P.O. Box 25165, MS 3101, Denver, Colorado, 80225-
0165.
SUPPLEMENTARY INFORMATION: The principal authors of this proposed rule
are Lawrence E. Cobb of MMS, John L. Price of MMS, and Peter Schaumberg
of the Office of the Solicitor. Members of the Federal Gas Valuation
Negotiated Rulemaking Committee also participated in the preparation of
this proposed rule.
I. Introduction
On June 2, 1994, the Secretary of the Interior chartered the
Committee to advise MMS on a rulemaking to address: (1) The valuation
of gas produced from approved Federal unit and communitization
agreements (agreements) (particularly when lessees take less than their
entitled share of production); and (2) the benchmark valuation system
for valuing gas sold under non-arm's-length contracts (59 FR 32944,
June 27, 1994). The Committee's scope was limited to examining values
for gas produced from Federal leases and its original charter did not
include the valuation of gas sold under arm's-length contracts.
However, the Committee was faced with a new gas marketing environment
which has resulted from deregulation of natural gas production and open
access, particularly with the issuance of Federal Energy Regulatory
Commission (FERC) Order No. 636 (Order No. 636) (57 FR 13267, April 16,
1992). To simplify valuation for all types of Federal gas sales
impacted by today's gas market, MMS concurred with the Committee's
recommendation to expand its charter to include the valuation of
Federal gas production under both arm's-length and non-arm's-length
sales contracts.
Members of the Committee included representatives from the American
Petroleum Institute (API), the Council of Petroleum Accountants
Societies (COPAS), the Rocky Mountain Oil and Gas Association (RMOGA),
the Independent Petroleum Association of America (IPAA)/Independent
Petroleum Association of Mountain States (IPAMS), the Natural Gas
Supply Association (NGSA), an independent marketer, representatives of
large independent producers, MMS, and personnel from the States of
Utah, North Dakota, Montana, and New Mexico representing the State and
Tribal Royalty Audit Committee (STRAC).
The Committee agreed to operate based on consensus decision making.
MMS committed to publish as a proposed rulemaking all consensus
decisions. The Committee further agreed that its final report and the
resulting proposed rule would not prohibit any Committee member or his/
her constituents from commenting on this proposed rule or challenging
the final rule, or any order issued under the rule.
The policy of the Department of the Interior is, whenever
practicable, to afford the public an opportunity to participate in the
rulemaking process. All of the sessions of the Committee were announced
in the Federal Register, were open to the public, and provided for an
opportunity for public input. In addition, any interested persons may
submit written comments, suggestions, or objections regarding this
[[Page 56008]]
proposed rule to the location identified in the ADDRESS section of this
preamble.
The rulemaking process has necessarily required that the
Committee's consensus be incorporated into the existing regulations as
well as in new regulations. In some instances, various participants on
the Committee may have longstanding differences of opinion with MMS on
the meaning and interpretation of existing regulations, some of which
may be under administrative or judicial appeal. The incorporation of
the Committee's consensus as expressed in the report into the existing
regulatory framework should not be interpreted or infer that consensus
was also reached on these differences or that they have been waived or
withdrawn.
MMS commends the Committee's ability to compromise and develop a
proposal that would simplify royalty payments on natural gas produced
from Federal leases, while reducing administrative costs, decreasing
litigation costs, and maintaining revenue neutrality.
II. Purpose and Background
In March 1995, the Committee published its final report
(``Committee Report''), which summarizes the consensus decisions of the
20-member Committee. This report forms the basis for the proposals in
this rulemaking and is an essential part of the regulatory history for
this proposed rulemaking. For each recommendation, the report provides
background as to why the Committee considered a regulatory change, the
alternatives discussed, any related negotiation, the final
recommendation, and, if necessary, further explanation of the
recommendation, including examples. You may obtain the report by
contacting the MMS Valuation and Standards Division at (303) 275-7201
or -7234, or by facsimile at (303) 275-7227.
III. Description of Regulatory Proposals
This proposed rulemaking would accomplish two principal purposes.
The first principal purpose is to establish a procedure to value, and
to report and pay royalties on, production for operating rights owners
of Federal leases that are part of mixed agreements, i.e., Federally-
approved agreements that include other than only Federal leases with
the same royalty rate and fund distribution. The second principal
purpose is to provide lessees with alternative methods to value gas
production from Federal leases that would supplement the valuation
procedures in the existing regulations in 30 CFR part 206. However, as
explained later in this preamble, not all leases would qualify for the
alternative valuation methods.
These alternative valuation methods would not apply to Indian
leases. Therefore, as part of this rulemaking, MMS would have to
restructure 30 CFR parts 202 and 206. Basically, the existing
provisions of subpart D of parts 202 and 206 currently applicable to
both Federal and Indian gas would be retained, but would be applicable
only to Indian gas. All references to Federal gas, and those valuation
provisions unique to Federal gas, would be removed. In addition, new
subparts would be created in both parts 202 and 206 for Federal gas.
These new subparts would retain most of the provisions of the existing
regulations applicable to Federal gas (of course, with references to
Indian gas removed). In addition, these new subparts would include the
proposed alternative valuation methods the Committee developed,
including simplified procedures to determine applicable transportation
allowances.
It should be noted that there is a negotiated rulemaking committee
that is considering changes to the procedures for valuing gas
production from Indian leases (60 FR 7152, February 7, 1995). However,
any regulatory changes resulting from that process would affect only
Indian leases and would not directly impact this rulemaking.
A description of the major regulatory changes proposed in this
rulemaking as a result of the Committee's recommendations follows:
Part 202
MMS is proposing a new subpart J for 30 CFR part 202 that would be
applicable only to Federal gas. MMS correspondingly would amend
existing subpart D of part 202 to remove references to Federal gas, but
would preserve all the provisions for valuing Indian gas under that
subpart.
The new subpart J for Federal gas would retain many of the basic
provisions of existing subpart D. Also, based on the Committee's
recommendations, several new provisions related to valuing production
from, or allocable to, Federal leases in agreements would be included
in subpart J.
In new Sec. 202.450(d), MMS is proposing that royalty would be due
on the full share of production allocated to a Federal lease under the
terms of the agreement at the royalty rate specified in the lease. This
would not be a change from the existing rules. The primary proposal is
that for each operating rights owner in the lease, royalty would be due
on its entitled share of production allocable to the lease based on its
percentage ownership. (See the recommendation under section II.D. of
the Committee Report and the definition of ``entitlements'' under new
Sec. 206.451.) Therefore, for an operating rights owner who owns 25
percent of the operating rights for a Federal lease in the agreement,
if 100 MMBtu of gas production are allocable to the lease, royalty is
due on 25 MMBtu.
Notwithstanding that royalties are due from each operating rights
owner based on its entitled share, the operating rights owner may be
able to report and pay royalties on a different basis as will be
discussed later in the preamble with respect to changes to part 211.
Further, for mixed agreements, that is, agreements comprised of
leases with different lessors, royalty rates, and/or funds
distributions, to provide some relief to small operating rights owners
(defined below) who cannot market their entitled share of production
each and every month, MMS is proposing an exception whereby royalties
could be paid monthly on takes (defined under new Sec. 206.451),
subject to an annual adjustment to entitlements. This issue is
addressed in detail in section II.D of the Committee Report (example on
page 68).
New Sec. 202.450(d) also would include procedures to value the
portion of any production to which an operating rights owner is
entitled but does not take. This provision is important because the
operating rights owner must pay royalty on the non-taken portion. In
most cases, value would be based on the weighted average value of the
gas that was taken from the lease. This issue also is addressed in
section II.D of the Committee Report.
Part 206
MMS is proposing a new subpart J for 30 CFR Part 206 that would be
applicable only to valuation of Federal gas. Like part 202, MMS would
amend existing subpart D to remove references to Federal gas, but would
preserve all the provisions for valuing Indian gas under that subpart.
Therefore, Indian gas valuation would not be affected by this
rulemaking.
The new subpart J for Federal gas basically would retain the
valuation provisions of existing subpart D applicable to Federal gas.
In fact, for some gas production from Federal leases, the valuation
rules would not change at all. However, to simplify the rules and to
provide new valuation mechanisms responsive to changes in the gas
market, MMS is proposing alternative valuation rules that would
determine gas values based on published indices. Transportation
[[Page 56009]]
allowance procedures also would be simplified for all producers.
Several of the more important changes are described below.
Section 206.451 Definitions
MMS would retain almost all of the definitions in existing
Sec. 206.151. However, Sec. 206.451 also would include many new
definitions for terms used in the alternative valuation sections and
other new sections of the rules. These definitions are contained in
attachment 5 to the Committee Report. Most of these definitions are
self-explanatory and are best understood when explained below in the
context in which they are used.
MMS is proposing a modified definition for ``gathering'' to assist
in distinguishing that function from transportation. Under this
proposed definition, some movement of gas which is now gathering would
fall within the definition of transportation. This change would be a
fundamental change in existing regulations. Under current regulations,
transportation constitutes movement of gas to a remote market away from
the lease, and gathering constitutes movement of lease production to a
central accumulation and/or treatment point on the lease, unit or
communitized area, or to a central accumulation or treatment point off
the lease, unit or communitized area as approved by BLM or MMS Outer
Continental Shelf (OCS) operations personnel for onshore and OCS
leases, respectively. The change reflected in the proposed rule's
definition is one element of overall negotiated concessions by all
parties involved in the Committee proceedings. The basis for the
proposed change is addressed in section II.E. of the Committee Report.
A new definition also is proposed for ``small operating rights
owner.'' These persons would be granted an exception from the
obligation to report and pay royalties on their entitled share of
production each month, and could pay based on their takes subject to an
annual adjustment to entitlements. This is addressed in Sec. 202.450
and in Sec. 211.18. A small operating rights owner would be defined as
a person who produces less than 6,000 Mcf/day total U.S. gas production
and less than 1,000 bbls/day total U.S. oil production. This includes
production from all domestic properties, Federal and non-Federal. (See
page 67 of the Committee Report.)
Section 206.452 Valuation Standards--Unprocessed Gas
In most respects this section is the same as existing Sec. 206.152.
Therefore, for Federal gas production that is not processed and does
not qualify for the proposed alternative valuation methods, discussed
below, valuation would occur under this section. The valuation
procedures essentially would be the same as under the existing rules in
Sec. 206.152.
However, there are a few changes in this proposed rule. Section
206.452(a)(3) would provide that gas which is sold or otherwise
transferred to the lessee's marketing affiliate (a defined term) would
be valued based upon the sale by the marketing affiliate. Thus, the
applicable valuation procedure would depend on the marketing
affiliate's sale. That sale would determine whether one of the new
alternative valuation methods applies. Therefore, as explained further
below, if the marketing affiliate sells unprocessed gas under an arm's-
length dedicated contract, it could not use the alternative valuation
methods. Other types of gas disposition by the marketing affiliate
might qualify for the alternative valuation methods. Page 15 of the
Committee Report provides a complete explanation of how such gas may be
valued.
Under Sec. 206.452(b), the valuation provisions applicable to gas
sold under arm's-length contracts, value would be determined the same
as under the existing rules, i.e., based on the lessee's gross
proceeds. However, if gas is sold under an arm's-length contract that
is not dedicated (a dedicated contract is a contract where gas is sold
from a specific source--see the definition in Sec. 206.451), and if the
gas production qualifies for valuation under the alternative valuation
methods in Sec. 206.454, then the lessee may elect to use those
alternative valuation methods instead of the arm's-length valuation
procedures in Sec. 206.452(b). What gas qualifies for valuation under
Sec. 206.454 is discussed below in the preamble for that section. This
issue is covered in detail in section II.A. of the Committee Report.
Paragraph (c) of Sec. 206.452 applies to gas that is not sold under
an arm's-length contract. It would provide that the lessee first must
determine whether the gas qualifies for valuation under the new
alternative valuation methods in Sec. 206.454. Those qualification
standards are discussed later in this preamble with respect to
Sec. 206.454. If the gas qualifies for valuation under Sec. 206.454,
the lessee would be required to use that section. (See recommendation
on page 15 of the Committee Report.) If the gas does not qualify for
valuation under Sec. 206.454, then the benchmark valuation procedures
under Sec. 206.452(c) for non-arm's-length dispositions would apply.
These procedures are the same as those under existing Sec. 206.152.
This issue is also discussed in detail in section II.A. of the
Committee Report.
Of all the issues the Committee addressed, only one issue remains
outstanding--improved benchmarks for valuing Federal gas sold under
non-arm's-length contracts (i.e., Secs. 206.452(c) (1), (2) and (3))
when the gas is not subject to valuation under the new provisions of
Sec. 206.454. This issue, representing a small portion of overall
Federal gas production, is the only issue on which the Committee did
not reach consensus. (See section II.B. of the Committee Report.) MMS
plans to issue a separate rulemaking that will improve the existing
benchmarks. For that rulemaking, MMS will take under consideration the
deliberations of the committee and invites any interested party to
submit suggestions for improvements to the benchmarks with comments
submitted on this proposed rulemaking.
Paragraph (g) of Sec. 206.452 is the provision that corresponds to
existing Sec. 206.152(i). The existing provision states that
``Notwithstanding any other provision of this section,'' value cannot
be less than the gross proceeds accruing to the lessee for lease
production.
MMS is proposing to amend this section to eliminate the above-
quoted introductory clause and to expressly exclude gas valued under an
index-based method under Sec. 206.454. This change is necessary to make
it clear that if a provision of Sec. 206.452 permits a lessee to value
gas using an index-based method under the new alternative valuation
methods in Sec. 206.454, it would not be required to compare that
index-based value to its gross proceeds.
Paragraph (i) of Sec. 206.452, which corresponds to existing
Sec. 206.152(j), also would be amended to exclude gas valued using an
index-based method under Sec. 206.454. The diligence standard addressed
in this paragraph is inapplicable to index-based valuation.
Section 206.453 Valuation Standards--Processed Gas
This section applies to the valuation of gas that is processed by
the lessee. The changes proposed to modify this section from existing
Sec. 206.153 basically parallel the changes discussed in the previous
section regarding the modifications in proposed Sec. 206.452 from
existing Sec. 206.152. However, because this section addresses
valuation of residue gas and gas plant products, there are some
additional differences.
Under Sec. 206.453(b), the valuation provision applicable to
residue gas and gas plant products sold under arm's-
[[Page 56010]]
length contracts, value would be determined the same as under the
existing rules; i.e., based on the lessee's gross proceeds.
However, if residue gas is sold under an arm's-length contract that
is not dedicated (see the definition of ``dedicated'' in Sec. 206.451),
and if the gas production qualifies for valuation under the alternative
valuation methods under Sec. 206.454, then the lessee could elect to
apply those provisions instead of the arm's-length valuation procedures
in Sec. 206.453(b). This issue is discussed with unprocessed gas in
section II.A. of the Committee Report. Likewise, for NGL's, elemental
sulfur and drip condensate associated with such residue gas, the lessee
may elect to apply Sec. 206.454 to value those products. The
alternative valuation methods in Sec. 206.454 would not be applicable
to carbon dioxide, nitrogen or other non-Btu gas plant products.
Section II.C. of the Committee Report provides a more complete
explanation of this issue.
Under Sec. 206.453(c), for residue gas or gas plant products not
sold under an arm's-length contract, the lessee first must determine
whether the residue gas or gas plant product is subject to valuation
under Sec. 206.454. For residue gas that is subject to Sec. 206.454,
the lessee would be required to use that section. (This proposal is
explained on page 15 of the Committee Report.) Otherwise, valuation
under this section would be the same as under existing Sec. 206.153.
The proposed changes to the remaining paragraphs of Sec. 206.453
are the same as those discussed above for Sec. 206.452. Some additional
changes applicable to both unprocessed gas and processed gas (both new
Secs. 206.452 and 206.453) not previously discussed are:
--MMS would delete all references in this new subpart to FERC maximum
lawful prices because of deregulation.
--All references to warranty contracts would be eliminated because MMS
does not believe there are any still in effect.
--The provisions of Sec. 206.155 of the existing rules requiring dual
accounting for certain Federal gas production (not Indian gas
production) are not included in proposed subpart J based on the
Committee's recommendation under section II.H. of the Committee Report.
Section 206.454 Alternative Valuation Standards for Unprocessed Gas
and Processed Gas
This section is the principal new section for this proposed rule.
It would add alternative gas valuation methods to the existing rules
using published index prices and other criteria that should facilitate
valuation in many circumstances.
However, this alternative valuation section would not be applicable
to all gas. First, it would not apply at all to unprocessed gas or
residue gas sold under a dedicated arm's-length contract, defined in
proposed Sec. 206.451 as a contractual commitment to deliver gas from a
specific lease or well. For a discussion of why the Committee excluded
gas sold under arm's-length dedicated contracts see section II.A.3 of
the Committee Report.
Second, this alternative gas valuation section is applicable only
to gas production from certain leases. Those leases must be in a zone
(MMS-defined geographic area containing blocks or fields as defined in
proposed Sec. 206.452) with an active spot market and published
indices, or be deepwater OCS leases. A complete discussion of these
zones begins on page 48 of the Committee Report.
An active spot market is defined in proposed Sec. 206.451 as a
market where one or more MMS-acceptable publications publish bidweek
prices (or if bidweek prices are not available, first-of-the-month
prices) for at least one index pricing point in the zone. An index
pricing point, or IPP, also is a defined term in Sec. 206.451. Page 19
of the Committee Report includes diagrams of IPP's for various
connection situations.
If the production does not qualify for valuation under this section
because the lease is not in a zone with an active spot market with
published indices, then the lessee would be required to value the
production under Secs. 206.452 or 206.453, as applicable. It also
should be noted that this section would not apply to carbon dioxide,
nitrogen, or other non-Btu gas plant products because all the
alternative valuation methods are Btu-based.
If the production qualifies for valuation under this section, then
the lessee would have a series of elections and choices for valuation
based on how the production is sold.
1. For unprocessed gas sold under an arm's-length non-dedicated
contract, the lessee could elect to use either an index-based method
under this section (described below) or the gross proceeds valuation
provision of Sec. 206.452(b)(1).
2. For unprocessed gas sold non-arm's-length, the lessee must value
the gas under this section using either an index-based method or, if
the gas is sold to the lessee's affiliated purchaser (who is not a
marketing affiliate) and if that affiliate sells the gas under an
arm's-length contract, then the affiliate's gross proceeds (determined
under Sec. 206.452) are the value. Sales to marketing affiliates would
be excluded here because, as provided in Sec. 206.452(a)(3), valuation
would be required on the basis of the marketing affiliate's sale.
3. For residue gas sold under an arm's-length non-dedicated
contract, the lessee could elect to use either an index-based method
under this section or the gross proceeds valuation procedure of
Sec. 206.453(b)(1).
4. For residue gas sold non-arm's-length, the procedure is the same
as for unprocessed gas sold non-arm's length in paragraph 2 above.
5. If the lessee values residue gas using an index-based method,
then the lessee has a choice on how to value the NGL's, elemental
sulfur and drip condensate associated with that residue gas. It could
either use the same index-based price per MMBtu used to value the
associated residue gas, or it could use the procedures in Secs. 206.453
(b) or (c) depending on whether the products are sold arm's-length or
non-arm's-length.
6. If the lessee values the residue gas under an arm's-length non-
dedicated contract using Sec. 206.453(b), or if the lessee uses its
affiliate's arm's-length gross proceeds under this section
(Sec. 206.454(a)(2)(ii)(B)), then the lessee also has a choice on how
to value the NGL's, elemental sulfur and drip condensate. It could use
the same price per MMBtu used to value the associated residue gas.
Alternatively, it could use Secs. 206.453 (b) or (c), depending on
whether the products are sold arm's-length or non-arm's-length.
Elections 1 and 2 are explained in section II.A.3.b. of the
Committee Report. Elections 3, 4, 5, and 6 are explained in section
II.C. of the Committee Report.
Paragraph (a)(3) of Sec. 206.454 would provide four conditions to
using the alternative valuation methods just described. First, there
must be an active spot market for the gas subject to the valuation. As
explained above, active spot market is defined in Sec. 206.451.
Second, the gas must actually flow, or be capable of flowing,
through at least one pipeline with at least one published index
applicable to the zone.
Third, for all leases in a zone:
1. All unprocessed gas and residue gas sold under an arm's-length
non-dedicated contract must be valued the same under this section.
Therefore, for all such gas in the zone the lessee must make the same
election to use either an index-based method or Secs. 206.452(b) or
206.453(b), as applicable.
2. All unprocessed gas and residue gas produced from leases in the
zone not sold under an arm's-length contract
[[Page 56011]]
must be valued using the same method where the lessee has an election.
Therefore, if for one lease the lessee's affiliate sells the gas arm's-
length and the lessee elects to use that value instead of an index-
based value, for every other lease in the zone where the affiliate
sells arm's-length the lessee must use the affiliate's arm's-length
gross proceeds for valuation. If there are other leases in the same
zone where, for example, the lessee's affiliate did not sell the gas
under an arm's-length contract, under paragraphs (a)(1)(ii) or
(a)(2)(ii) of Sec. 206.454 there is no election for those leases and
the lessee would be required to use index for those situations.
3. For all residue gas from leases in the zone valued under
paragraphs (a)(2) (i) or (ii) of Sec. 206.454 using the index-based
method, the lessee must value all the NGL's, elemental sulfur and drip
condensate associated with that residue gas using the same method.
Thus, the lessee must use either an index-based method to value all
such products in the zone or it must use Secs. 206.453 (b) or (c), as
applicable.
4. For all residue gas from leases in the zone valued under
paragraphs (a)(2)(i) or (a)(2)(ii)(B) of Sec. 206.454 using a gross
proceeds method, the lessee must value all the NGL's, elemental sulfur
and drip condensate associated with that residue gas using the same
method. Therefore, the lessee must use either the price per MMBtu of
the associated residue gas to value all such products in the zone or it
must use Secs. 206.453 (b) or (c), as applicable.
Fourth, the lessee's elections for valuation in each zone must be
made for a period of 2 calendar years. If the lessee adds production
from leases in the zone during that 2-year period, or acquires new
leases in the zone, that production would be valued under the same
election.
If the lessee does not satisfy all of the four above-described
criteria, then it must value production under Secs. 206.452 and
206.453. These criteria are listed on page 16 of the Committee Report.
Paragraph (a)(6) of Sec. 206.454 would address an issue that the
Committee did not consider. It involves situations where a lessee
entered into a gas contract settlement prior to the effective date of a
final rule in this matter, and actually receives the settlement payment
before or after the effective date of the final rule. Under current MMS
interpretation of the gross proceeds requirements, the payment the
lessee receives under that gas contract settlement may be attributable
in whole or in part to production that occurs after the effective date
of this rule. This paragraph would provide that any portion of the gas
contract settlement payment attributable to that production would be
subject to royalty in addition to any index-based or other value
established under Sec. 206.454.
By way of illustration, assume that the lessee entered into a gas
contract settlement and received a lump-sum payment in January 1995 for
a gas sales contract for lease production that would have been in
effect until June 1997. Assume further that under MMS' current royalty
valuation procedures, MMS would consider the lump-sum payment to be
attributable pro rata to the production that occurs from the lease
until June 1997 at the rate of $0.10 per MMBtu. Under paragraph (a)(6)
of Sec. 206.454, if the index-based value determined for production for
May 1996 were $2.00, the lessee would be required to pay royalty on
$2.10.
Paragraph (a)(6) of Sec. 206.454, as proposed, does not require
that royalty be paid on any amounts attributable to gas contract
settlements entered into after the effective date of the rule where the
lessee uses an index-based or other value under Sec. 206.454. (Of
course, MMS does consider certain of such payments to be subject to
royalty for lessees using gross proceeds to value production, which is
not addressed in this paragraph.) MMS specifically requests comment on
whether amounts for gas contract settlements entered into after the
rule's effective date should be subject to royalty for lessees who use
index-based or other values under Sec. 206.454.
Paragraph (b) of Sec. 206.454 would explain how to determine the
index value for gas production when the lessee must use, or elects to
use, an index-based method. Determination of the index value depends on
whether the gas flows or could flow through a single connect, a split
connect or a multiple connection. This determination must be made for
each well on a lease because different wells may have different
connections. A discussion of determining index values begins on page 18
of the Committee Report under Index Pricing Points.
For a single connect, the index value is the index price for the
first index pricing point (IPP). For that IPP, the lessee will have
selected a publication from the MMS-acceptable list in accordance with
Sec. 206.454(d). The price published in that publication for that month
for that IPP would be used to value all production from the well that
month.
If the well has a split connect or a multiple connection, the
lessee would be required to elect one of two methods to calculate the
index value:
1. Weighted-average index value. This index would be calculated by
first multiplying the volume of gas from the well actually flowing to
each IPP by the applicable index price for that IPP (using the
publication the lessee selected under paragraph (d) of Sec. 206.454).
(Example: IPP1--10,000 MMBtu x $1.20/MMBtu = $12,000; IPP2--
20,000 MMBtu x $1.30/MMBtu = $26,000; IPP3--10,000 MMBtu x $1.20/
MMBtu = $12,000). The numbers for each IPP are then added, equaling a
total of $50,000. That sum is divided by the total volume (40,000
MMBtu) and the resulting quotient ($1.25/MMBtu) is the index value. The
amount of gas actually flowing to each IPP is determined by using the
nominations confirmed at the first of the month or the total
nominations confirmed during the month, applied consistently for the
two-year election period. If the actual flow of the gas during the
month is different from the flow determined by the confirmed
nominations used to calculate the value under this paragraph, the
weighted average index value will not be recalculated using the actual
flow volume. This index value would apply to all production from the
well no matter which IPP the gas actually flowed through.
2. Fixed index value. First, for each IPP through which gas from
the well flows or could flow, determine the average of the applicable
monthly index prices for the previous calendar year using the
publication selected for that year. Array the average prices determined
for each IPP from highest at the top to lowest at the bottom. If there
are only two IPP's, select the IPP associated with the highest average
price. If there are three or more IPP's, select the IPP associated with
the second highest average price. For whichever IPP is selected, go to
the publication selected for that IPP for the current year (which could
be a different publication than the one used the previous year). The
index price for the current month for the IPP in that publication is
the index value for all gas production from the well that month no
matter where the gas actually flows. Example: Last year's 12-month
average and this month's index price for each IPP through which the
lessee's gas flows or could flow are:
------------------------------------------------------------------------
Last year's
average Current month
------------------------------------------------------------------------
IPP2............................ $1.89/MMBtu....... $2.05/MMBtu.
[[Page 56012]]
IPP3............................ $1.86/MMBtu....... $2.00/MMBtu.
IPP1............................ $1.85/MMBtu....... $2.10/MMBtu.
------------------------------------------------------------------------
The second IPP in the array, IPP3, is used to value production in
the current year. For this month, the index price in the publication
selected for IPP 3 is $2.00/MMBtu. This index value is used to value
all production from the well.
If the result of the calculation is that the selected average index
price (either the highest or second highest, as applicable) is
identical to another average index price, then the calculation of the
average index prices for the previous year would have to be redone to
eight decimal places, and the process would then proceed the same.
The lessee would be required to elect to use either the weighted
average index method or the fixed index method for the two-calendar-
year election period. The lessee also would have to apply the same
elected method to all wells connected to the same split connect or
multiple connection. But the lessee could use the weighted average
index method for one split connect in a zone and the fixed index method
for another split connect in the same zone. For the Committee's
discussion of this issue, see pages 20-23 of the Committee Report.
Paragraph (c) of Sec. 206.454 would provide that the lessee would
be entitled to deduct an applicable transportation allowance from the
index value to determine the value for royalty purposes. Transportation
allowances are addressed later in this preamble.
Paragraph (d) of Sec. 206.454 would explain how a lessee selects an
acceptable publication for the index price from a list of acceptable
publications that MMS periodically will publish in the Federal
Register. (See Committee Report discussion under Choice of Index
Publication, beginning on page 29.)
Paragraph (e) of proposed Sec. 206.454 relates to determination of
the final safety net median value. In summary, as is explained in
substantial detail at pages 33 to 45 of the Committee Report, the
lessee would be required to compare its alternative value determined
under this section to the final safety net median value for each zone.
If its alternative value is lower than the final safety net median
value (which would be based on arm's-length gross proceeds valuation
information reported to MMS on Form MMS-2014 and other sources), then
the lessee would be required to pay additional royalty and, in some
cases, late payment interest.
Paragraphs (e)(1) through (e)(3) of Sec. 206.454 would explain in
substantial detail what reported information and other data MMS would
use to calculate the final safety net median value.
Paragraph (e)(4) of Sec. 206.454 would explain that the final
safety net median value for a zone would be calculated by arraying the
prices per MMBtu derived from the collected data from highest to lowest
(at the bottom). The final safety net median value would be that price
at which 50 percent plus 1 MMBtu of the production (starting from the
bottom) is sold. This value would apply for a calendar year.
The proposed rules would provide in paragraph (e)(7) of
Sec. 206.454 that a lessee could request a technical procedural review
of the final safety net median value from the Associate Director for
Royalty Management. The Associate Director's decision following that
review would be a final Departmental decision not subject to further
administrative review.
Paragraphs (e)(8) through (e)(10) of Sec. 206.454 would explain how
the lessee must determine whether it owes additional royalty based on
the difference between the annual weighted average value of its
production determined under this section and the final safety net
median value for each zone. If its annual weighted-average value is
lower than the final safety net median value, this proposed rule
explains in detail what percentage of the difference the lessee must
pay as additional royalty. That percentage depends upon what product is
being valued (e.g. unprocessed gas, residue gas, or plant products) and
which alternative valuation method is used. If the lessee's annual
weighted average value is higher than the final safety net median
value, it would owe no additional royalty and would not receive any
credit or refund.
Under paragraph (e)(11) of Sec. 206.454, for leases on certain OCS
deepwater blocks that MMS specifies, the additional royalty
calculations under paragraphs (e)(8), (e)(9), and (e)(10) would be made
using adjusted transportation allowances because of the unusual
distances involved. MMS also would use the final safety net median
value for the closest zone where production flows or could flow.
Paragraph (e)(6) of Sec. 206.454 would require that MMS publish the
final safety net median value within 2 years after the end of the
relevant calendar year. The Committee did not address the consequences
of MMS not publishing the final safety net median value within two
years. MMS requests comments on the appropriate consequences in this
event. Options could include: (1) Using the initial safety net median
value; or (2) having no additional royalties due; or (3) suspending
interest until the final safety net median value is published.
Paragraph (e)(12) of Sec. 206.454 would provide that MMS will
endeavor to publish an initial safety net median value within 6 months
following the end of the calendar year to give lessees an up-front
approximation of the safety net median value. The lessee could then pay
any additional royalty that may be due. If the lessee made an estimated
payment following publication of the initial safety net median value
and if the final safety net median value is lower than the initial
safety net median value, then the lessee would receive a credit or
refund of its overpayment.
This paragraph also would provide that the lessee could report any
additional royalty payments using a one-line entry on Form MMS-2014 for
each zone. If the lessee reports an estimated payment following the
initial safety net median value, then following publication of the
final safety net median value it must file an amended Form MMS-2014
adjusting any payments for each zone, if necessary. On this amended
report, the lessee may recoup any overpayment by filing a credit
adjustment. This first credit adjustment would not be subject to
section 10 of the Outer Continental Shelf Lands Act, 43 U.S.C.
Sec. 1339, for the same reasons that adjustment of an estimated
transportation or processing allowance from estimated to actual is not
subject to section 10. See 30 CFR 230.461(f). However, if the lessee
makes a second adjustment to that line for any zone, it would be
subject to all of section 10's provisions including the 2-year limit
and the approval requirements.
Finally, under this section, late payment interest would not accrue
on any additional royalty owed until the date MMS publishes the initial
safety net value. Therefore, for example, for calendar 1997, if the
initial safety net value is published June 30, 1998, and if the lessee
makes an estimated payment July 31, 1998, it would owe only 1-month's
interest. If it did not pay any additional royalty until the final
safety net median value is published, or if its estimated payment were
deficient, interest would run from June 30, 1998, until the deficient
royalty payments were made. The issue of interest is explained on pages
42-43 of the Committee Report.
These proposed rules would require in paragraph (e)(5) of
Sec. 206.454 that the final safety net median value must be based on a
representative sample of data
[[Page 56013]]
reflecting gross proceeds sales. Paragraph (f) of Sec. 206.454 would
explain how that representative sample would be determined. (See
Representative Sample discussion beginning on page 44 of the Committee
Report.)
Paragraph (g) of Sec. 206.454 would provide that MMS would publish
in the Federal Register the zones with an active spot market and
published indices that are eligible for an index-based valuation
method. MMS would consider such criteria as common markets served,
common pipeline systems, simplification and easy identification, such
as an offshore block or an onshore county. Under paragraph (h) of
Sec. 206.454, MMS would hold a technical conference if necessary and
publish notice in the Federal Register that a zone is disqualified for
the following calendar year. That notice would be published by
September 1 of the preceding year.
Section 206.456 Transportation Allowances--General
If a lessee values gas at a point off the lease, this section would
authorize a transportation allowance for the reasonable costs of
transporting identifiable, measurable gas to that point. This section
would also provide for an exception whereby MMS could approve an
allowance for the transportation of bulk deepwater production upon
request of the lessee. No allowance would be authorized for gathering
costs. The basis for this proposal is contained in section II.E. of the
Committee Report. The Committee Report used the term ``location
differential,'' but this proposed rule uses the term ``transportation
allowance'' for the same purpose. The transportation allowance would be
applicable to unprocessed gas, residue gas and gas plant products, and
would be available both in situations where production is valued under
Secs. 206.452 and 206.453, as well as under the new alternative
valuation methods in Sec. 206.454.
If gas flows (or, for some alternative valuation methods, gas could
flow) through more than one pipeline segment to the point where value
is determined, the applicable transportation allowance would be based
on the total allowance for each segment determined under Sec. 206.457.
Therefore, if the gas flows through a jurisdictional pipeline and then
a non-jurisdictional pipeline before it gets to the point where value
is determined, the allowance would be based on the total for both
segments.
MMS would add a new provision in Sec. 206.456(a)(2) providing that
the lessee's costs of compression downstream of the facility
measurement point (FMP), incurred either by the payment of such cost
under a contract or by performance of the compression by the lessee, is
allowable as a transportation cost. Also, under this new provision,
costs of boosting or compressing residue gas after processing would be
part of the lessee's transportation allowance for residue gas. This
issue is addressed in section II.F. of the Committee Report.
The remaining provisions are the same as in existing Sec. 206.156,
including limitations on the allowances.
Section 206.457 Determination of Transportation Allowances
This section would be organized differently from existing
Sec. 206.157. In addition to determining whether the transportation
cost is arm's-length or non-arm's-length, the lessee would have to
differentiate in some cases between jurisdictional pipelines (defined
in Sec. 206.451 as a pipeline with a rate regulated by FERC or a state
agency) and non-jurisdictional pipelines (not FERC or state-agency
regulated). This distinction is based on the Committee's
recommendations for classifying pipeline systems on pages 23-24 of the
Committee Report.
Paragraph (a) of Sec. 206.457 would explain that if the lessee uses
gross proceeds to value its gas, then the transportation allowance
would be determined under paragraphs (b) or (c) of Sec. 206.457,
depending upon whether the pipeline is jurisdictional or non-
jurisdictional and whether or not the transportation arrangement is
arm's-length. If the lessee elects an index-based method to value its
gas, then, as provided in paragraph (d) of Sec. 206.457, the
transportation allowance would also be determined under paragraphs (b)
or (c) of Sec. 206.457, if the lessee actually transports some gas to
the IPP used for value. If the lessee elects an index-based method but
does not flow any gas to the IPP used for value, then the
transportation allowance would be determined under paragraph (d)(5) of
Sec. 206.457.
Paragraph (b) of Sec. 206.457 would apply if the lessee determines
value under Sec. 206.452 or 206.453, or under the provisions applicable
to arm's-length sales of gas by the lessee's affiliate
(Secs. 206.454(a)(1)(ii)(B) and 206.454(a)(2)(ii)(B)). If the value is
determined under those sections and if the lessee transports either
unprocessed gas, residue gas, gas plant products, or drip condensate
through a jurisdictional pipeline, the transportation allowance would
be based on the reasonable, actual contract rate paid. (See Committee
recommendation on page 23 of the Committee Report.) This would apply to
both arm's-length and non-arm's-length situations. Similarly, if the
lessee values under those sections and transports production though a
non-jurisdictional pipeline under an arm's-length contract, the
transportation allowance also would be based on the reasonable, actual
contract rate paid. (See Committee recommendation on page 24 of the
Committee Report.)
The remaining provisions of paragraph (b) are essentially the same
as the arm's-length contract rate provisions in existing Sec. 206.157.
Paragraph (c) of Sec. 206.457 would apply in situations where value
is determined under Secs. 206.452 and 206.453 and transportation is
through a non-jurisdictional pipeline under a non-arm's-length contract
or no contract situations (see page 24 of the Committee Report). The
transportation allowance provision that would apply would depend upon
how much gas is transported through that pipeline under arm's-length
transportation contracts.
If 30 percent or less of the gas in the pipeline flows under arm's-
length transportation contracts, the allowance would be based on
either:
(1) The lessee's reasonable actual costs determined under paragraph
(c)(2) of Sec. 206.457, which contains basically the same cost
calculations as under the existing regulations; or
(2) A rate of $0.02/MMBtu for OCS leases or a de minimis rate for
onshore leases not to exceed $0.09/MMBtu. MMS would periodically
determine the onshore rate based upon available transportation cost
data and publish it in the Federal Register. The rate would be
applicable for 1 calendar year.
If more than 30 percent of the gas is transported under arm's-
length contracts, the lessee could use either:
(1) Its reasonable actual costs for transportation; or
(2) A rate determined by arraying all of the arm's-length rates for
the pipeline from highest at the top to the lowest at the bottom. The
applicable rate would be the one closest to the 25th percentile from
the bottom. An example is provided on page 26 of the Committee Report.
As noted above, the provisions of Sec. 206.457(c)(2) used to
determine reasonable actual costs are essentially the same as under
existing Sec. 206.157(b)(2). A new provision would be added to
paragraph (c)(2)(iv)(A) of Sec. 206.457 related to depreciation for
purchased systems. This issue is discussed on pages 28 and 29 of the
Committee Report.
Paragraph (d) of Sec. 206.457 would apply to determine
transportation
[[Page 56014]]
allowances each month for gas valued under the new index-based
valuation methods in Sec. 206.454(b). The transportation allowance
would be determined by the type of connection to the well (i.e., single
connect, split connect or multiple connection) and the type of index
valuation method used. This issue is discussed under section II.A. of
the Committee Report under Location Differential (LD).
Under Sec. 206.457(d)(2), for a single connect, the transportation
allowance for volumes actually transported to the IPP where value is
determined would be determined under Sec. 206.457 (b) or (c), as
applicable. Thus, for example, if it is a jurisdictional pipeline or a
non-jurisdictional pipeline with an arm's-length contract,
Sec. 206.457(b) would apply and the allowance would be based on the
lessee's contract rate. By contrast, if it is a non-jurisdictional
pipeline and the lessee has a non-arm's-length transportation contract,
the allowance would be determined under Sec. 206.457(c) based on the
lessee's actual costs or one of the other alternatives in that
paragraph. These proposals are listed on pages 23-24 of the Committee
Report.
If the lessee's gas does not actually flow to the IPP, then the
transportation allowance for that pipeline would be determined under
Sec. 206.457(d)(5) discussed below.
Paragraph (d)(3) of Sec. 206.457 applies to situations where the
lessee's gas production from a well with a split connect or multiple
connection is valued using the weighted average index method under
Sec. 206.454(b)(2)(i). The lessee first would be required to determine
the applicable transportation allowance, using either paragraph (b) or
(c) of Sec. 206.457, as applicable, for gas volumes actually
transported to each IPP used in the calculation to value the lessee's
gas from the well. Thus, if there are five IPP's used in the weighted
average calculation, five allowances must be calculated. The lessee
then must determine the volume weighted average transportation
allowance per MMBtu for those five pipelines. That rate per MMBtu could
then be deducted as the transportation allowance against the weighted
average index value per MMBtu for all the lessee's production from the
well. Page 25 of the Committee Report provides an example of
calculating the weighted average transportation allowance.
Finally, paragraph (d)(4) of Sec. 206.457 applies where the
lessee's gas production from a well with a split connect or multiple
connection is valued using the fixed index value method under
Sec. 206.454(b)(2)(ii) and where some of the lessee's gas actually
flows to the IPP selected for value. In that situation, the
transportation allowance for all the lessee's gas from the well would
be determined based on the lessee's transportation allowance rate per
MMBtu, determined under Sec. 206.457 (b) or (c), as applicable, to
transport gas to that IPP. Therefore, if IPP5 is the selected IPP for
valuation purposes, and 20 percent of the lessee's gas from the well
actually flows to that IPP, the transportation allowance rate per MMBtu
for the pipeline to IPP5 also would be applied to the other 80 percent
of the lessee's gas from the same well. If none of the lessee's gas
actually flows to that IPP, then the lessee must use Sec. 206.457(d)(5)
to determine the allowance.
As noted above, there may be situations where gas does not actually
flow to an IPP that is used to determine value. However, a
transportation allowance rate must be determined for the pipeline or
pipelines, to that IPP. Under Sec. 206.457(d)(5), if it is a
jurisdictional pipeline, the rate would be the maximum interruptible
transportation (IT) rate for the pipeline that month (see page 23 of
the Committee Report).
If the pipeline is a non-jurisdictional pipeline and the lessee is
not affiliated with the owners of that pipeline, the rate would be
based on either:
(1) A rate MMS would calculate for the lessee for a fee to cover
MMS administrative costs; or
(2) A rate determined by the lessee based on such factors as rates
paid under arm's-length contracts for that pipeline, the pipeline's
published rates, and rates the lessee actually pays to the pipeline
(see page 24 of the Committee Report).
If it is a non-jurisdictional pipeline and the lessee is affiliated
with the owners of that pipeline, the applicable transportation
allowance rate would be determined under the cost-based provisions of
Sec. 206.457(c) applicable to other non-arm's-length or no contract
situations (see page 24 of the Committee Report).
Paragraph (e) of Sec. 206.457 would require that the transportation
allowance must be reported as a separate line item on the Form MMS-2014
unless MMS approves a different procedure (see page 23 of the Committee
Report). However, all gas transportation allowance forms would be
eliminated to make reporting simple. See section II.G. of the Committee
Report for the Committee's recommendation on this issue.
The other paragraphs relating to interest assessments, adjustments,
and actual or theoretical losses are essentially the same as under the
existing rules. Certain changes would be made to account for the
reduction in the reporting procedures.
Section 206.458 Processing Allowances--General
This section, which would allow a deduction for the reasonable
actual costs of processing when value is determined under Sec. 206.453,
is the same as existing Sec. 206.158. Therefore, the same limitations
on allowances would apply as under the existing rules. No processing
allowance would be applicable to gas plant products valued under
Sec. 206.454.
Section 206.459 Determination of Processing Allowances
This section would explain how the processing allowance is
determined based on whether the lessee has an arm's-length or non-
arm's-length (or no contract) processing agreement. This section is the
same as existing Sec. 206.159 with a few changes. Under
Sec. 206.459(b)(2)(iv)(A), which is part of the actual cost calculation
for non-arm's-length or no contract processing situations, a new
provision would be added regarding depreciation for newly acquired
facilities. The issue regarding depreciation is discussed on page 24 of
the Committee Report.
The most significant change would be in paragraph (c) of
Sec. 206.459. As with transportation allowances, the reporting
requirements would be simplified by eliminating all processing
allowance forms. The lessee only would be required to report the
processing allowance as a separate line on the Form MMS-2014 unless MMS
approves a different reporting procedure. (See section II.G. of the
Committee Report.) Of course, all allowances are subject to audit, and
the interest assessment and adjustment provisions in Secs. 206.459 (d)
and (e) would apply.
Part 211
In a separate rulemaking, MMS has proposed regulations regarding
who is liable for royalty and other payments due on Federal and Indian
leases (60 FR 30492, June 9, 1995). That rulemaking also explains who
is required to report and pay royalties. MMS does not address in that
other rulemaking the reporting requirements for mixed agreements and,
instead, is proposing those rules in this rulemaking. Therefore, MMS is
proposing here paragraph (c) of what would be a new Sec. 211.18
regarding who is required to report and pay royalties.
[[Page 56015]]
The Committee was requested to consider payment and reporting for
agreements which contain only Federal leases with the same royalty rate
and funds distribution. The Committee concurred with an MMS draft
proposal that payment should be made on a takes basis with an exception
to seek approval for payment on an entitlements basis. (See pages 63-64
of Committee report.) Because this subject was beyond the Committee's
charge, MMS included it in that separate rulemaking (60 FR 30492, June
9, 1995).
This new paragraph would explain royalty reporting requirements for
leases in mixed agreements. The basic requirement is that an operating
rights owner in a Federal lease in a mixed agreement must report and
pay royalties each month based on its entitled share of production.
This issue is described in section II.D. of the Committee Report.
However, in a provision parallel to what is proposed in this
rulemaking for Sec. 202.450(d), discussed above, an operating rights
owner who meets the definition of small operating rights owner in
Sec. 206.451 could report and pay royalties each month based on its
takes. Then, within 6 months after the end of the calendar year, it
would have to adjust its reports and pay based on its entitled share if
it is greater than the takes.
This proposed rule would allow a credit for overtaken volumes for
the calendar year. MMS specifically requests comments on how this
credit should be processed.
Under Sec. 211.18(c)(2)(iii), if the volume of production the small
operating rights owner reported and paid on for the calendar year is
equal to or greater than its entitled share of production for the year,
no interest would be assessed for any individual months where volumes
were underreported. However, MMS would assess interest for any volumes
reported on takes but where the value of those volumes is underpaid.
For example, assume that the entitled share of production is 10 MMBtu
of production each month. For the year, the small operating rights
owner reported and paid on 120 MMBtu. However, in July, only 5 MMBtu
with a value of $1.00 per MMBtu was reported. The correct value should
have been $2.00 per MMBtu. No interest is owed for the underreported 5
MMBtu that month. However, for the 5 MMBtu that were reported, interest
is owed on the $1.00 of underreported value.
If the total volume the small operating rights owner reported and
paid on for the calendar year is less than its entitled share for that
year, it would be required to pay interest on all underreported volumes
and any associated underpaid royalties.
The rule would provide an exemption from the basic requirement that
all operating rights owners must report pay based on entitlements if
they agree among themselves to use an alternative method. The only
condition is that royalties must be reported and paid on the full
volume of production for the lease and the agreement.
Finally, under many of the proposals contained in this rulemaking,
additional reporting on the Report of Sales and Royalty Remittance
(Form MMS-2014) would be necessary to implement the proposals. For
example, where a small operating rights owner pays on its takes, MMS
would need to be alerted via the Form MMS-2014 that it may not receive
royalties on the full share of production allocable to the lease during
the calendar year. Lessees using index-based methods, as well as
lessees using alternative methods to value the gas plant products,
would need to notify MMS on the Form MMS-2014 in order for MMS to apply
the safety net median value procedure. Also, lessees paying on gross
proceeds in zones with an active spot market would need to alert MMS on
the Form MMS-2014 whether or not those gross proceeds are based on
arm's-length or non-arm's-length contracts. MMS requests input on how
to best accommodate this supplementary reporting.
IV. Procedural Matters
The Regulatory Flexibility Act
The Department certifies that this rule will not have significant
economic effect on a substantial number of small entities under the
Regulatory Flexibility Act (5 U.S.C. 601 et seq.). This proposed rule
will amend regulations governing the valuation for royalty purposes of
natural gas produced from Federal leases. These changes would add
several alternative valuation methods to the existing regulations.
Executive Order 12630
The Department certifies that the rule does not represent a
governmental action capable of interference with constitutionally
protected property rights. Thus, a Takings Implication Assessment need
not be prepared under Executive Order 12630, ``Government Action and
Interference with Constitutionally Protected Property Rights.''
Executive Order 12778
The Department has certified to the Office of Management and Budget
that these final regulations meet the applicable standards provided in
Sections 2(a) and 2(b)(2) of Executive Order 12778.
Executive Order 12866
This rule is significant under Executive Order 12866 and has been
reviewed by the Office of Management and Budget.
The Committee's many objectives for improving the process included
simplicity, administrative cost savings, and revenue neutrality for
both lessees and lessors.
A key component of the Committee's recommendations, the ``safety
net,'' assured MMS and the States that index-based values would not
result in substantially lower revenues than those received under the
current method of gross proceeds. The ``safety net'' allows MMS the
ability to monitor the revenue impact of index-based valuation by
comparing index values to the median value of all gross proceeds in the
area.
The Committee was not able to demonstrate empirically the revenue
neutrality of this proposed rule for a number of reasons. Although
revenue neutrality could not be documented, the Committee anticipated
that the use of published indices may ultimately reduce MMS' and
industry's administrative costs related to royalty payments.
The benefits of the proposed rule to both MMS and its constituents
are numerous. Benefits to independent producers include: (1) The
ability to continue to pay royalties on gross proceeds received under
dedicated arm's-length contracts and (2) an option to eliminate
administrative costs associated with natural gas liquid royalty
payments by paying on a wellhead value for non-dedicated arm's-length
contracts.
Benefits to all producers include: (1) An option to value
production from arm's-length non-dedicated contracts on published
indices in areas with active spot markets; (2) elimination of the
requirement to submit transportation and processing forms for Federal
gas leases; (3) elimination of dual accounting for gas produced from
Federal leases; and (4) greatly simplified definitions of gathering and
compression.
MMS and State governments realize administrative cost savings
through: (1) Reduction in audit, enforcement, and litigation costs
associated with determining the proper value of federal gas sold in the
FERC Order 636 environment; (2) reduction in retroactive adjustments
made to royalty reports to account for sales adjustments made from gas
pools and market
[[Page 56016]]
centers; and (3) elimination of resources necessary to collect and
verify all forms related to transportation and processing allowances.
Paperwork Reduction Act
This rule does not contain information collection requirements
which require approval by the Office of Management and Budget. The
proposed amendments to the gas valuation regulations would reduce
reporting requirements by not requiring the following forms to be filed
for gas production from Federal onshore and offshore mineral leases:
MMS-4109--Gas Processing Allowance Summary Report (OMB No. 1010-0075)
MMS-4295--Gas Transportation Allowance Report (OMB No. 1010-0075)
National Environmental Policy Act of 1969
We have determined that this rulemaking is not a major Federal
action significantly affecting the quality of the human environment,
and a detailed statement under section 102(2)(C) of the National
Environmental Policy Act of 1969 (42 U.S.C. 4332(2)(C)) is not
required.
List of Subjects
30 CFR Parts 202 and 206
Coal, Continental shelf, Geothermal energy, Government contracts,
Indians-lands, Mineral royalties, Natural gas, Petroleum, Public
lands--mineral resources, Reporting and recordkeeping requirements.
30 CFR Part 211
Coal, Continental shelf, Geothermal energy, Indians-lands, Mineral
resources, Mineral royalties, Natural gas, Oil, Public lands--mineral
resources, Reporting and recordkeeping requirements.
Dated: August 4, 1995.
Bob Armstrong,
Assistant Secretary--Land and Minerals Management.
For the reasons set out in the preamble, parts 202, 206, and 211 of
title 30 of the Code of Federal Regulations are proposed to be amended
as follows:
PART 202--ROYALTIES
1. The authority citation for part 202 is revised 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 B--Oil, Gas, OCS Sulfur, General
2. Section 202.51 is amended by revising paragraph (b) to read as
follows:
Sec. 202.51 Scope and definitions.
* * * * *
(b) The definitions in subparts C, D, I, and J of part 206 of this
title are applicable to subparts B, C, D, I, and J of this part.
3. The heading of subpart D is revised to read ``Indian Gas.''
4. Section 202.150 is amended by adding a new sentence at the
beginning of paragraph (a) as set forth below and by removing the words
``, except helium produced from Federal leases,'' in the first sentence
of paragraph (a); removing the words ``a Federal or'' from paragraph
(b)(1), paragraph (e)(2), and paragraph (f), and substituting the word
``an'' in their place; removing the words ``or if MMS determines that
gas was unavoidably lost or wasted from an OCS lease,'' in paragraph
(c); removing the words ``Federal or'' from the first and third
sentences of paragraph (e)(1); and by removing the words ``Federal
and'' from paragraph (f) introductory text.
Sec. 202.150 Royalty on gas.
(a) This subpart applies only to Indian leases. * * *
* * * * *
5. Section 202.151 is amended by removing the phrase ``Federal
and'' in the second sentence of paragraph (a).
6. Section 202.152 is amended by removing the words ``, except that
for OCS leases in the Gulf of Mexico, gas volumes and BTU heating
values shall be reported at a standard pressure base of 15.025 psia and
a standard temperature base of 60 deg.F,'' from the second sentence of
paragraph (a)(1).
7. A new subpart J is added as follows:
Subpart J--Federal Gas
Sec.
202.450 Royalty on gas.
202.451 Royalty on processed gas.
202.452 Standards for reporting and paying royalties on gas.
Subpart J--Federal Gas
Sec. 202.450 Royalty on gas.
(a) Royalty rate. Royalties due on gas production from leases
subject to the requirements of this subpart must be at the rate
established by the terms of the lease. Royalty must be paid in value
unless MMS requires payment in kind. When paid in value, the royalty
due must be the value, for royalty purposes, determined under 30 CFR
part 206 multiplied by the royalty rate in the lease.
(b) Gas subject to royalty. (1) All gas (except gas unavoidably
lost or used on, or for the benefit of, the lease, including that gas
used off-lease for the benefit of the lease when such off-lease use is
permitted by MMS or BLM, as appropriate) produced from a Federal lease
to which this subpart applies is subject to royalty. However, except as
provided in Sec. 202.451(b), in no instances will any gas be approved
for use royalty free downstream of the facility measurement point
approved for the gas.
(2) When gas is used on, or for the benefit of, the lease at a
production facility handling production from more than one lease with
the approval of MMS or BLM, as appropriate, or at a production facility
handling unitized or communitized production, only that proportionate
share of each lease's production (actual or allocated) necessary to
operate the production facility may be used royalty free.
(3) Where the terms of any lease are inconsistent with this
subpart, the lease terms will govern to the extent of that
inconsistency.
(c) Avoidably lost and wasted gas and compensatory royalty. (1) If
BLM determines that gas was avoidably lost or wasted from an onshore
lease, or that gas was drained from an onshore lease for which
compensatory royalty is due, or if MMS determines that gas was
avoidably lost or wasted from an OCS lease, then the value of that gas
must be determined in accordance with 30 CFR part 206.
(2) If a lessee receives insurance compensation for unavoidably
lost gas, royalties are due on the amount of that compensation. This
paragraph does not apply to compensation through self-insurance.
(d) Agreements. (1) Royalties are due on production allocated to
Federal leases under the terms of an agreement in accordance with the
following requirements:
(i) Royalty rate--Royalties are due based on the royalty rate
specified in the lease (or as modified by the agreement).
(ii) Volume--Royalties are due each month on the full share of
production allocated to the lease under the terms of the agreement. For
each operating rights owner (working interest owner) in the lease,
royalties are due on its entitled share of production allocable to the
lease; provided that, for production allocable to a small operating
rights owner (defined in Sec. 206.451) of a lease committed to a mixed
agreement (also defined in Sec. 206.451), royalties may be reported and
paid on a monthly basis on takes volumes, even if the total volume
reported and paid for that lease for the
[[Page 56017]]
month is less than the total volume of production allocable to the
lease under the agreement; provided further, for each calendar year in
which royalties are paid by or on behalf of a small operating rights
owner based on its takes volumes, within 6 months after the end of that
calendar year the operating rights owner must compare its total
entitled volumes of production for the calendar year to its total takes
volume for that calendar year and pay additional royalties on any
portion of its annual entitled volumes not taken during the calendar
year based on the value determined under paragraph (d)(1)(iii)(D) of
this section. If the small operating rights owner has taken more than
its entitled share of production for the calendar year and has paid
royalty on that taken volume, the small operating rights owner will be
entitled to a credit for the over-taken volumes.
(iii) Value--The value of production that an operating rights owner
in a Federal lease takes must be determined under 30 CFR part 206.
However, if an operating rights owner in a Federal lease in a mixed
agreement takes more than its entitled share of production for any
month, the value of its entitled share must be the weighted-average
value of the production, determined under 30 CFR part 206, that the
operating rights owner takes during that month based on the acceptable
method.
(iv) Value for mixed agreements--untaken volumes--For mixed
agreements, the value of production that an operating rights owner in a
Federal lease is entitled to but does not take for any month must be
determined as follows:
(A) Where the operating rights owner takes a portion of its
entitled share of production from a lease, value for the untaken
volumes must be based on the weighted average of the value of the
production taken by that owner for that month from the same lease in
the agreement as determined under 30 CFR part 206.
(B) If the operating rights owner takes none of its entitled share
and that production would have been valued using an index-based method
under Sec. 206.454 had it been taken, then the value of production not
taken for that month must be determined under Sec. 206.454(b) as if it
had been taken. If the operating rights owner uses a weighted-average
index value under Sec. 206.454(b)(2)(i), the most recent prior month's
confirmed nominations must be used in calculating the weighted-average
index value.
(C) If the operating rights owner takes none of its entitled share
of production from a lease and that production cannot be valued under
paragraph (B) above, then the value of production not taken for that
month must be determined based on the first applicable of the following
methods:
(1) The weighted average of the operating rights owner's gross
proceeds under arm's-length contracts during the previous three months
for production from or attributable to the same lease in the agreement;
(2) The weighted average of the operating rights owner's gross
proceeds under arm's-length contracts during the previous three months
for production from or attributable to other leases in the agreement;
(3) The weighted average of the operating rights owner's gross
proceeds under arm's-length contracts for that month in the field or
area.
(4) An index-based value for that month determined under
Sec. 206.454 if the lease is in a zone with an active spot market and
acceptable published indices and the gas production flows or could flow
to an IPP.
(5) A value determined for that month under Secs. 206.452(c) or
206.453(c), as applicable.
(D) For a small operating rights owner of a Federal lease who
elects to pay royalties on takes under paragraph (d)(1)(ii) of this
section, the value of any portion of its entitled share not taken
during the calendar year must be based on the first applicable of the
following methods:
(1) The weighted-average value of the production the operating
rights owner takes from the same lease in the agreement during the
calendar year;
(2) The weighted-average value of the production the operating
rights owner takes from other leases in the agreement during the
calendar year;
(3) A value determined under Secs. 206.452(c) or 206.453(c), as
applicable.
(v) Reporting and payment--Royalties must be reported and paid as
provided in part 211 of this title.
(2) If a lessee takes less than its entitled share of agreement
production for any month, but royalties are paid on the full volume of
its entitled share in accordance with the provisions of this section,
no additional royalty will be owed for that lease for prior periods at
the time the lessee subsequently takes more than its entitled share to
balance its account or when the lessee is paid a sum of money by the
other agreement participants to balance its account.
(3) If a Federal lessee takes less than its entitled share of
agreement production, upon request of the lessee MMS may authorize a
royalty valuation method different from that required by paragraph
(d)(1) of this section, but consistent with the purpose of these
regulations, for any volumes not taken by the lessee but for which
royalties are due.
(e) Exception for all agreement production. For production from
Federal leases which are committed to agreements, upon request of a
lessee MMS may establish the value of production under a method other
than the method required by the regulations in this title if: (1) the
proposed method for establishing value is consistent with the
requirements of the applicable statutes, lease terms and agreement
terms; (2) to the extent practical, persons with an interest in the
agreement, including royalty interests, are given notice and an
opportunity to comment on the proposed valuation method before it is
authorized; and (3) to the extent practical, persons with an interest
in a Federal lease committed to the agreement, including royalty
interests, must agree to use the proposed method for valuing production
from the agreement for royalty purposes.
Sec. 202.451 Royalty on processed gas.
(a) A royalty, as provided in the lease, must be paid on the value
of: (1) any drip condensate; and (2) residue gas and all gas plant
products resulting from processing the gas produced from a lease
subject to this part. MMS will authorize a processing allowance for the
reasonable, actual costs of processing the gas produced from Federal
leases. Processing allowances must be determined in accordance with
Subpart J of 30 CFR Part 206.
(b) A reasonable amount of residue gas will be allowed royalty free
for operation of the processing plant, but no allowance will be made
for expenses incidental to marketing, except as provided in 30 CFR part
206. In those situations where a processing plant processes gas from
more than one lease, only that proportionate share of each lease's
residue gas necessary for the operation of the processing plant will be
allowed royalty free.
(c) No royalty is due on residue gas, or any gas plant product
resulting from processing gas, which is reinjected into a reservoir
within the same lease, unit area, or communitized area, when the
reinjection is included in a plan of development or operations and the
plan has received BLM or MMS approval for onshore or offshore
operations, respectively, until such time as they are finally produced
from the reservoir for sale or other disposition off-lease.
[[Page 56018]]
Sec. 202.452 Standards for reporting and paying royalties on gas.
(a)(1) Gas volumes and Btu heating values, if applicable, must be
determined under the same degree of water saturation. Gas volumes must
be reported in units of one thousand cubic feet (Mcf), and Btu heating
value must be reported at a rate of Btu's per cubic foot, at a standard
pressure base of 14.73 psia and a standard temperature base of
60 deg.F, except that for OCS leases in the Gulf of Mexico, gas volumes
and Btu heating values must be reported at a standard pressure base of
15.025 psia and a standard temperature base of 60 deg.F. Gas volumes
and Btu heating values must be reported, for royalty purposes, on the
same water vapor saturated or unsaturated basis prescribed in the
lessee's gas sales contract.
(2) The frequency and method of Btu measurement as set forth in the
lessee's contract must be used to determine Btu heating values for
reporting purposes. However, the lessee must measure the Btu value at
least semiannually by recognized standard industry testing methods even
if the lessee's contract provides for less frequent measurement.
(b)(1) Residue gas and gas plant product volumes must be reported
as specified in this paragraph.
(2) Carbon dioxide (CO2), nitrogen (N2), helium (He),
residue gas, and any other gas marketed as a separate product must be
reported by using the same standards specified in paragraph (a) of this
section.
(3) Natural gas liquids (NGL's) must be reported in standard U.S.
gallons (231 cubic inches) at 60 deg.F, except for zones with an active
spot market and valid published indices. In those zones, NGL's must be
reported based on its heating value in accordance with the MMS Oil and
Gas Payor Handbook.
(4) Sulfur (S) volumes must be reported in long tons (2,240
pounds).
PART 206--PRODUCT VALUATION
8. The authority citation for part 206 is revised 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 D [Revised]
9. The heading of subpart D is revised to read ``Indian Gas.''
Sec. 206.150 [Amended]
10. Section 206.150 is amended by removing the words ``Federal
and'' from paragraph (a); removing paragraph (e)(1); redesignating
paragraph (e)(2) as paragraph (e)(1); redesignating paragraph (e)(3) as
paragraph (e)(2); and by removing paragraph (e)(4).
11. Section 206.151 is amended by removing the words ``Federal
and'' from the definition of Audit; removing the third sentence from
the definition of Field; removing the words ``Federal or'' from the
fourth sentence of the definition of Gross proceeds; removing the words
``Outer Continental Shelf or onshore Federal or'' from the definition
of Lease products; removing the words ``Federal and'' from the
definition of Net profit share; removing the definitions of Outer
Continental Shelf (OCS) and Section 6 lease; and by adding two new
sentences at the end of the definition of Lease as set forth below.
Sec. 206.151 Definitions.
* * * * *
Lease * * * For purposes of this subpart, this definition excludes
Federal leases. However, where the term lease is used in reference to
an agreement, this term may refer to non-Indian leases (e.g., Federal
leases, State leases, or fee leases) where the context requires.
Sec. 206.152 [Amended]
12. Section 206.152 is amended by removing the words ``Federal or''
from paragraph (e)(2).
Sec. 206.153 [Amended]
13. Section 206.153 is amended by removing the words ``Federal or''
from paragraph (e)(2).
Sec. 206.154 [Amended]
14. Section 206.154 is amended by removing the words ``or MMS for
onshore and OCS leases, respectively'' from paragraph (a)(1); and by
removing the words ``Federal and'' from the second sentence of
paragraph (c)(4).
Sec. 206.157 [Amended]
15. Section 206.157 is amended by removing the words ``(for both
Federal and Indian leases)'' and ``or a State regulatory agency (for
Federal leases)'' from the second sentence in paragraph (b)(5);
removing the words ``For lessees transporting production from onshore
Federal and Indian leases,'' from paragraph (e)(2); and by removing
paragraph (e)(3).
Sec. 206.159 [Amended]
16. Section 206.159 is amended by removing the words ``For lessees
processing production from onshore Federal and Indian leases,'' from
paragraph (e)(2); and by removing paragraph (e)(3).
17. A new Subpart J is added as follows:
Subpart J--Federal Gas
Sec.
206.450 Purpose and scope.
206.451 Definitions.
206.452 Valuation standards--unprocessed gas.
206.453 Valuation standards--processed gas.
206.454 Alternative valuation standards for unprocessed gas and
processed gas.
206.455 Determination of quantities and qualities for computing
royalties.
206.456 Transportation allowances--general.
206.457 Determination of transportation allowances.
206.458 Processing allowances--general.
206.459 Determination of processing allowances.
Subpart J--Federal Gas
Sec. 206.450 Purpose and scope.
(a) This subpart is applicable to all gas production from Federal
oil and gas leases. The purpose of this subpart is to establish the
value of production for royalty purposes consistent with the mineral
leasing laws, other applicable laws and lease terms. This subpart does
not apply to Indian leases.
(b) If the specific provisions of any statute, settlement agreement
resulting from any administrative or judicial proceeding, or oil and
gas lease subject to the requirements of this subpart are inconsistent
with any regulation in this subpart, then the lease, statute, or
settlement agreement will govern to the extent of that inconsistency.
(c) All royalty payments made to MMS are subject to audit and
adjustment.
Sec. 206.451 Definitions.
For purposes of this subpart:
Active spot market means a market where one or more MMS-acceptable
publications publish bidweek prices (or if bidweek prices are not
available, first of the month prices) for at least one index pricing
point in the zone.
Agreement means a federally-approved unit or communitization
agreement.
Allowance means a deduction in determining value for royalty
purposes. Processing allowance means an allowance for the reasonable
costs for processing gas determined under this subpart. Transportation
allowance means an allowance for the cost of moving royalty bearing
substances (identifiable, measurable oil and gas, including gas that is
not in need of initial separation) from the point at which it is first
identifiable and measurable to the sales point or other point where
value is established under this subpart.
[[Page 56019]]
Area means a geographic region at least as large as the defined
limits of an oil and/or gas field, in which oil and/or gas lease
products have similar quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement that has been
arrived at in the marketplace between independent, nonaffiliated
persons with opposing economic interests regarding that contract.
(1) For purposes of this subpart, two persons are affiliated if one
person controls, is controlled by, or is under common control with
another person. For purposes of this subpart, based on the instruments
of ownership of the voting securities of an entity, or based on other
forms of ownership:
(i) Ownership in excess of 50 percent constitutes control;
(ii) Ownership of 10 through 50 percent creates a presumption of
control; and
(iii) Ownership of less than 10 percent creates a presumption of
noncontrol which MMS may rebut if it demonstrates actual or legal
control, including the existence of interlocking directorates.
(2) Notwithstanding any other provisions of this subpart, contracts
between relatives, either by blood or by marriage, are not arm's-length
contracts. MMS may require the lessee to certify ownership control. To
be considered arm's-length for any production month, a contract must
meet the requirements of this definition for that production 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 payment
compliance activities of lessees or other interest holders who pay
royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the
Interior.
Compression means raising the pressure of gas.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees
of API gravity) recovered at the surface without resorting to
processing. Condensate is the mixture of liquid hydrocarbons that
results from condensation of petroleum hydrocarbons existing initially
in a gaseous phase in an underground reservoir.
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.
Dedicated means a contractual commitment to deliver gas production
(or a specified portion of production) from a lease or well when that
production is specified in a sales contract and that production must be
sold pursuant to that contract to the extent that production occurs
from that lease or well.
Drip condensate means any condensate recovered downstream of the
facility measurement point without resorting to processing. Drip
condensate includes condensate recovered as a result of its becoming a
liquid during the transportation of the gas removed from the lease or
recovered at the inlet of a gas processing plant by mechanical means,
often referred to as scrubber condensate.
Entitlement (or entitled share) means, for leases in an agreement,
the gas production allocable to lease acreage under the agreement
terms, multiplied by the operating rights owner's percentage of
interest ownership in that acreage.
Facility measurement point (or point of royalty settlement) means
the point at which the measurement device is located that was approved
by MMS or BLM for determining the volume of gas removed from the lease.
Field means a geographic region situated over one or more
subsurface oil and gas reservoirs encompassing at least the outermost
boundaries of all oil and gas accumulations known to be within those
reservoirs vertically projected to the land surface. Onshore fields are
usually given names and their official boundaries are often designated
by oil and gas regulatory agencies in the respective States in which
the fields are located. Outer Continental Shelf (OCS) fields are named
and their boundaries are designated by MMS.
Gas means any fluid, either combustible or noncombustible,
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and
which has neither independent shape nor volume, but tends to expand
indefinitely. It is a substance that exists in a gaseous or rarefied
state under standard temperature and pressure conditions.
Gas plant products means separate marketable elements, compounds,
or mixtures, whether in liquid, gaseous, or solid form, resulting from
processing gas, excluding residue gas.
Gathering means the movement of an unseparated, bulk production
stream to a point, on or off the lease, where the production stream
undergoes initial separation into identifiable oil, gas, or free water.
Gross proceeds (for royalty payment purposes) means the total
monies and other consideration accruing to an oil and gas lessee for
the disposition of unprocessed gas, residue gas, or gas plant products
produced. Gross proceeds includes, but is not limited to, payments to
the lessee for certain services such as compression, dehydration,
measurement, and/or field gathering to the extent that the lessee is
obligated to perform them at no cost to the Federal Government, and
payments for gas processing rights. Gross proceeds, as applied to gas,
also includes but is not limited to reimbursements for severance taxes
and other reimbursements. Tax reimbursements are part of the gross
proceeds accruing to a lessee even though the Federal royalty interest
may be exempt from taxation. 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 are also part of gross proceeds.
Index means the calculated composite price ($/MMBtu) of spot market
sales published by a publication that meets MMS-established criteria
for acceptability at the index pricing point.
Index pricing point (IPP) means the first point on any pipeline
connected to a well which is a single connect or split connect for
which there is an index. For a multiple connection, it means the first
point on each pipeline segment after the pipeline connected to the well
splits for which there is an index.
Jurisdictional pipeline means a pipeline with a rate regulated and
approved by the Federal Energy Regulatory Commission (FERC) or a state
agency.
Lease means any contract, profit-share arrangement, joint venture,
or other agreement issued or approved by the United States under a
mineral leasing law that authorizes exploration for, development or
extraction of, or removal of lease products--or the land area covered
by that authorization, whichever is required by the context. For
purposes of this subpart, this definition excludes Indian leases.
However, where the term ``lease'' is used in reference to an agreement,
the term may refer to non-Federal leases (e.g. Indian leases, State
leases, or fee leases) where the context requires.
Lease products means any leased minerals attributable to,
originating from, or allocated to a lease.
[[Page 56020]]
Lessee means any person to whom the United States issues a lease,
and any person who has been assigned an obligation to make royalty or
other payments required by the lease. This includes any person who has
an interest in a lease as well as an operator or payor who has no
interest in the lease but who has assumed the royalty payment
responsibility.
Like-quality lease products means lease products which have similar
chemical, physical, and legal characteristics.
Marketable condition means lease products which 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 field or
area.
Marketing affiliate means an affiliate of the lessee whose function
is to acquire only the lessee's production and to market that
production.
Minimum royalty means that minimum amount of annual royalty that
the lessee must pay as specified in the lease or in applicable leasing
regulations.
Mixed agreement means an agreement that includes leases other than
only Federal leases with the same royalty rate and fund distribution.
Multiple connection means a situation where one pipeline is
connected to the well, platform, central delivery point, or plant, but
that pipeline splits prior to an IPP or IPP's.
Natural gas liquids (NGL's) means those gas plant products
consisting of a mixture of ethane, propane, butane, and/or heavier
liquid hydrocarbons.
Net-back method (or work-back method) means a method for
calculating market value of gas at the lease. Under this method, costs
of transportation, processing, or manufacturing are deducted from the
proceeds received for the gas, residue gas or gas plant products, and
any extracted, processed, or manufactured products, or from the value
of the gas, residue gas or gas plant products, and any extracted,
processed, or manufactured products, at the first point at which
reasonable values for any such products may be determined by a sale
under an arm's-length contract or comparison to other sales of such
products, to ascertain value at the lease.
Net output means the quantity of residue gas and each gas plant
product that a processing plant produces.
Net profit share means the specified share of the net profit from
production of oil and gas as provided in the agreement.
Non-jurisdictional pipeline means a pipeline with no rates
regulated or approved by Federal Energy Regulatory Commission (FERC) or
a state agency.
Operating rights owner (working interest owner) means a person who
owns operating rights in a lease subject to this subpart. A record
title owner is the owner of operating rights under a lease except to
the extent that the operating rights or a portion thereof have been
transferred from record title. (See BLM regulations at 43 CFR 3100.0-
5(d) and MMS regulations at 30 CFR 256.62).
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of land beneath navigable waters as
defined in section 2 of the Submerged Lands Act (43 U.S.C. Sec. 1301)
and of which the subsoil and seabed appertain to the United States and
are subject to its jurisdiction and control.
Percentage-of-proceeds contract means a contract for the sale of
gas prior to processing which provides for the consideration to be
determined based upon a percentage of the purchaser's proceeds
resulting from processing and selling the gas and the gas plant
products.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Posted price means the price, net of all adjustments for quality
and location, specified in publicly available price bulletins or other
price notices available as part of normal business operations for
quantities of unprocessed gas, residue gas, or gas plant products in
marketable condition.
Processing means any process designed to remove elements or
compounds (hydrocarbon and nonhydrocarbon) from gas, including
absorption, adsorption, or refrigeration. Field processes which
normally take place on or near the lease, such as natural pressure
reduction, mechanical separation, heating, cooling, dehydration, and
compression, are not considered processing. The changing of pressures
and/or temperatures in a reservoir is not considered processing.
Residue gas means that hydrocarbon gas consisting principally of
methane resulting from processing gas.
Section 6 lease means an OCS lease subject to section 6 of the
Outer Continental Shelf Lands Act, as amended, 43 U.S.C. 1335.
Selling arrangement means the individual contractual arrangements
under which sales or dispositions of gas, residue gas and gas plant
products are made. Selling arrangements are described by illustration
in the MMS Royalty Management Program Oil and Gas Payor Handbook.
Single connect means a situation where only one pipeline is
connected to the well, platform, central delivery point, or plant, and
that pipeline does not split prior to an IPP.
Small operating rights owner is a person who produces less than
6,000 Mcf/day total U.S. gas production at 14.73 pounds per square inch
absolute (psia) at 60 deg.F and less than 1,000 bbls/day total U.S.
oil production at 60 deg.F.
Split connect means a situation where more than one pipeline
connects to the well, platform, central delivery point, or plant prior
to or at the IPP or IPP's.
Spot sales agreement means a contract wherein a seller agrees to
sell to a buyer a specified amount of unprocessed gas, residue gas, or
gas plant products at a specified price over a fixed period, usually of
short duration, which does not normally require a cancellation notice
to terminate, and which does not contain an obligation, nor imply an
intent, to continue in subsequent periods.
Takes means when the operating rights owner sells or removes
production from, or allocated to, the lease, or when such sale or
removal occurs for the benefit of an operating rights owner.
Zone means a geographic area containing blocks or fields as defined
by MMS.
Sec. 206.452 Valuation standards--unprocessed gas.
(a)(1) This section applies to the valuation of gas that is not
processed and gas that is processed but is sold or otherwise disposed
of by the lessee under an arm's-length contract prior to processing
(including gas sold under an arm's-length percentage-of-proceeds
contract). Where the lessee's contract includes a reservation of the
right to process the gas and the lessee exercises that right,
Sec. 206.453 of this subpart will apply instead of this section.
(2) The value of production, for royalty purposes, is the value of
gas determined under this section less applicable allowances determined
under this subpart.
(3) For purposes of this section, gas which is sold or otherwise
transferred to the lessee's marketing affiliate and then sold by the
marketing affiliate must be valued depending on how the marketing
affiliate resells the gas.
(b)(1)(i) The value of gas sold under an arm's-length contract is
the gross proceeds accruing to the lessee, except as provided in
paragraphs (b)(1)(ii) and (iii) of this section, and except as provided
in Sec. 206.454 of this subpart to
[[Page 56021]]
the extent that section applies to gas sold under an arm's-length
contract that is not dedicated. The lessee will have the burden of
demonstrating that its contract is arm's-length. The value which the
lessee reports, for royalty purposes, is subject to monitoring, review,
and audit. Also, for arm's-length percentage-of-proceeds contracts, the
value of production, for royalty purposes, must never be less than a
value equivalent to 100 percent of the value of the residue gas
attributable to the processing of the lessee's gas.
(ii) In conducting reviews and audits for gas valued based upon
gross proceeds under this paragraph, MMS will examine whether the
contract reflects the total consideration actually transferred either
directly or indirectly from the buyer to the seller for the gas. If the
contract does not reflect the total consideration, then MMS may require
that the gas sold under that contract be valued in accordance with
paragraphs (c) (2) or (3) of this section. Value may not be less than
the gross proceeds accruing to the lessee, including the additional
consideration.
(iii) If MMS determines for gas valued under this paragraph that
the gross proceeds accruing to the lessee under an arm's-length
contract do not reflect the reasonable value of the production because
of misconduct by or between the contracting parties, or because the
lessee otherwise has breached its duty to the lessor to market the
production for the mutual benefit of the lessee and the lessor, then
MMS will require that the gas production be valued under paragraphs (c)
(2) or (3) of this section. When MMS determines that the value may be
unreasonable, MMS will notify the lessee and give the lessee an
opportunity to provide written information justifying the lessee's
value.
(2) MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the gas.
(c) If gas is not sold under an arm's-length contract, the lessee
must first determine whether the gas is subject to valuation under
Sec. 206.454. If that section is applicable, the lessee must use it to
value the production. For gas not subject to valuation under that
section and for other gas that must be valued under this paragraph, the
value of gas must be the first applicable of the following:
(1) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition other than by
an arm's-length contract), provided that those gross proceeds are
equivalent to the gross proceeds derived from, or paid under,
comparable arm's-length contracts for purchases, sales, or other
dispositions of like-quality gas in the same field (or, if necessary to
obtain a reasonable sample, from the same area). In evaluating the
comparability of arm's-length contracts for the purposes of these
regulations, the following factors shall be considered: price, time of
execution, duration, market or markets served, terms, quality of gas,
volume, and such other factors as may be appropriate to reflect the
value of the gas;
(2) A value determined by consideration of other information
relevant in valuing like-quality gas, including gross proceeds under
arm's-length contracts for like-quality gas in the same field or nearby
fields or areas, posted prices for gas, prices received in arm's-length
spot sales of gas, other reliable public sources of price or market
information, and other information as to the particular lease operation
or the salability of the gas; or
(3) A net-back method or any other reasonable method to determine
value.
(d)(1) Where the value is determined under paragraph (c) of this
section, the lessee must retain all data relevant to the determination
of royalty value. Such data will be subject to review and audit, and
MMS will direct a lessee to use a different value if it determines that
the reported value is inconsistent with the requirements of these
regulations.
(2) Any Federal lessee will make available upon request to the
authorized MMS or state representatives, to the Office of the Inspector
General of the Department of the Interior, or other person authorized
to receive such information, arm's-length sales and volume data for
like-quality production sold, purchased or otherwise obtained by the
lessee from the field or area or from nearby fields or areas.
(e) If MMS determines that a lessee has not properly determined
value, the lessee must pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by MMS. The lessee must
also pay interest on that difference computed under 30 CFR 218.54. If
the lessee is entitled to a credit, MMS will provide instructions for
the taking of that credit.
(f) The lessee may request a value determination from MMS. In that
event, the lessee must propose to MMS a value determination method, and
may use that method in determining value for royalty purposes until MMS
issues its decision. The lessee must submit all available data relevant
to its proposal. MMS will expeditiously determine the value based upon
the lessee's proposal and any additional information MMS deems
necessary. In making a value determination MMS may use any of the
valuation criteria authorized by this subpart. That determination will
remain effective for the period stated therein. After MMS issues its
determination, the lessee must make the adjustments in accordance with
paragraph (e) of this section.
(g) For gas valued under this section (but not for any gas valued
using an index-based method under Sec. 206.454), under no circumstances
may the value of production for royalty purposes be less than the gross
proceeds accruing to the lessee for lease production, less applicable
allowances determined under this subpart.
(h) The lessee is required to place gas in marketable condition at
no cost to the Federal Government unless otherwise provided in the
lease agreement. Where the value established under this section is
determined by a lessee's gross proceeds, that value must be increased
to the extent that the gross proceeds have been reduced because the
purchaser, or any other person, is providing certain services the cost
of which ordinarily is the responsibility of the lessee to place the
gas in marketable condition.
(i) For gas valued under this section (but not for any gas valued
using an index-based method under Sec. 206.454), value must be based on
the highest price a prudent lessee can receive through legally
enforceable claims under its contract. If there is no contract revision
or amendment, and the lessee fails to take proper or timely action to
receive prices or benefits to which it is entitled, it must pay royalty
at a value based upon that obtainable price or benefit. Contract
revisions or amendments must be in writing and signed by all parties to
an arm's-length contract. If the lessee makes timely application for a
price increase or benefit allowed under its contract but the purchaser
refuses, and the lessee takes reasonable measures, which are
documented, to force purchaser compliance, the lessee will owe no
additional royalties unless or until monies or consideration resulting
from the price increase or additional benefits are received. This
paragraph may not be construed to permit a lessee to avoid its royalty
payment obligation in situations where a purchaser fails to pay, in
whole or in part or timely, for a quantity of gas.
(j) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a
[[Page 56022]]
redetermination by MMS of value under this section will be considered
final or binding as against the Federal Government or its beneficiaries
until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation
proposals, including transportation or extraordinary cost allowances,
may be exempted from disclosure under the Freedom of Information Act, 5
U.S.C. 552, or other Federal Law. Any data specified by law to be
privileged, confidential, or otherwise exempt will be maintained in a
confidential manner in accordance with applicable law and regulations.
All requests for information about determinations made under this
subpart are to be submitted in accordance with the Freedom of
Information Act regulation of the Department of the Interior, 43 CFR
part 2.
Sec. 206.453 Valuation standards--processed gas.
(a)(1) This section applies to the valuation of gas that is
processed by the lessee (including gas where the lessee has an
agreement with a gas processing plant that provides for the retention
of the gas plant products by the plant owner and for the payment, in
kind or in value, to the lessee for the plant thermal reduction). This
section also applies to any other gas production to which this subpart
applies and that is not subject to the valuation provisions of
Sec. 206.452 of this subpart, including situations where the lessee's
contract includes a reservation of the right to process the gas and the
lessee exercises that right.
(2) The value of production, for royalty purposes, is the combined
value of the residue gas and all gas plant products determined under
this section, plus the value of any drip condensate determined under
this part, less applicable transportation allowances and processing
allowances determined under this part. No processing allowance is
applicable to any gas plant products valued under Sec. 206.454.
(3) For purposes of this section, residue gas or any gas plant
product which is sold or otherwise transferred to the lessee's
marketing affiliate must be valued depending on how the marketing
affiliate resells the gas.
(b)(1)(i) The value of residue gas or any gas plant product sold
under an arm's-length contract is the gross proceeds accruing to the
lessee, except as provided in paragraphs (b)(1) (ii) and (iii) of this
section, and except as provided in Sec. 206.454 of this subpart to the
extent that section applies. The lessee will have the burden of
demonstrating that its contract is arm's-length. The value that the
lessee reports for royalty purposes is subject to monitoring, review,
and audit.
(ii) In conducting these reviews and audits for gas valued based
upon gross proceeds under this paragraph, MMS will examine whether or
not the contract reflects the total consideration actually transferred
either directly or indirectly from the buyer to the seller for the
residue gas or gas plant product. If the contract does not reflect the
total consideration, then MMS may require that the residue gas or gas
plant product sold under that contract be valued in accordance with
paragraph (c) (2) or (3) of this section. Value may not be less than
the gross proceeds accruing to the lessee, including the additional
consideration.
(iii) If MMS determines for gas valued under this paragraph that
the gross proceeds accruing to the lessee under an arm's-length
contract do not reflect the reasonable value of the residue gas or gas
plant product because of misconduct by or between the contracting
parties, or because the lessee otherwise has breached its duty to the
lessor to market the production for the mutual benefit of the lessee
and the lessor, then MMS will require that the residue gas or gas plant
product be valued under paragraph (c) (2) or (3) of this section. When
MMS determines that the value may be unreasonable, MMS will notify the
lessee and give the lessee an opportunity to provide written
information justifying the lessee's value.
(2) MMS may require a lessee to certify that its arm's-length
contract provisions include all of the consideration to be paid by the
buyer, either directly or indirectly, for the residue gas or gas plant
product.
(c) If residue gas or any gas plant product is not sold under an
arm's-length contract, the lessee must first determine whether the
residue gas or gas plant product is subject to valuation under
Sec. 206.454. For residue gas subject to valuation under Sec. 206.454,
the lessee must use that section to value the residue gas. For residue
gas or any gas plant product not subject to valuation under that
section and for other residue gas and gas plant products that must be
valued under this paragraph, the value must be the first applicable of
the following:
(1) The gross proceeds accruing to the lessee pursuant to a sale
under its non-arm's-length contract (or other disposition other than by
an arm's-length contract), provided that those gross proceeds are
equivalent to the gross proceeds derived from, or paid under,
comparable arm's-length contracts for purchases, sales, or other
dispositions of like quality residue gas or gas plant products from the
same processing plant (or, if necessary to obtain a reasonable sample,
from nearby plants). In evaluating the comparability of arm's-length
contracts for the purposes of these regulations, the following factors
shall be considered: price, time of execution, duration, market or
markets served, terms, quality of residue gas or gas plant products,
volume, and such other factors as may be appropriate to reflect the
value of the residue gas or gas plant products;
(2) A value determined by consideration of other information
relevant in valuing like-quality residue gas or gas plant products,
including gross proceeds under arm's-length contracts for like-quality
residue gas or gas plant products from the same gas plant or other
nearby processing plants, posted prices for residue gas or gas plant
products, prices received in spot sales of residue gas or gas plant
products, other reliable public sources of price or market information,
and other information as to the particular lease operation or the
salability of such residue gas or gas plant products; or
(3) A net-back method or any other reasonable method to determine
value.
(d)(1) Where the value is determined under paragraph (c) of this
section, the lessee must retain all data relevant to the determination
of royalty value. Such data will be subject to review and audit, and
MMS will direct a lessee to use a different value if it determines upon
review or audit that the reported value is inconsistent with the
requirements of these regulations.
(2) Any Federal lessee will make available upon request to the
authorized MMS or state representatives, to the Office of the Inspector
General of the Department of the Interior, or other persons authorized
to receive such information, arm's-length sales and volume data for
like-quality residue gas and gas plant products sold, purchased or
otherwise obtained by the lessee from the same processing plant or from
nearby processing plants.
(e) If MMS determines that a lessee has not properly determined
value, the lessee must pay the difference, if any, between royalty
payments made based upon the value it has used and the royalty payments
that are due based upon the value established by MMS. The lessee must
also pay interest computed on that difference under 30 CFR 218.54. If
the lessee is entitled to a credit, MMS will provide instructions for
the taking of that credit.
(f) The lessee may request a value determination from MMS. In that
event,
[[Page 56023]]
the lessee must propose to MMS a value determination method, and may
use that method in determining value for royalty purposes until MMS
issues its decision. The lessee must submit all available data relevant
to its proposal. MMS will expeditiously determine the value based upon
the lessee's proposal and any additional information MMS deems
necessary. In making a value determination, MMS may use any of the
valuation criteria authorized by this subpart. That determination will
remain effective for the period stated therein. After MMS issues its
determination, the lessee must make the adjustments in accordance with
paragraph (g) of this section.
(g) For residue gas and gas plant products valued under this
section (but not for residue gas or gas plant products valued under
Secs. 206.454(a)(2)(i), (ii)(A), (iii) or (iv)), under no circumstances
may the value of production for royalty purposes be less than the gross
proceeds accruing to the lessee for residue gas and/or any gas plant
products, less applicable transportation allowances and processing
allowances determined under this subpart.
(h) The lessee is required to place residue gas and gas plant
products in marketable condition at no cost to the Federal Government
unless otherwise provided in the lease agreement. Where the value
established under this section is determined by a lessee's gross
proceeds, that value must be increased to the extent that the gross
proceeds have been reduced because the purchaser, or any other person,
is providing certain services the cost of which ordinarily is the
responsibility of the lessee to place the residue gas or gas plant
products in marketable condition.
(i) For residue gas and gas plant products valued under this
section (but not for any residue gas or gas plant product valued using
an index-based method under Sec. 206.454), value must be based on the
highest price a prudent lessee can receive through legally enforceable
claims under its contract. Absent contract revision or amendment, if
the lessee fails to take proper or timely action to receive prices or
benefits to which it is entitled it must pay royalty at a value based
upon that obtainable price or benefit. Contract revisions or amendments
must be in writing and signed by all parties to an arm's-length
contract. If the lessee makes timely application for a price increase
or benefit allowed under its contract but the purchaser refuses, and
the lessee takes reasonable measures, which are documented, to force
purchaser compliance, the lessee will owe no additional royalties
unless or until monies or consideration resulting from the price
increase or additional benefits are received. This paragraph may not be
construed to permit a lessee to avoid its royalty payment obligation in
situations where a purchaser fails to pay, in whole or in part, or
timely, for a quantity of residue gas or gas plant product.
(j) Notwithstanding any provision in these regulations to the
contrary, no review, reconciliation, monitoring, or other like process
that results in a redetermination by MMS of value under this section
will be considered final or binding as against the Federal Government
or its beneficiaries until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation
proposals, including transportation allowances, processing allowances
or extraordinary cost allowances, may be exempted from disclosure under
the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any
data specified by law to be privileged, confidential, or otherwise
exempt, will be maintained in a confidential manner in accordance with
applicable law and regulations. All requests for information about
determinations made under this subpart are to be submitted in
accordance with the Freedom of Information Act regulation of the
Department of the Interior, 43 CFR part 2.
Sec. 206.454 Alternative valuation standards for unprocessed gas and
processed gas.
(a) Applicability. This section provides an alternative method to
value for royalty purposes unprocessed gas and processed gas produced
from Federal leases. However, it does not apply to unprocessed gas or
residue gas sold under a dedicated arm's-length contract. It also does
not establish value for carbon dioxide, nitrogen, or other non-Btu
components of the gas stream. This section applies only to gas
production from leases that are in zones with an active spot market and
published indices acceptable to MMS under paragraph (d) of this section
and to deepwater OCS leases whether or not in a zone. If the production
does not qualify for valuation under this section, then the lessee must
value its production under Secs. 206.452 or 206.453, as applicable.
(1)(i) For unprocessed gas subject to this section that is sold
under an arm's-length contract that is not dedicated, the lessee may
elect to value the gas using an index-based method under this section.
If the lessee does not elect to use this section, then the requirements
of Sec. 206.452(b)(1) apply.
(ii) For unprocessed gas subject to this section not sold under an
arm's-length contract, the lessee must value the gas using either:
(A) an index-based method under this section; or
(B) the gross proceeds (determined under Sec. 206.452) accruing to
the lessee's affiliated purchaser, but only if the affiliated purchaser
is not a marketing affiliate and it sells the gas under an arm's-length
contract.
(2)(i) For residue gas subject to this section that is sold under
an arm's-length contract that is not dedicated, the lessee may elect to
value the gas using an index-based method under this section. If the
lessee does not elect to use this section, then the requirements under
Sec. 206.453(b)(1) apply.
(ii) For residue gas subject to this section that is not sold under
an arm's-length contract, the lessee must value the gas under this
section using either:
(A) an index-based value under this section; or
(B) the gross proceeds (determined under Sec. 206.453) accruing to
the lessee's affiliated purchaser, but only if the affiliated purchaser
is not a marketing affiliate and it sells the residue gas under an
arm's-length contract.
(iii) If the lessee values residue gas under paragraph (a)(2) of
this section using an index-based method, then the lessee may elect to
value the NGL's, elemental sulfur, and drip condensate associated with
that residue gas using the same index-based value per MMBtu used to
value the associated residue gas, including any transportation
allowance under Sec. 206.457 applicable to the residue gas. If the
lessee does not elect to use the index-based method, the provisions of
Secs. 206.453(b) or (c), as applicable, apply to value those products.
(iv) If the lessee values the residue gas under an arm's-length
contract that is not dedicated using Sec. 206.453(b), or if it values
the residue gas using its affiliated purchaser's arm's-length gross
proceeds under paragraph (a)(2)(ii)(B) of this section, then the lessee
may elect to value the NGL's, elemental sulfur, and drip condensate
associated with that residue gas using the same price per MMBtu used to
value the associated residue gas, including any transportation
allowance under Sec. 206.457 applicable to the residue gas. If the
lessee does not elect to use this alternative value, the provisions of
Secs. 206.453(b) or (c), as applicable, apply.
(3) A lessee may use the alternative valuation methods provided
under paragraphs (a)(1) and (a)(2) of this section only if:
[[Page 56024]]
(i) There is an active spot market for the gas to be valued; and
(ii) The gas flows or could flow through at least one pipeline with
at least one published index price in the zone; and
(iii) For all leases in a zone or each OCS deepwater lease:
(A) all unprocessed gas and residue gas subject to this section
that is sold under an arm's-length contract that is not dedicated is
valued using the same valuation method under this section; and
(B) all unprocessed gas and residue gas subject to this section
that is not sold under an arm's-length contract is valued using the
same valuation method under this section where the lessee has an
election; and
(C) all NGL's, elemental sulfur, and drip condensate associated
with residue gas valued under paragraph (a)(2) of this section using an
index-based method is valued using the same valuation method; and
(D) all NGL's, elemental sulfur, and drip condensate associated
with residue gas valued under paragraphs (a)(2)(i) and (a)(2)(ii)(B) of
this section using a gross proceeds based method is valued using the
same valuation method; and
(iv) The lessee uses the valuation method elected for at least 2
calendar years.
(v) Any alternative value election under paragraphs (a)(1) and
(a)(2) of this section is subject to adjustment as provided in
paragraph (e) of this section.
(4) If the lessee does not satisfy all the criteria under paragraph
(a)(3) of this section, the value of the unprocessed gas or processed
gas must be determined under Secs. 206.452 or 206.453 of this subpart,
as applicable.
(5) Any production in the zone that the lessee adds during the two
year election period must be valued for the remainder of the period
using the same method as for the lessee's other production in the zone
sold under similar circumstances.
(6) If the lessee receives or received any revenue in connection
with the reformation or termination of any gas purchase contract that
occurred prior to effective date of this rule associated with
production from a Federal lease, those revenues may be subject to
royalty in accordance with the Department's existing precedents at the
time a part of such revenue is attributed to later production. If so,
royalty will be due on the increment of revenue attributed to future
production in addition to any index-based or other value established
under this section.
(b) Index-based valuation. The value of gas from a well on a lease
for any month determined by using an index-based method under this
section is the index value. Calculation of the index value depends upon
whether the gas flows or could flow through a single connect, a split
connect, or multiple connection as follows:
(1) For a single connect, the index value is the index price for
the first IPP. The index value must be used for that month to value the
gas production from the well.
(2) For a split connect or a multiple connection, the lessee must
elect one of the two following options to determine the index value.
The index value so determined must be used for that month to value the
gas production from the well.
(i) Weighted-Average Index Value. The weighted-average index value
for the month is calculated by:
(A)(1) multiplying the volume of the lessee's gas actually flowing
from a well to each IPP by the applicable index price for that IPP
determined using the publication selected under paragraph (d) of this
section;
(2) adding the numbers for each IPP determined under paragraph
(b)(2)(i)(A)(1) of this section; and
(3) dividing that sum by the total volume of the lessee's gas
actually flowing to all IPP's. The resulting quotient is the index
value for gas production from the well for that month.
(B) For purposes of paragraph (b)(2)(i) of this section, the amount
of gas actually flowing to each IPP is determined by using the
nominations confirmed at the first of the month or the total
nominations confirmed during the month, applied consistently for the
two-year election period. If the actual flow of the gas during the
month is different from the flow determined by the confirmed
nominations used to calculate the value under this paragraph, the
weighted average index value will not be recalculated using the actual
flow volume.
(ii) Fixed Index Value. (A) The fixed index value for the month is
determined as follows: for each of the IPP's through which gas from a
well flows or could flow, determine the average of the applicable
monthly index prices for the previous calendar year published in the
publication selected for each of those IPP's under paragraph (d) of
this section. List the average price determined for each IPP from
highest at the top to lowest at the bottom. If there are only two
IPP's, select the IPP associated with the first average index price
starting from the top of the list. The selected IPP will be used for
the entire calendar year. The index price for the current month in the
current year's publication selected for that IPP is the index value for
all gas production from the well for that month. If there are three or
more IPP's, select the IPP associated with the second average index
price starting from the top of the list. The selected IPP will be used
for the entire calendar year. The index price for the current month in
the current year's publication selected for that IPP is the index value
for all gas production from the well for that month.
(B) The result of the calculation in preceding paragraph (A) may be
that the selected average index price (either the highest average index
price if there are only two IPP's, or the second highest if there are
more than two IPP's) is identical to another index price in the array.
In that event, the lessee must recalculate the average of the
applicable monthly index prices for the previous calendar year for each
IPP to eight decimal points and redetermine the selected average index
price and the corresponding publication in accordance with preceding
paragraph (b)(2)(ii)(A) of this section. If the selected average index
price still is identical to another average index price, the lessee may
choose either one.
(C) The transportation allowance provided under Sec. 206.457 may
not be included in the calculation under either preceding paragraphs
(b)(2)(ii) (A) or (B) of this section.
(iii) Election. To determine the index value for a split connect or
multiple connection situation, the lessee must elect to use the
weighted-average index value or the fixed index value for the same two
year period as elected under paragraph (a)(3)(iv) of this section. The
elected method must be applied to all of the lessee's gas subject to
valuation under this section produced from wells that are connected for
the same split connect or multiple connection. Therefore, for example,
within the same zone, the lessee may elect the weighted-average index
value for production from wells connected to one multiple connection,
and the fixed index value for production from wells connected to a
different multiple connection. The election to use either the weighted-
average index value or the fixed index value must be made at the same
time the lessee elects to use an index-based method under paragraph (a)
of this section.
(c) Transportation allowance. As provided under Sec. 206.456, a
transportation allowance may be deducted from the index-based value
determined under this section for the
[[Page 56025]]
costs that are, or would be, incurred to transport the gas to the
IPP(s).
(d) Acceptable publications. At the beginning of each calendar year
for which the lessee elects to use an index-based method to value
production from a well under paragraph (a) of this section, the lessee
must select a publication that meets MMS-established criteria for
acceptability for each applicable IPP to determine the associated index
price. If more than one publication publishes an index price at an
applicable IPP, the lessee must select one of the acceptable
publications to use during that calendar year.
(1) MMS periodically will publish in the Federal Register a list of
acceptable publications based on certain criteria, including, but not
limited to:
(i) Publications frequently used by buyers and sellers,
(ii) Publications frequently referenced in purchase or sales
contracts,
(iii) Publications which use adequate survey techniques, including
the gathering of information from a substantial number of sales, and
(iv) Publications independent from lessees and MMS.
(2) Any publication may petition MMS to be added to the list of
acceptable publications provided the publication meets the criteria
under paragraph (d)(1) of this section.
(3) MMS will reference which tables in the publications must be
used for determining IPP's and associated index prices.
(4) MMS will publish the IPP's that it considers common among
acceptable publications.
(5) For single connects:
(i) If an acceptable publication publishes a new IPP that qualifies
as the first IPP, the lessee must use that IPP beginning with the first
day of the month the new IPP is published;
(ii) If the lessee's selected publication eliminates the IPP the
lessee is using, the lessee must select another publication for that
IPP beginning with the first day of the month the IPP is eliminated;
(iii) If the IPP the lessee is using is eliminated from all
acceptable publications, the lessee must determine a new IPP at the
first pipeline interconnect to which the gas flows or could flow
beginning with the first day of the month the original IPP is
eliminated.
(6) For a split connect or a multiple connection where the lessee
elects to use the weighted-average index value:
(i) If an acceptable publication adds a new IPP to which the
lessee's gas flows, the lessee must begin using the new IPP beginning
with the first day of the month the new IPP is added;
(ii) If any of the lessee's selected publications eliminates an IPP
to which the lessee's gas flows, the lessee must select another
acceptable publication for that IPP beginning with the first day of the
month the IPP is eliminated;
(iii) If an IPP to which the lessee's gas flows is eliminated from
all acceptable publications, the lessee may not use that volume in the
weighted-average index value calculation beginning with the first day
of the month the IPP is eliminated, unless another IPP is downstream of
the original IPP.
(7) For a split connect or a multiple connection where the lessee
elects to use the fixed index value:
(i) If an acceptable publication adds a new IPP, that IPP must not
be used in determining the fixed index value until the following
calendar year;
(ii) If the lessee's selected publication eliminates an IPP the
lessee was using, the lessee must select another acceptable publication
for that IPP beginning with the first day of the month the IPP is
eliminated.
(iii) If the IPP the lessee was using is eliminated from all
acceptable publications, the lessee must exclude that IPP and determine
a new IPP under paragraph (b)(2)(ii) of this section beginning with the
first day of the month the original IPP is eliminated.
(e) Additional royalty obligations. Under paragraphs (e)(8),
(e)(9), and (e)(10) of this section, the weighted average of the
alternative values determined under this section by the lessee in a
zone for the calendar year, less applicable transportation allowances,
must be compared to the final safety net median value calculated for
the zone under this paragraph. If the lessee's weighted-average value
is less than the final safety net median value, the lessee must pay
additional royalties under paragraphs (e)(8), (e)(9), or (e)(10) of
this section, as applicable. If the lessee's weighted-average value for
the zones less applicable transportation allowances under Sec. 206.457
equals or exceeds the final safety net median value, royalty will be
based on the lessee's weighted-average value for the zone.
(1) MMS will use, to the extent possible, the following information
reported on Form MMS-2014 for leases in a zone for the calendar year to
calculate the final safety net median value. The lines of information
from the Form MMS-2014 described in the following paragraphs (e)(1)(i)-
(iv) of this section are the final reported transactions existing at
the time the final safety net median value is calculated 2 years
following the end of the calendar year:
(i) Lines reporting royalty due (Transaction Code 01 or 06) for
unprocessed gas (Product Code 04) and residue gas (Product Code 03)
where the sales value represents values based on gross proceeds under
the following sales transactions:
(A) Arm's-length dedicated sales;
(B) Arm's-length non-dedicated sales, but only if the associated
gas plant products are valued under Sec. 206.453;
(C) Arm's-length resales by the lessee's affiliated purchaser, but
only if the associated gas plant products are valued under
Sec. 206.453;
(D) Federal royalty-in-kind gas sales for the applicable zone.
(ii) Lines reporting royalty due (Transaction Code 01) for drip
condensate (Product Code 05), natural gas liquids (Product Code 07),
and elemental sulfur (Product Code 19) associated with the residue gas
reported on the lines in paragraph (e)(1)(i) of this section.
(iii) Lines reporting transportation allowances (Transaction Code
11) associated with any product reported on the lines in paragraphs
(e)(1)(i) and (ii) of this section.
(iv) Lines reporting processing allowances (Transaction Code 15)
associated with NGL's and sulfur reported on the lines in paragraph
(e)(1)(ii) of this section.
(2) MMS will also use the following information related to the
calendar year's production to calculate the final safety net median
value:
(i) Unappealed orders for additional royalties;
(ii) Unappealed MMS Director's decisions involving orders for
additional royalties;
(iii) Refunds from requests under Section 10 of the OCS Lands Act
of 1953, 43 U.S.C. Sec. 1339; and
(iv) Amounts from MMS Director's decisions pending in
administrative or judicial actions.
(v) If any monetary amounts under paragraphs (e)(1)(i)-(iv) of this
section are not reported on a Form MMS-2014, MMS will convert the
amounts to an appropriate rate per MMBtu for use under paragraph (e)(1)
of this section.
(3) The final safety net median value will not include:
(i) Lines reporting royalties paid on pipeline buyout or buydown
settlement amounts (Transaction Code 31);
(ii) Unpaid issue letters (preliminary determination letters); or
(iii) Appealed orders not yet decided by the MMS Director.
(4) The final safety net median value for a zone is calculated by
arraying the
[[Page 56026]]
prices per MMBtu derived from the information under paragraphs (e)(1)
and (2) of this section from highest to lowest (at the bottom). The
final safety net median value is that price at which 50 percent plus 1
MMBtu of the production (starting from the bottom) is sold.
(5) The final safety net median value must be based on a
representative sample as provided in paragraph (f) of this section.
(6) MMS will publish in the Federal Register the final safety net
median value within two years following the end of the calendar year.
(7) A lessee may request a technical procedural review from the
Associate Director for Royalty Management of the final safety net
median value after it is published. All affected parties will be given
an opportunity to participate in the review process. Following the
technical procedural review, the Associate Director may modify the
final safety net median value. The Associate Director's decision
following the technical procedural review will be completed in an
expeditious manner and will be a final Departmental decision not
subject to further administrative review.
(8) This paragraph applies to a lessee's unprocessed gas and
residue gas produced from leases in a zone which is valued using an
index-based method under this section, but only for that residue gas
where the associated gas plant products are valued under Sec. 206.453
and not under this section. The lessee must determine the weighted-
average index-based value for unprocessed gas and residue gas in the
zone by summing the index-based values determined under this section,
less applicable transportation allowances under Sec. 206.457, and
dividing that sum by the total quantity of MMBtu's of unprocessed gas
and residue gas in the zone. If that weighted-average index-based value
is less than the final safety net median value for the zone, the lessee
must pay additional royalties, plus interest, as follows:
(i) For the first calendar year this section is in effect, the
additional royalty payment for production subject to this paragraph is
calculated as follows:
(A) Determine the lesser of the final safety net median value or
105 percent of the lessee's weighted-average index-based value
determined in preceding paragraph (e)(8);
(B) Subtract the weighted-average index-based value from the lesser
value under preceding paragraph (e)(8)(i)(A) of this section;
(C) Multiply the difference by the lessee's royalty quantity for
all unprocessed gas and residue gas in the zone subject to this
paragraph, converted to MMBtu's.
(ii) For subsequent calendar years, the additional royalty payment
for production subject to this paragraph is calculated as follows:
(A) Subtract the lessee's weighted-average index-based value
determined under preceding paragraph (e)(8) from the final safety net
median value;
(B) Multiply the difference by 50 percent;
(C) Multiply the result by the lessee's royalty quantity for all
unprocessed gas and residue gas in the zone subject to this paragraph,
converted to MMBtu's.
(iii) Late payment interest will accrue on any underpaid royalties
in accordance with paragraph (e)(12) of this section.
(9) This paragraph applies to a lessee's residue gas, NGL's,
elemental sulfur, and drip condensate produced from leases in a zone
which are valued using an index-based value determined under this
section. The lessee must determine the weighted-average index-based
value of that residue gas and associated products in the zone by
summing the index-based values determined under this section, less
applicable transportation allowances under Sec. 206.457, and dividing
that sum by the total quantity of MMBtu's of that residue gas and
associated products in the zone. If that weighted-average index-based
value is less than the final safety net median value for the zone, the
lessee must pay additional royalties, plus interest, as follows:
(i) For the first calendar year this section is in effect, the
additional royalty payment for production subject to this paragraph is
calculated as follows:
(A) Determine the lesser of the final safety net median value or
105 percent of the lessee's weighted-average index-based value
determined under preceding paragraph (e)(9);
(B) Subtract the weighted-average index-based value from the lesser
value under preceding paragraph (e)(9)(i)(A) of this section;
(C) Multiply the difference by the lessee's royalty quantity for
all residue gas and associated products in the zone subject to this
paragraph, converted to MMBtu's.
(ii) For subsequent calendar years, the additional royalty payment
for production subject to this paragraph is calculated as follows:
(A) Subtract the lessee's weighted-average index-based value
determined under preceding paragraph (e)(9) from the final safety net
median value;
(B) Multiply the difference by 50 percent;
(C) Multiply the result by the lessee's royalty quantity for all
residue gas and associated products in the zone subject to this
paragraph, converted to MMBtu's.
(iii) Late payment interest will accrue on any underpaid royalties
in accordance with paragraph (e)(12) of this section.
(10) This paragraph applies to a lessee's residue gas, NGL's,
elemental sulfur, and drip condensate produced from leases in a zone
which are valued using the lessee's or the lessee's affiliated
purchaser's gross proceeds for residue gas determined under
Secs. 206.453(b) or 206.454(a)(2)(ii)(B) of this subpart, as
applicable. The lessee must determine the weighted-average value of
that residue gas and associated products in the zone by summing the
gross proceeds-based values determined under Secs. 206.453(b) or
206.454(a)(2)(ii)(B), less applicable transportation allowances under
Sec. 206.457, and dividing that sum by the total quantity of MMBtu's of
that residue gas and associated products in the zone. If the resulting
weighted-average gross proceeds-based value is less than the final
safety net median value for the zone, the lessee must pay additional
royalties, plus interest, as follows:
(i) For the first calendar year this section is in effect, the
additional royalty payment for production subject to this paragraph is
calculated as follows:
(A) Determine the lesser of the final safety net median value or
105 percent of the lessee's weighted-average gross proceeds-based value
determined under preceding paragraph (e)(10);
(B) Subtract the weighted-average gross proceeds-based value from
the lesser value under preceding paragraph (e)(10)(i)(A) of this
section;
(C) Multiply the difference by the lessee's royalty quantity for
all residue gas and associated products in the zone subject to this
paragraph, converted to MMBtu's.
(ii) For subsequent calendar years, the additional royalty payment
for production subject to this paragraph is calculated as follows:
(A) Subtract the lessee's weighted-average gross proceeds-based
value determined under preceding paragraph (e)(10) from the final
safety net median value;
(B) Multiply the difference by 50 percent;
(C) Multiply the result by the lessee's royalty quantity for all
residue gas and associated products in the zone subject
[[Page 56027]]
to this paragraph, converted to MMBtu's.
(iii) Late payment interest will accrue on any underpaid royalties
in accordance with paragraph (e)(12) of this section.
(11) For each deepwater lease on the Outer Continental Shelf, the
additional royalty due under paragraphs (e)(8), (e)(9), and (e)(10) of
this section will be calculated by deducting from the applicable safety
net median value the appropriate transportation allowance to the first
point within a zone to which production from that lease flows.
(12)(i) As soon as possible following the end of each calendar year
(preferably within 6 months), MMS will publish an initial safety net
median value for each zone. The initial safety net median value will be
calculated using the methodology in paragraph (e)(4) of this section
and using the information listed in paragraph (e)(1) of this section
available at the time of its calculation, even if that information is
not final.
(ii) The lessee may submit an estimated payment for any additional
royalty it determines is due because of the difference between the
lessee's weighted-average value determined under this section and the
initial safety net median value. If the final safety net median value
published under paragraph (e)(6) of this section is lower than the
initial safety net median value, the lessee is entitled to a credit or
refund of all or a portion of its estimated payment without interest
under paragraph (e)(12)(iii) of this section.
(iii) After publication of the initial safety net median value or
the final safety net median value, the lessee may report additional
royalty payments using a one-line entry on Form MMS-2014 for each zone.
If the lessee files a Form MMS-2014 and makes an estimated payment of
additional royalty after publication of the initial safety net median
value, then following publication of the final safety net median value
it must file an amended Form MMS-2014 adjusting any payments for each
zone, if necessary. On this amended Form MMS-2014, the lessee may
recoup any overpayment by filing a credit adjustment. This first credit
adjustment is not subject to the requirements of section 10 of the
Outer Continental Shelf Lands Act, 43 U.S.C. 1339. Any subsequent
credit adjustment for a zone is subject to section 10.
(iv) Late payment interest will not accrue on any additional
royalty owed under paragraphs (e)(8), (e)(9), or (e)(10) of this
section until the date MMS publishes the initial safety net value.
(f) Representative sample. The final safety net median value must
be based on a representative sample, which, for purposes of this
section, means at least ten percent of the MMBtu of production reported
to MMS on Form MMS-2014 for leases in a zone under paragraphs (e)(1)
(i) and (ii) of this section, or at least twenty percent of the lines
reported to MMS on Form MMS-2014 for leases in a zone under paragraphs
(e)(1) (i) and (ii) of this section. If a representative sample meeting
these criteria is not available at the time MMS is required to
calculate the initial safety net median value under paragraph (e)(12)
of this section, MMS will use the following procedures to obtain an
appropriate sample:
(1) Among lessees in the zone using an index-based method to value
production under this section, MMS will ask for volunteers to provide
access to their records (including records regarding affiliated
purchasers' resale values) to obtain arm's-length gross proceeds volume
and value information. MMS will take a stratified sample of this
information to be added to the information reported on Form MMS-2014
based on arm's-length gross proceeds under paragraphs (e)(1) (i) and
(ii) of this section to determine the final safety net median value for
the zone.
(2) If there are no volunteers in the zone, or not enough
information from the volunteers to fulfill the requirements of a
representative sample, MMS will establish the final safety net median
value. Actions that MMS will take to determine the final safety net
median value will include, but not be limited to, issuing orders to
lessees within the zone necessary to obtain sufficient gross proceeds
data to develop the final safety net median value for the zone.
(3) Lessees that volunteer to provide access to their records under
this paragraph will have any additional royalty obligation determined
under paragraphs (e)(8), (e)(9), or (e)(10) of this section based upon
the lesser of a negotiated value or a calculation under those
paragraphs using the final safety net median value reduced by $0.005/
MMBtu.
(g) Zone determination. (1) MMS will publish in the Federal
Register the zones with an active spot market and published indices
that are eligible for an index-based valuation method. MMS will use the
following factors and conditions in determining eligible zones:
(i) Common markets served;
(ii) Common pipeline systems;
(iii) Simplification; and
(iv) Easy identification in MMS' system, such as offshore blocks,
offshore areas, or onshore counties.
(2) Deepwater leases in the OCS will not be included in a zone that
includes non-deepwater leases.
(3) MMS will monitor the market activity in the zones and, if
necessary, hold a technical conference to add or modify a particular
zone. Any change to the zones will be published in the Federal
Register.
(h) Zone disqualification. If market conditions change so that an
index-based method for determining value is no longer an appropriate
measure of market value for a zone, MMS will hold a technical
conference to consider disqualification of a zone. MMS will publish
notice in the Federal Register of a zone disqualification. However, MMS
will not disqualify a zone prior to the end of the calendar year. MMS
will notify lessees by September 1 of the year prior to
disqualification.
Sec. 206.455 Determination of quantities and qualities for computing
royalties.
(a)(1) Royalties must be computed on the basis of the quantity and
quality of unprocessed gas at the facility measurement point approved
by BLM or MMS for onshore and OCS leases, respectively.
(2) If the value of gas determined under Sec. 206.452 of this
subpart is based upon a quantity and/or quality that is different from
the quantity and/or quality at the facility measurement point, as
approved by BLM or MMS, that value must be adjusted for the differences
in quantity and/or quality.
(b)(1) For residue gas and gas plant products, the quantity basis
for computing royalties due is the monthly net output of the plant even
though residue gas and/or gas plant products may be in temporary
storage.
(2) If the value of residue gas and/or gas plant products
determined under Sec. 206.453 of this subpart is based upon a quantity
and/or quality of residue gas and/or gas plant products that is
different from that which is attributable to a lease, determined in
accordance with paragraph (c) of this section, that value must be
adjusted for the differences in quantity and/or quality.
(c) The quantity of the residue gas and gas plant products
attributable to a lease must be determined according to the following
procedure:
(1) When the net output of the processing plant is derived from gas
obtained from only one lease, the quantity of the residue gas and gas
plant products on which computations of royalty are based is the net
output of the plant.
[[Page 56028]]
(2) When the net output of a processing plant is derived from gas
obtained from more than one lease producing gas of uniform content, the
quantity of the residue gas and gas plant products allocable to each
lease must be in the same proportions as the ratios obtained by
dividing the amount of gas delivered to the plant from each lease by
the total amount of gas delivered from all leases.
(3) When the net output of a processing plant is derived from gas
obtained from more than one lease producing gas of nonuniform content,
the quantity of the residue gas allocable to each lease will be
determined by multiplying the amount of gas delivered to the plant from
the lease by the residue gas content of the gas, and dividing the
arithmetical product thus obtained by the sum of the similar
arithmetical products separately obtained for all leases from which gas
is delivered to the plant, and then multiplying the net output of the
residue gas by the arithmetic quotient obtained. The net output of gas
plant products allocable to each lease will be determined by
multiplying the amount of gas delivered to the plant from the lease by
the gas plant product content of the gas, and dividing the arithmetical
product thus obtained by the sum of the similar arithmetical products
separately obtained for all leases from which gas is delivered to the
plant, and then multiplying the net output of each gas plant product by
the arithmetic quotient obtained.
(4) A lessee may request MMS approval of other methods for
determining the quantity of residue gas and gas plant products
allocable to each lease. If approved, such method will be applicable to
all gas production from Federal leases that is processed in the same
plant.
(d)(1) No deductions may be made from the royalty volume or royalty
value for actual or theoretical losses. Any actual loss of unprocessed
gas that may be sustained prior to the facility measurement point will
not be subject to royalty provided that such loss is determined to have
been unavoidable by BLM or MMS, as appropriate.
(2) Except as provided in paragraph (d)(1) of this section and 30
CFR 202.451(c) of this part, royalties are due on 100 percent of the
volume determined in accordance with paragraphs (a) through (c) of this
section. There can be no reduction in that determined volume for actual
losses after the quantity basis has been determined or for theoretical
losses that are claimed to have taken place. Royalties are due on 100
percent of the value of the unprocessed gas, residue gas, and/or gas
plant products as provided in this subpart, less applicable allowances.
There can be no deduction from the value of the unprocessed gas,
residue gas, and/or gas plant products to compensate for actual losses
after the quantity basis has been determined, or for theoretical losses
that are claimed to have taken place.
Sec. 206.456 Transportation allowances--general.
(a)(1) Where the value of gas has been determined under this
subpart at a point off the lease (e.g., sales point, IPP, or other
point of value determination), the lessee may deduct from value a
transportation allowance to reflect the value, for royalty purposes, at
the lease. For residue gas and gas plant products, the lessee may
deduct a transportation allowance representing the reasonable costs of
transporting the residue gas and gas plant products to a gas processing
plant off the lease and from the plant to a point away from the plant.
If gas flows or could flow through more than one pipeline segment to
the point where value is determined, the transportation allowance will
be based on the total allowances for each segment determined under
Sec. 206.457.
(2) For the purposes of this subpart, the lessee's costs of
compression downstream of the facility measurement point incurred
either by the payment of such cost under a contract or the performance
of that function may be a part of the lessee's transportation allowance
determined under Sec. 206.457 of this subpart. However, under no
circumstances may any costs of compression occurring prior to the
facility measurement point be deductible. The lessee's costs of
boosting or compressing residue gas after processing are part of the
transportation allowance for residue gas.
(b) Transportation costs must be allocated among all products
produced and transported as provided in Sec. 206.457 of this subpart.
(c)(1) Except as provided in paragraph (c)(2) of this section, the
transportation allowance deduction on the basis of a selling
arrangement must not exceed 50 percent of the value of the unprocessed
gas, residue gas, or gas plant products determined under Sec. 206.452,
Sec. 206.453, or Sec. 206.454 of this subpart, as applicable. For
purposes of this section, NGL's must be considered one product.
(2) Upon request of a lessee, MMS may approve an exception for a
transportation allowance deduction in excess of the limitations
prescribed by paragraph (c)(1) of this section. The lessee must
demonstrate that the transportation costs incurred in excess of the
limitations prescribed in paragraph (c)(1) of this section were
reasonable and necessary. An application for exception must contain all
relevant and supporting documentation necessary for MMS to make a
determination. Under no circumstances may the value for royalty
purposes under any selling arrangement be reduced to zero.
(3) Notwithstanding any other provision of this subpart, MMS may
approve, upon request of the lessee, a transportation allowance for the
movement of gas from deepwater OCS leases, even if the production from
the lease has not been initially separated.
(d) If, after a review and/or audit, MMS determines that a lessee
has improperly determined a transportation allowance authorized by this
subpart, then the lessee must pay any additional royalties, plus
interest, determined in accordance with 30 CFR 218.54, or will be
entitled to a credit, without interest.
Sec. 206.457 Determination of transportation allowances.
(a) Introduction. This section explains how to determine the
applicable transportation allowance. If the lessee uses gross proceeds
to value its production, then the transportation allowance is based on
the transportation costs under paragraphs (b) or (c) of this section,
depending upon whether the pipeline is jurisdictional or non-
jurisdictional, and whether the transportation contract is arm's-
length. If the lessee uses an index-based method to value its
production, and if a portion of the lessee's gas flows to the IPP used
for value, then, as provided in paragraph (d) of this section, the
transportation allowance is based on the transportation costs under
paragraphs (b) or (c) of this section, as applicable. If the lessee
uses an index-based method to value its production, but none of its gas
flows to the IPP used for value, the transportation allowance is
determined under paragraph (d)(5) of this section.
(b) Jurisdictional pipelines and arm's-length transportation
contracts for non-jurisdictional pipelines. (1)(i) For all value
determinations under Sec. 206.452, Sec. 206.453,
Sec. 206.454(a)(1)(ii)(B), or Sec. 206.454(a)(2)(ii)(B) of this
subpart, where the lessee or its affiliate actually transports
unprocessed gas, residue gas, gas plant products, or drip condensate
through a jurisdictional pipeline, the transportation allowance must be
based on the reasonable, actual contract rate paid in accordance with
this paragraph.
(ii) For all value determinations under Sec. 206.452, Sec. 206.453,
Sec. 206.454 (a)(1)(ii)(B), or Sec. 206.454(a)(2)(ii)(B) of
[[Page 56029]]
this subpart, where the lessee or its affiliate actually transports
unprocessed gas, residue gas, gas plant products, or drip condensate
through a non-jurisdictional pipeline under an arm's-length
transportation contract, the transportation allowance must be based on
the reasonable, actual contract rate paid in accordance with this
paragraph.
(2)(i) In conducting reviews and audits, MMS will examine whether
or not the actual contract rate paid reflects more than the
consideration actually transferred either directly or indirectly from
the lessee to the transporter for the transportation. If the contract
rate paid reflects more than the total consideration, then MMS may
require that the transportation allowance be determined in accordance
with paragraph (c)(2) of this section.
(ii) If MMS determines that the actual contract rate paid does not
reflect the reasonable value of the transportation because of
misconduct by or between the contracting parties, or because the lessee
otherwise has breached its duty to the lessor to market the production
for the mutual benefit of the lessee and the lessor, then MMS will
require that the transportation allowance be determined in accordance
with paragraph (c)(2) of this section. When MMS determines that the
value of the transportation may be unreasonable, MMS will notify the
lessee and give the lessee an opportunity to provide written
information justifying the lessee's transportation costs.
(3)(i) If a transportation contract includes more than one product
in a gaseous phase and the transportation costs attributable to each
product cannot be determined from the contract, the total
transportation costs must be allocated in a consistent and equitable
manner to each of the products transported in the same proportion as
the ratio of the volume of each product to the volume of all products
in the gaseous phase. No allowance may be taken for the costs of
transporting lease production which is not royalty bearing without MMS
approval.
(ii) Notwithstanding the requirements of paragraph (b)(3)(i) of
this section, the lessee may propose to MMS a cost allocation method on
the basis of the values of the products transported. MMS will approve
the method unless it determines that it is not consistent with the
purposes of the regulations in this part.
(4) If a transportation contract includes both gaseous and liquid
products and the transportation costs attributable to each cannot be
determined from the contract, the lessee must propose an allocation
procedure to MMS. The lessee may use the transportation allowance
determined in accordance with its proposed allocation procedure until
MMS issues its determination on the acceptability of the cost
allocation. The lessee must submit all relevant data to support its
proposal. MMS will then determine the gas transportation allowance
based upon the lessee's proposal and any additional information MMS
deems necessary.
(5) Where the lessee's payments for transportation under a contract
are not based on a dollar per unit, the lessee must convert whatever
consideration is paid to a dollar value equivalent for the purposes of
this section.
(6) Where an arm's-length sales contract price or a posted price
includes a provision whereby the listed price is reduced by a
transportation factor, MMS will not consider the transportation factor
to be a transportation allowance. The transportation factor may be used
in determining the lessee's (or affiliate's, as the case may be) gross
proceeds for the sale of the product. The transportation factor may not
exceed 50 percent of the base price of the product without MMS
approval.
(7) MMS may require that a lessee submit transportation contracts,
production agreements, operating agreements, and related documents.
Documents must be submitted within a reasonable time as determined by
MMS.
(c) Non-jurisdictional pipelines--non-arm's-length transportation.
(1) For all value determinations under Sec. 206.452, Sec. 206.453,
Sec. 206.454(a)(1)(ii)(B), or Sec. 206.454(a)(2)(ii)(B) of this
subpart, the transportation allowance for a non-jurisdictional pipeline
under either a non-arm's-length transportation contract or no contract
must be determined as follows:
(i) If 30 percent or less of the gas in the pipeline is transported
under arm's-length transportation contracts, the transportation
allowance for a calendar year must be based on either:
(A) The lessee's reasonable, actual costs as provided under
paragraph (c)(2) of this section; or
(B) A rate of $0.02/MMBtu for leases on the Outer Continental
Shelf; for onshore leases a de minimis rate determined by MMS for
onshore leases not to exceed $0.09/MMBtu, including pipeline fuel
consideration. MMS periodically will establish the rate based upon
available transportation cost data and will publish the applicable rate
in the Federal Register.
(ii) If more than 30 percent of the gas in the pipeline is
transported under arm's-length transportation contracts, the
transportation allowance for a calendar year must be based on either:
(A) The lessee's reasonable, actual costs as provided under
paragraph (c)(2) of this section; or
(B) A rate determined by arraying all of the arm's-length contract
rates for the pipeline from highest at the top to lowest at the bottom
and starting from the bottom, choosing the rate closest to the 25th
percentile from the bottom. If two of the contract rates are
equidistant from the 25th percentile, use the average of the two rates.
(2) This paragraph applies to non-arm's-length and no contract
transportation situations where the lessee elects to determine its
transportation allowance based upon its actual costs. Under this
paragraph, the lessee's reasonable, actual costs include operating and
maintenance expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(c)(2)(iv)(A) of this section, or a cost equal to the initial
depreciable investment in the transportation system multiplied by a
rate of return in accordance with paragraph (c)(2)(iv)(B) of this
section. Allowable capital costs are generally those costs for
depreciable fixed assets (including costs of delivery and installation
of capital equipment) which are an integral part of the transportation
system.
(i) Allowable operating expenses include: Operations supervision
and engineering; operations labor; fuel; utilities; materials; ad
valorem property taxes; rent; supplies; and any other directly
allocable and attributable operating expense which the lessee can
document.
(ii) Allowable maintenance expenses include: Maintenance of the
transportation system; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which
the lessee can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on
depreciable capital investment. After a lessee has elected to use
either method for a transportation system, the lessee may not later
elect to change to the other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the
[[Page 56030]]
reserves which the transportation system services, or a unit of
production method. After an election is made, the lessee may not change
methods without MMS approval. A change in ownership of a transportation
system will not alter the depreciation schedule established by the
original transporter/lessee for purposes of the allowance calculation.
However, for transportation systems purchased by the lessee or the
lessee's affiliate that do not have a previously claimed MMS
depreciation schedule, the lessee may treat the transportation system
as a newly installed facility for depreciation purposes. With or
without a change in ownership, a transportation system must be
depreciated only once. Equipment may not be depreciated below a
reasonable salvage value.
(B) MMS will allow as a cost an amount equal to the allowable
initial capital investment in the transportation system multiplied by
the rate of return determined under paragraph (b)(2)(v) of this
section. No allowance will be provided for depreciation. This
alternative may apply only to transportation facilities first placed in
service after March 1, 1988.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(vi) The deduction for transportation costs must be determined on
the basis of the lessee's cost of transporting each product through
each individual transportation system. Where more than one product in a
gaseous phase is transported, the allocation of costs to each of the
products transported must be made in a consistent and equitable manner
in the same proportion as the ratio of the volume of each product to
the volume of all products in the gaseous phase. The lessee may not
take an allowance for transporting a product which is not royalty
bearing without MMS approval.
(vii) Notwithstanding the requirements of paragraph (c)(2)(vi) of
this section, the lessee may propose to MMS a cost allocation method on
the basis of the values of the products transported. MMS will approve
the method unless it determines that it is not consistent with the
purposes of the regulations in this part.
(viii) Where both gaseous and liquid products are transported
through the same transportation system, the lessee must propose a cost
allocation procedure to MMS. The lessee may use the transportation
allowance determined in accordance with its proposed allocation
procedure until MMS issues its determination on the acceptability of
the cost allocation. The lessee must submit all relevant data to
support its proposal. MMS will then determine the transportation
allowance based upon the lessee's proposal and any additional
information MMS deems necessary.
(ix) Upon request by MMS, the lessee must submit all data used to
determine its transportation allowance. The data must be provided
within a reasonable period of time, as determined by MMS.
(d) All pipelines--index-based valuation methods. (1) This
paragraph applies to determine transportation allowances each month for
gas valued under the index-based valuation methods in Sec. 206.454(b)
of this subpart.
(2) Where the lessee's gas production from a well with a single
connect is valued using an index-based method under Sec. 206.454(b)(1),
and a portion of the lessee's gas actually flows to the IPP used for
value, the applicable transportation allowance must be determined under
either paragraphs (b) or (c) of this section, as applicable. If the
lessee's gas does not actually flow to the IPP, the transportation
allowance for that pipeline must be determined under paragraph (d)(5)
of this section.
(3) Where the lessee's gas production from a well with a split
connect or multiple connection is valued using a weighted-average index
value under Sec. 206.454(b)(2)(i) of this subpart, the lessee first
must determine the applicable transportation allowance under either
paragraphs (b) or (c) of this section, as applicable, for gas volumes
actually transported to each IPP used in the calculation to value the
lessee's gas from the well. The volume weighted-average transportation
allowance per MMBtu for all of the lessee's gas transported to each IPP
used for valuation is the applicable transportation allowance for all
of the lessee's gas from the well.
(4) Where the lessee's gas production from a well with a split
connect or multiple connection is valued using the fixed-index value
method under Sec. 206.454(b)(2)(ii) of this subpart, and if some of the
lessee's gas actually flows to the IPP selected for value, then the
transportation allowance for all the lessee's gas from the well is
determined based upon the lessee's transportation allowances per MMBtu,
determined under paragraphs (b) or (c) of this section, as applicable,
to transport gas to that IPP. If none of the lessee's gas actually
flows to the IPP selected for value, the transportation allowance must
be determined under paragraph (d)(5) of this section.
(5) A transportation allowance for a pipeline, or pipeline segment,
through which a lessee's gas does not actually flow must be determined
as follows:
(i) If it is a jurisdictional pipeline, the applicable
transportation allowance rate is the maximum interruptible
transportation (IT) rate for the pipeline for the month.
(ii) If it is a non-jurisdictional pipeline and the lessee is not
affiliated with the owners of the pipeline, the applicable
transportation allowance is determined based on either:
(A) A rate calculated by MMS at the lessee's request for a fee paid
to MMS based on MMS' administrative costs of calculating that rate; or
(B) A rate determined by the lessee based on documentation
supporting the non-jurisdictional pipeline's rate, including but not
limited to any one of the following:
(1) an arm's-length contract;
(2) the pipeline's published rate; or
(3) the rate applicable to the lessee's actual transportation
through the pipeline for any 30 days (not necessarily consecutive) in
the previous 12 months.
(iii) If it is a non-jurisdictional pipeline and the lessee is
affiliated with the owners of the pipeline, the applicable
transportation allowance is determined under Sec. 206.457(c).
(e) Reporting. Transportation allowances must be reported as a
separate line item on Form MMS-2014, unless MMS approves a different
reporting procedure.
(f) Interest assessments. (1) If a lessee erroneously reports a
transportation allowance which results in an underpayment of royalties,
interest must be paid on the amount of that underpayment.
(2) Interest required to be paid by this section must be determined
in accordance with 30 CFR 218.54.
(g) Adjustments. (1) If the actual transportation allowance is less
than the amount the lessee has taken on Form MMS-2014, the lessee will
be required to pay additional royalties due plus interest computed
under 30 CFR 218.54, retroactive to the first day of the first month
the lessee is authorized to deduct a transportation allowance. If the
actual transportation allowance is greater than the amount the lessee
has taken on Form MMS-2014, the lessee will be entitled to a credit
without interest.
(2) For lessees transporting production from onshore Federal
leases, the lessee must submit a corrected Form MMS-2014 to reflect
actual costs, together with any payment, in
[[Page 56031]]
accordance with instructions provided by MMS.
(3) For lessees transporting gas production from leases on the OCS,
if the lessee's estimated transportation allowance exceeds the
allowance based on actual costs, the lessee must submit a corrected
Form MMS-2014 to reflect actual costs, together with its payment, in
accordance with instructions provided by MMS. If the lessee's estimated
transportation allowance is less than the allowance based on actual
costs, the refund procedure will be specified by MMS.
(h) Actual or theoretical losses. Notwithstanding any other
provisions of this subpart, for other than arm's-length contracts, no
cost will be allowed for transportation which results from payments
(either volumetric or for value) for actual or theoretical losses. This
section does not apply when the transportation allowance is based upon
a FERC or state regulatory agency-approved tariff.
(i) Other transportation cost determinations. The provisions of
this section will apply to determine transportation costs when
establishing value using a net-back valuation procedure or any other
procedure that requires deduction of transportation costs.
Sec. 206.458 Processing allowances--general.
(a) Where the value of any gas plant product is determined under
Sec. 206.453 of this subpart, a deduction will be allowed for the
reasonable actual costs of processing. No processing allowance is
applicable to any gas plant product valued under Sec. 206.454.
(b) Processing costs must be allocated among the gas plant
products. A separate processing allowance must be determined for each
gas plant product and processing plant relationship. Natural gas
liquids (NGL's) must be considered as one product.
(c)(1) Except as provided in paragraph (d)(2) of this section, the
processing allowance may not be applied against the value of the
residue gas. Where there is no residue gas MMS may designate an
appropriate gas plant product against which no allowance may be
applied.
(2) Except as provided in paragraph (c)(3) of this section, the
processing allowance deduction on the basis of an individual product
must not exceed 66\2/3\ percent of the value of each gas plant product
determined in accordance with Sec. 206.453 of this subpart (such value
to be reduced first for any transportation allowances related to
postprocessing transportation authorized by Sec. 206.456 of this
subpart).
(3) Upon request of a lessee, MMS may approve a processing
allowance in excess of the limitation prescribed by paragraph (c)(2) of
this section. The lessee must demonstrate that the processing costs
incurred in excess of the limitation prescribed in paragraph (c)(2) of
this section were reasonable, actual, and necessary. An application for
exception must contain all relevant and supporting documentation for
MMS to make a determination. Under no circumstances may the value for
royalty purposes of any gas plant product be reduced to zero.
(d)(1) Except as provided in paragraph (d)(2) of this section, no
processing cost deduction will be allowed for the costs of placing
lease products in marketable condition, including dehydration,
separation, compression upstream of the facility measurement point, or
storage, even if those functions are performed off the lease or at a
processing plant. Where gas is processed for the removal of acid gases,
commonly referred to as `sweetening,' no processing cost deduction will
be allowed for such costs unless the acid gases removed are further
processed into a gas plant product. In such event, the lessee will be
eligible for a processing allowance as determined in accordance with
this subpart. However, MMS will not grant any processing allowance for
processing lease production which is not royalty bearing.
(2)(i) If the lessee incurs extraordinary costs for processing gas
production from a gas production operation, it may apply to MMS for an
allowance for those costs which will be in addition to any other
processing allowance to which the lessee is entitled under this
section. Such an allowance may be granted only if the lessee can
demonstrate that the costs are, by reference to standard industry
conditions and practice, extraordinary, unusual, or unconventional.
(ii) Prior MMS approval to continue an extraordinary processing
cost allowance is not required. However, to retain the authority to
deduct the allowance the lessee must report the deduction to MMS in a
form and manner prescribed by MMS.
(e) If MMS determines that a lessee has improperly determined a
processing allowance authorized by this subpart, then the lessee must
pay additional royalties, plus interest determined in accordance with
30 CFR 218.54, or will be entitled to a credit, without interest.
Sec. 206.459 Determination of processing allowances.
(a) Arm's-length processing contracts. (1)(i) For processing costs
incurred by a lessee under an arm's-length contract, the processing
allowance must be the reasonable actual costs incurred by the lessee
for processing the gas under that contract, except as provided in
paragraphs (a)(1)(ii) and (a)(1)(iii) of this section, subject to
monitoring, review, audit, and adjustment. The lessee will have the
burden of demonstrating that its contract is arm's-length.
(ii) In conducting reviews and audits, MMS will examine whether the
contract reflects more than the consideration actually transferred
either directly or indirectly from the lessee to the processor for the
processing. If the contract reflects more than the total consideration,
then MMS may require that the processing allowance be determined in
accordance with paragraph (b) of this section.
(iii) If MMS determines that the consideration paid under an arm's-
length processing contract does not reflect the reasonable value of the
processing because of misconduct by or between the contracting parties,
or because the lessee otherwise has breached its duty to the lessor to
market the production for the mutual benefit of the lessee and lessor,
then MMS will require that the processing allowance be determined in
accordance with paragraph (b) of this section. When MMS determines that
the value of the processing may be unreasonable, MMS will notify the
lessee and give the lessee an opportunity to provide written
information justifying the lessee's processing costs.
(2) If an arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
can be determined from the contract, then the processing costs for each
gas plant product must be determined in accordance with the contract.
No allowance may be taken for the costs of processing lease production
which is not royalty-bearing.
(3) If an arm's-length processing contract includes more than one
gas plant product and the processing costs attributable to each product
cannot be determined from the contract, the lessee must propose an
allocation procedure to MMS. The lessee may use its proposed allocation
procedure until MMS issues its determination. The lessee must submit
all relevant data to support its proposal. MMS will then determine the
processing allowance based upon the lessee's proposal and any
additional information MMS deems necessary. No processing allowance
will be granted for the costs of processing lease production which is
not royalty bearing.
[[Page 56032]]
(4) Where the lessee's payments for processing under an arm's-
length contract are not based on a dollar per unit basis, the lessee
must convert whatever consideration is paid to a dollar value
equivalent for the purposes of this section.
(5) MMS may require that a lessee submit arm's-length processing
agreements and related documents. Documents must be submitted within a
reasonable time, determined by MMS.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length processing contract or has no contract, including those
situations where the lessee performs processing for itself, the
processing allowance will be based upon the lessee's reasonable actual
costs as provided in this paragraph. All processing allowances deducted
under a non-arm's-length or no-contract situation are subject to
monitoring, review, audit, and adjustment. MMS will monitor the
allowance deduction to ensure that deductions are reasonable and
allowable. When necessary or appropriate, MMS may direct a lessee to
modify its estimated or actual processing allowance.
(2) The processing allowance for non-arm's-length or no-contract
situations must be based upon the lessee's actual costs for processing
during the reporting period, including operating and maintenance
expenses, overhead, and either depreciation and a return on
undepreciated capital investment in accordance with paragraph
(b)(2)(iv)(A) of this section, or a cost equal to the initial
depreciable investment in the processing plant multiplied by a rate of
return in accordance with paragraph (b)(2)(iv)(B) of this section.
Allowable capital costs are generally those costs for depreciable fixed
assets (including costs of delivery and installation of capital
equipment) which are an integral part of the processing plant.
(i) Allowable operating expenses include: Operations supervision
and engineering; operations labor; fuel; utilities; materials; ad
valorem property taxes; rent; supplies; and any other directly
allocable and attributable operating expense which the lessee can
document.
(ii) Allowable maintenance expenses include: Maintenance of the
processing plant; maintenance of equipment; maintenance labor; and
other directly allocable and attributable maintenance expenses which
the lessee can document.
(iii) Overhead directly attributable and allocable to the operation
and maintenance of the processing plant is an allowable expense. State
and Federal income taxes and severance taxes, including royalties, are
not allowable expenses.
(iv) A lessee may use either depreciation or a return on
depreciable capital investment. When a lessee has elected to use either
method for a processing plant, the lessee may not later elect to change
to the other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the processing plant services, or a
unit-of-production method. After an election is made, the lessee may
not change methods without MMS approval. A change in ownership of a
processing plant will not alter the depreciation schedule established
by the original processor/lessee for purposes of the allowance
calculation. However, for processing plants purchased by the lessee or
the lessee's affiliate that do not have a previously claimed MMS
depreciation schedule, the lessee may treat the processing plant as a
newly installed facility for depreciation purposes. With or without a
change in ownership, a processing plant may be depreciated only once.
Equipment may not be depreciated below a reasonable salvage value.
(B) MMS will allow as a cost an amount equal to the allowable
initial capital investment in the processing plant multiplied by the
rate of return determined under paragraph (b)(2)(v) of this section. No
allowance will be provided for depreciation. This alternative will
apply only to plants first placed in service after March 1, 1988.
(v) The rate of return must be the industrial rate associated with
Standard and Poor's BBB rating. The rate of return must be the monthly
average rate as published in Standard and Poor's Bond Guide for the
first month for which the allowance is applicable. The rate must be
redetermined at the beginning of each subsequent calendar year.
(3) The processing allowance for each gas plant product must be
determined based on the lessee's reasonable and actual cost of
processing the gas. Allocation of costs to each gas plant product must
be based upon generally accepted accounting principles. The lessee may
not take an allowance for the costs of processing lease production
which is not royalty bearing.
(4) A lessee may apply to MMS for an exception from the requirement
that it compute actual costs in accordance with paragraphs (b)(1)
through (b)(3) of this section. MMS may grant the exception only if:
(i) The lessee has arm's-length contracts for processing other gas
production at the same processing plant; and (ii) at least 50 percent
of the gas processed annually at the plant is processed under arm's-
length processing contracts; if MMS grants the exception, the lessee
must use as its processing allowance the volume weighted average prices
charged other persons under arm's-length contracts for processing at
the same plant.
(5) Upon request by MMS, the lessee must submit all data used by
the lessee to determine its processing allowance. The data must be
provided within a reasonable period of time, as determined by MMS.
(c) Reporting. Processing allowances must be reported as a separate
line on the Form MMS-2014, unless MMS approves a different reporting
procedure.
(d) Interest assessments. (1) If a lessee erroneously reports a
processing allowance which results in an underpayment of royalties,
interest must be paid on the amount of that underpayment.
(2) Interest required to be paid by this section must be determined
in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual gas processing allowance is less
than the amount the lessee has taken on Form MMS-2014 for each month
during the allowance form reporting period, the lessee will be required
to pay additional royalties due plus interest computed under 30 CFR
218.54, retroactive to the first day of the first month the lessee is
authorized to deduct a processing allowance. If the actual processing
allowance is greater than the amount the lessee has taken on Form MMS-
2014 for each month during the allowance period, the lessee will be
entitled to a credit without interest.
(2) For lessees processing production from onshore Federal leases,
the lessee must submit a corrected Form MMS-2014 to reflect actual
costs, together with any payment, in accordance with instructions
provided by MMS.
(3) For lessees processing gas production from leases on the OCS,
if the lessee's estimated processing allowance exceeds the allowance
based on actual costs, the lessee must submit a corrected Form MMS-2014
to reflect actual costs, together with its payment, in accordance with
instructions provided by MMS. If the lessee's estimated costs were less
than the actual costs, the refund procedure will be specified by MMS.
(f) Other processing cost determinations. The provisions of this
section will apply to determine processing costs when establishing
value using a net back valuation
[[Page 56033]]
procedure or any other procedure that requires deduction of processing
costs.
PART 211--LIABILITY FOR ROYALTY DUE ON FEDERAL AND INDIAN LEASES
AND RESPONSIBILITY TO REPORT ROYALTY AND OTHER PAYMENTS
18. The authority citation for part 211 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.; 43 U.S.C. 1301 et seq., 1331 et seq., 1801 et
seq.
Subpart C--Reporting and Paying Royalties
19. In section 211.18 as proposed to be added at 60 FR 30500 (June
19, 1995) a new paragraph (c) is added to read as follows:
Sec. 211.18 Who is required to report and pay royalties?
* * * * *
(c) Persons who take production allocable to Federal or Indian
leases in all other approved Federal or Indian agreements. This
paragraph provides requirements and instructions for reporting and
paying royalties and other payments for Federal leases in approved
Federal agreements comprised of leases with differing lessors, royalty
rates, or fund distributions.
(1) Except as provided in paragraphs (c) (2) and (3) and (d) of
this section, if you are an operating rights owner in a Federal lease
in an agreement under this paragraph, you must report and pay royalties
on your entitled share of production under the terms of the agreement.
You must:
(i) File a PIF with MMS as specified in Part 210 of this title and
the MMS Payor Handbooks;
(ii) Report the royalties owed for that production on a Form MMS-
2014 and follow the instructions provided in Part 210 of this title and
the MMS Payor Handbooks; and
(iii) Pay royalties on that production as specified in Part 218 of
this title and the MMS Payor Handbooks.
(2) If you are an operating rights owner who meets the definition
of a small operating rights owner in Sec. 206.451 of this title, you
may report and pay royalties each month on the volume of production you
actually take subject to the following criteria:
(i) You must report your takes on Form MMS-2014 using a special
code.
(ii) Within 6 months after the end of each calendar year in which
you report based on takes, you must pay any additional royalties that
may be due on the difference between your entitled share and the volume
of production on which you reported and paid royalties in accordance
with 30 CFR Sec. 202.450(d)(1)(iv)(D).
(iii) If the volume of the production on which you reported and
paid royalties for the calendar year is equal to or greater than the
volume of your entitled share of production for that calendar year, you
will not be assessed late payment interest for any sales month during
the calendar year in which you underreported volume. However, MMS will
assess interest for any reported volumes based on takes if the royalty
value for those volumes was not properly reported and paid. MMS will
allow a credit for any overtaken volumes in accordance with applicable
procedures.
(iv) If the volume of the production on which you report and paid
royalties for the calendar year is less than the volume of your
entitled share of production for the calendar year, you must:
(A) Report and pay royalties on the difference between the volume
of your entitled share of the production for the calendar year and the
volume of the production on which you reported and paid under the takes
basis; and
(B) Pay interest in accordance with MMS regulations and procedures
on any underpaid royalties.
(3) You are not required to report and pay royalties on your
entitled share of production under paragraph (c)(1) of this section if
all operating rights owners in the agreement agree to assign reporting
and payment responsibilities among themselves in an alternative manner
that ensures that royalties are reported and paid properly each month
on the full volume of production from or attributable to each Federal
lease in the agreement.
[FR Doc. 95-27079 Filed 11-3-95; 8:45 am]
BILLING CODE 4310-MR-P
