[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]



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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.

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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