Amendments to Gas Valuation Regulations for Federal Leases

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)(

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